## 2 Methodology
\begin{table}
\begin{tabular}{c c} \hline \hline
**Geological Parameter** & **Value** \\ \hline Initial reservoir temperature (\({}^{\circ}\)C) & 12 \\ Initial reservoir pressure at 240 mTVD (kPa) & 1600 \\ Horizontal absolute permeability (Darcy) & 2.5 \\ Vertical absolute permeability (Darcy) & 1.25 \\ Porosity (-) & 0.3 \\ Initial oil saturation of the payzone (-) & 0.8 \\ Irreducible water saturation (-) & 0.2 \\ Rock volumetric heat capacity (kJ/m\({}^{3}\).\({}^{\circ}\)C) & 2600 \\ Rock thermal conductivity (kJ/m\(\cdot\)day.\({}^{\circ}\)C) & 660 \\ Gas thermal conductivity (kJ/m\(\cdot\)day.\({}^{\circ}\)C) & 5 \\ Oil thermal conductivity (kJ/m\(\cdot\)day.\({}^{\circ}\)C) & 11.5 \\ Water thermal conductivity (kJ/m\(\cdot\)day.\({}^{\circ}\)C) & 53.5 \\ \hline \hline \end{tabular}
\end{table} 
Table 1: Input properties used in the synthetic reservoir model. TVD: true vertical depth. \begin{table}
\begin{tabular}{c c} \hline \hline
**Property** & **Value** \\ \hline Oil molecular weight (kg/kg-mol) & 570 \\ Oil viscosity at 10 \({}^{\circ}\)C (cp) & 2,864,376 \\ Oil viscosity at 90 \({}^{\circ}\)C (cp) & 655 \\ Oil viscosity at 250 \({}^{\circ}\)C (cp) & 6 \\ \hline \hline \end{tabular}
\end{table} 
Table 2: Properties of the oleic component. In Equations (2) and (3), \(V\) is the volume, and the subscripts \(s\) and \(o\) represent the injected steam and the produced oil, respectively, i.e., \(V_{o,t}\) is the oil production rate at time \(t\). In this study, the daily rates at the injector and the producer are used. \(n\) indicates the end of the SAGP process. \(STEP\) has  
Figure 1: Schematic diagram of the synthetic models including: (**a**) the finite aquifer; and (**b**) the infinite aquifer. \begin{table}
\begin{tabular}{c c c c} \hline \hline
**Well Type** & **Constraints** & **Condition** & **Value** \\ \hline Injector & Surface total phase rate (m\({}^{3}\)/day CWE) 1  & Maximum & 6.0 \\ Producer & Bottom hole pressure (kPa) & Minimum & 1300 \\  & Surface liquid rate (m\({}^{3}\)/day) & Maximum & 7.5 \\  & Steam rate (m\({}^{3}\)/day) & Maximum & 0.2 \\ \hline \hline \end{tabular}
\end{table} 
Table 3: Well constraints for the steam and gas push (SAGP) modeling. been developed to examine the optimum energy-efficient operations that show the highest recovery, as defined in Equation (4) [23]:  
\[STEP=\frac{(RF/0.5)\times(CDOR/0.111)}{(cSOR/3)^{2.4}} \tag{4}\]  
\[CDOR=\frac{\frac{1}{n}\sum\limits_{t=0}^{n}V_{o,t}}{L_{h}} \tag{5}\]  
\[RF=\frac{\sum\limits_{t=0}^{n}V_{o,t}}{STOIIP} \tag{6}\]  
In Equations (4)-(6), \(CDOR\) stands for the \"calendar day oil rate\", which is the average oil production rate per unit of perforated length, i.e., the average value of the daily production rate divided by the total perforated length (\(L_{h}\)). This study assumes a full perforation along with horizontal wells and \(L_{h}\) is, therefore, equal to \(\Delta j\) (=20 m). \(RF\) represents the \"recovery factor\" that is calculated using \(STOIIP\) (=8821.8 m\({}^{3}\)) and the cumulative volume of the produced oil. The figures that serve as the denominators in Equation (3) are the abandonment values per each parameter that are obtained from the commercial field database of an actual oil sands development, as follows: 0.5 for \(RF\), 0.111 for \(CDOR\), and 3 for \(cSOR\). The exponent of 2.4 in Equation (3) is determined to show a linear relationship with the net present value when the steam cost is $5/barrel and the bitumen commodity price is $20/barrel [23].