## 3 Model Development
### Process Flow Diagram  
The process flowsheet of capturing CO2 can be divided into 4 different sections as shown in Figure 2 namely:  
1. Desulfurization unit
2. Flue gas cooling unit (DCC)
3. Absorption of carbon dioxide and regeneration of the solvent
4. CO2 compression train  
Flue gas leaves the case study power plant at an average temperature of 169 \({}^{\circ}\)C and a flow rate of 325 t/h. The CO2 content in the flue gas was assumed to be 15.4 mass %, which agrees with [PERSON] et al. [35]. Details of the flue gas- and utility properties as well as the final product specifications are given in Table 1. The flue gas initially enters through the Wet Flue Gas Desulfurization (FGD) units to remove the SOx content. The de-sulfurized stream is then cooled in a direct contact cooler (DCC) before entering the absorber tower. The absorber in a 30 wt% MEA system operates at low temperatures of around 40 \({}^{\circ}\)C and pressure, hence the need to cool the flue gas prior to entering the absorber. The FGD unit already lowers the flue gas temperature but rises again after passing through the blower, which requires a DCC unit to ensure that the entering stream is within the recommended range.  
After the absorption stage, the rich amine leaving the bottom of the absorber exchanges heat with the returning lean amine from the stripper. The lean amine stream with the higher temperature heats the rich amine to a temperature of 113 \({}^{\circ}\)C through a cross heat exchanger. In the desorber stage, the reverse of absorption occurs at higher temperatures where the rich amine comes in contact with the rising vapors from the reboiler. The top stream exiting the stripper is condensed and flashed to obtain a near pure CO\({}_{2}\) stream. The gas stream is finally compressed in a multi-stage compression train up to a pressure  
\begin{table}
\begin{tabular}{c c c c} \hline \hline
**Fine Gas** & & 169 & \({}^{\circ}\)C \\ \hline \hline \multicolumn{1}{c}{Temperature} & & 1.013 & bar \\ \hline \multicolumn{1}{c}{Pressure} & & 1.013 & bar \\ \hline \multicolumn{1}{c}{Flow rate} & & 325,130 & kg/h \\ \hline \multirow{4}{*}{Composition} & CO\({}_{2}\) & 15.4 & mass-\% \\  & H\({}_{2}\)O & 8.33 & mass-\% \\  & O\({}_{2}\) & 3.35 & mass-\% \\  & SO\({}_{2}\) & 0.07 & mass-\% \\  & N\({}_{2}\) & 72.89 & mass-\% \\ \hline \multicolumn{1}{c}{**Utilities**} & & \\ \hline \multicolumn{1}{c}{Cooling water} & & 15 & \({}^{\circ}\)C (Max temp. increase 10 K) \\ \hline \multirow{3}{*}{Steam} & LP & 4 bar & 150 \({}^{\circ}\)C \\ \cline{2-4}  & IP & 20 bar & 220 \({}^{\circ}\)C \\  & HP & 70 bar & 290 \({}^{\circ}\)C \\ \hline \multicolumn{1}{c}{MEA} & & 1400 & \(\epsilon\)/t \\ \hline \multicolumn{1}{c}{Air Temp.} & & 10 & \({}^{\circ}\)C \\ \hline \multicolumn{1}{c}{**CO\({}_{2}\) specifications**} & & \\ \hline \multicolumn{1}{c}{Pressure} & & 130 & bar \\ \hline \multicolumn{1}{c}{Temperature} & & 30 & \({}^{\circ}\)C \\ \hline \multicolumn{1}{c}{Mass fraction} & & 0.99 & - \\ \hline \multicolumn{1}{c}{Flow rate} & & 45,289 & kg/h \\ \hline \hline \end{tabular}
\end{table}
Table 1: Flue gas and utility parameters.  
Figure 2: Process schematic of CO\({}_{2}\) capture using MEA solvent (left to right: desulfurization, flue gas cooling, absorption/desorption, CO\({}_{2}\) compression train).  
of 70 bar. Next, the supercritical liquid is pumped up to a final discharge pressure of 130 bar for transportation. Each utilization process requires a specific pressure, whether it is underground storage, injection into a pipeline grid, or directly sent to a reactor for further upgrading. In this study, the carbon dioxide gas is assumed to be sent for transportation via a pipeline. The pipelines are capable of handling a dense phase of CO2 beyond the critical pressure (\(P_{c}=73.8\) bar). Although vapor phase transportation is also possible, the former has the advantage of smaller pipe diameters and lower pressure drops [9].