# Feasibility Assessment of Acid Gas Injection in an Iranian Offshore Aquifer
## 4 Dynamic Modelling
\begin{table}
\begin{tabular}{c c c} \hline \hline \multirow{2}{*}{**Components**} & \multicolumn{2}{c}{**Reservoir Fluid Composition**} \\ \cline{2-3}  & & **(Dry Basis)** \\ \cline{2-3}  & **Mole \%** & **Mass \%** \\ \hline Nitrogen & 11.797 & 15.657 \\ CO\({}_{2}\) & 6.795 & 14.167 \\ H\({}_{2}\)S & 3.908 & 6.309 \\ Methane & 73.861 & 56.139 \\ Ethane & 2.330 & 3.319 \\ Propane & 0.526 & 1.100 \\ \hline \hline \end{tabular}
\end{table} 
Table 2: Injected Fluid composition. \begin{table}
\begin{tabular}{c c c c c c} \hline \hline \multirow{2}{*}{**Upper Surmeh**} & \multirow{2}{*}{**Porosity**} & **Irreducible Water** & **Gas** & **Minimum** & **Gas Relative** \\  & & **Saturation** & **Saturation** & **Pressure** & **Permeability** \\ \cline{2-5}  & **(\%)** & **S\({}_{wi}\) (\%)** & **S\({}_{ge}\) (\%)** & **P\({}_{e}\) (psi)** & **K\({}_{rg}\)** \\
**6** & **22** & **4** & **660** & **0.65** \\ \hline \hline \end{tabular}
\end{table} 
Table 3: Saturation function data for acid gas simulation. formations. Consequently, capillary trapping exerts a considerable influence on the spatial distribution of gas plumes within the reservoirs [27]. The capillary trapping mechanism can be clarified as follows: once the gas is injected into a saline aquifer, the significant density and viscosity disparities between the gas and water phases cause the gas plume to ascend towards the highest accessible formation top until it encounters an impermeable cap rock layer. In this phase, a drainage process takes place, during which the non-wet gaseous phase displaces the wet phase, which in this case is saline water. Upon completion of the injection, the saline water reabsorbs into the formation, displacing the gas plume in a process like imbibition. During this process, the continuous gas plume fragments, forming bubbles which subsequently become trapped within the formation [28]. To simulate the trapping mechanism from a conceptual perspective, a simple structure with dimensions of 100 \(\times\) 100 \(\times\) 10 m is used. To replicate this phenomenon in a simulation, two methods are employed: one assumes homogeneous rock properties with a single rock type, employing single relative permeability and capillary pressure curves without incorporating a hysteresis process; the other considers heterogeneous rock properties with two different rock types, defining the single relative permeability and capillary pressure curves, and hypothesizing a hysteresis process for both curves. Figure 10: Capillary pressure of water and gas. Figure 9: Relative permeability curves used for water and gas. Figures 11 and 12 show vertical cross-sections of gas saturation for the homogeneous and heterogeneous cases after the injection is stopped. Once injected, the CO\({}_{2}\) disperses both horizontally and vertically. The buoyancy force drives the upward movement of the gas plume. The relative strengths of the viscous and gravitational forces determine the shape of the plume uniformly. In a homogeneous reservoir, the gas plume rapidly rises to the top of the reservoir and then expands laterally at a slower rate. On the other hand, under heterogeneous conditions, the gas plume exhibits distinct characteristics. It becomes twice as wide as in the homogeneous case, and only a portion of the gas manages to reach the top of the reservoir. Furthermore, the distribution of gas saturation within the reservoir becomes non-uniform. These results highlight the significant influence of capillary curves and hysteresis processes associated with different rock types, which fundamentally dictate trapping mechanisms and consequently shape and govern gas plume dynamics. Extensive research has been carried out on CCS, resulting in the availability of relevant data. In this case, the acid gas composition is primarily composed of CO\({}_{2}\) rather than H\({}_{2}\)S. Therefore, only the CO\({}_{2}\) composition was considered for simulation purposes. The solubility of CO\({}_{2}\) in water was determined thanks to the experimental data from [29].