# Feasibility Assessment of Acid Gas Injection in an Iranian Offshore Aquifer
## 4 Dynamic Modelling  
The plan is to transfer a sour gas that has been extracted from one field (source field) and injected into the Surmeh Formation. As mentioned above, acid gas consists mainly of H\({}_{2}\)S and CO\({}_{2}\). According to the PVT (Standard Pressure Volume Temperature) data, the H\({}_{2}\)S concentration in the source field is 39,000 ppm, while the CO\({}_{2}\) concentration is 68,000 ppm (see Table 2). Considering the extraction of all H\({}_{2}\)S, CO\({}_{2}\), and a small portion of methane during the acid gas processing, approximately 12% of the injected gas is acid gas. Based on the MDP (Master Development Plan) of the source field, the gas estimated in place is 22 TCF of sour gas. Consequently, considering a recovery factor of 75% for dry gas reservoirs, roughly 2 TCF of acid gas will be injected into the Surmeh formation. \begin{table}
\begin{tabular}{c c} \hline
**Property** & **Description** \\ \hline Reservoir Formation & Surmeh Formation (corresponds to Arab Formation) \\ Porosity (\%) & Range: 2.5–6 \\ Permeability (mD) & Range: 0.1–100 \\ Formation Water & Fully saturated with brine (220,000 ppm salinity) \\ Formation Temperature (\({}^{\circ}\)C) & 80 \\ Pore Pressure (psi) & 3800 \\ Fracture Pressure (psi) & 6100 \\ \hline \end{tabular}
\end{table} 
Table 1: Static properties of the Surmeh formation in the upper and lower parts. Figure 8: Thickness map of the Hith formation (Surmeh Cap rock). Ref. [22] expresses the capillary pressure \(P_{c}\) as a function of saturation (S) using the following equation [1]:  
\[P_{c}=P_{e}\bigg{(}\frac{S_{w}-S_{wi}}{1-S_{wi}}\bigg{)}^{-\frac{1}{\lambda}} \tag{1}\]  
where \(S_{W}\) is water saturation, \(S_{wi}\) is Irreducible Water Saturation, \(P_{e}\) is the minimum pressure required for the gas to enter the pores of the rock, and \(\lambda\) is a fit parameter known as the pore size distribution index [23]. For this formation, \(\lambda\) was 0.55. The relative permeability curves employed in this study were based on the relationships of [24], specifically using the Equations (2)-(4) proposed by [25]:  
\[K_{rw}=\left(S_{w}^{*}\right)^{N_{w}} \tag{2}\]  
\[S_{w}^{*}=\frac{S_{w}-S_{wi}}{1-S_{wi}} \tag{3}\]  
\[K_{rg}=K_{rg}(S_{wi})\bigg{(}1-S_{w}^{*}\bigg{)}^{2}\bigg{(}1-\left(S_{w}^{*} \right)^{N_{gas}}\bigg{)} \tag{4}\]  
The variables \(N_{w}\) and \(N_{gas}\), (range from 1 to 6) are used as fitting parameters, known as the Corey exponents for water and gas, respectively [26]. The following values are used, \(N_{w}\) = 5 and \(N_{gas}\) = 4 (typical value used in modeling in the Persian Gulf). Table 3 shows a summary of the saturation function data. Figures 9 and 10 show the relative permeability and capillary pressure curves, respectively. In the context of gas injection scenarios for storage purposes, a comprehensive understanding of the four identified trapping mechanisms is crucial; these are: structural, capillary, solubility, and mineralization trapping. These mechanisms are responsible for the prolonged storage of injected gas within geological formations. The relative contribution of each trapping mechanism during the storage period may vary. In the short term, capillary trapping serves as the primary mechanism for gas retention in porous media. This phenomenon can be attributed to the hysteresis of relative permeability and capillary pressure. Capillary trapping plays a pivotal role in the initial stages of CO\({}_{2}\) storage, effectively containing a significant portion of the gas plume within the formation. Furthermore, capillary pinning is expected to occur because of contrasting constitutive relations among different rock types, such as variations in capillary pressure (P\({}_{c}\)), relative permeability (K\({}_{r}\)), and irreducible water saturation (S\({}_{wi}\)), which are commonly observed in natural rock