# Feasibility Assessment of Acid Gas Injection in an Iranian Offshore Aquifer
## 6 Ideal Reservoir  
In 2003, Gas Liquids Engineering (GLE) conducted a conceptual design study to explore the possibility of acid gas injection at Kharg Island. Recently, in the current year, GLE has initiated a Front-End Engineering Design (FEED) study for an acid gas injection  
Figure 14: Trend of the well bottom-hole pressure according to a gas injection rate of 200,000 Sm\({}^{3}\)/d. facility to replace the existing sulfur plant [31]. These studies are crucial for evaluating the feasibility and potential of implementing acid gas injection in the reservoirs at Kharg Island and further assessing the suitability of the reservoirs for this process. Based on the available data from the formation core and logs [31], the primary reservoir properties in the Dhruma Zone are as follows:  
* Depth range: 4016-4150 m;
* Net Pay: Approximately 125 m;
* Typical porosity of the injection zone: 15-23%;
* Typical permeability of the injection zone: 10-600 mD;
* Proposed injection rate: 80 MMSCFD. As can be seen, the permeability of the reservoir is relatively high, and the formation is highly porous (15% porosity). By considering a permeability of 100 mD and a porosity of 6%, the results are shown in Figure 15. It should be emphasized that a porosity of 6% in rocks generally results in a permeability of less than 100 mD: this value is only considered for the conceptual feasibility of acid gas injection. Under such conditions, the bottom-hole pressure increases over time. After 25 years it reaches 400 bars, which coincides with the fracture pressure. Throughout this period, the injection rate remains constant at 2,000,000 Sm\({}^{3}\)/d (70 MMSCFD). In addition to black oil simulation, a compositional model was used to validate the results. This involved considering two components, CO\({}_{2}\) and H\({}_{2}\)O. By comparing the results obtained from the compositional model with those from the black oil simulation, the accuracy and reliability of the findings were assessed. This approach allows a more comprehensive understanding of the behavior and performance of the reservoir during acid gas injection. Figure 15 shows two black oil cases and one compositional case: it is evident that the injection rate involves a high risk of fracturing and, over a period of 30 years of injection, there is a possibility of formation breakdown. In the black oil cases, two scenarios were examined, and the descriptions of both of them are shown in Table 4. \begin{table}
\begin{tabular}{c c c} \hline
**Simulator** & **Differences** & **Time of BHP Limit (400 Bars)** \\ \hline Black Oil & CO\({}_{2}\) solubility was considered & 24 years \\ Black Oil & CO\({}_{2}\) solubility was ignored & 23 years \\ Compositional & interaction between various & 17 years \\ \end{tabular}
\end{table} 
Table 4: Characteristics of the 3 cases examined (Porosity: 6%, Permeability = 100 mD). Figure 15: BHP for 3 cases (Red: Compositional; Green: Black oil without CO\({}_{2}\) solubility; Brown: Black oil with CO\({}_{2}\) solubility). Figures 16 and 17 display the gas saturation distribution within the reservoir: they show how the gas fluid rapidly moves upward, driven by the buoyancy force, and accumulates in the crest of the structure. As a result, a gas cap is formed over the water zone in the formation. The visualization of gas saturation provides insights into the spatial distribution and movement of gas within the reservoir. The formation's porosity of 6% and permeability of 100 mD restrict the injection rate, allowing a maximum injection of 70 MMSCFD. To maintain the pressure of the reservoir and reduce the pressure of the bottom-hole, three injection wells are needed. The low porosity of the reservoir significantly affects the increase in reservoir pressure and BHP. Figure 18 shows a comparison between the bottom-hole pressures obtained for two different cases, based on the porosity values of 6% and 12%. The Arab formation (Surmeh), depicted in Figure 5, exhibits a porosity range of 10-15% and a permeability range of 1-100 mD, highlighting its high heterogeneity.