# Feasibility Assessment of Acid Gas Injection in an Iranian Offshore Aquifer
## 5 Results  
Two different cases were examined, respectively, with a permeability of 1 and 0.1 mD covering the minimum and maximum possible range expected for Surmeh formation at the forecasted burial depth in the field. In the following, the results obtained are highlighted. Permeability = 1 mD: To assess the gas injection capacity into the reservoir, a sensitivity analysis was conducted based on empirical correlations. These correlations show that for a porosity of 6%, the typical range of permeability falls between 0.1 and 1 mD (see Figure 5). By varying the permeability values within this range, the study aimed to determine the maximum gas injection volume that could be accommodated by the reservoir. When performing dynamic modeling, it is important to consider the following factors:  
* Vertical permeability: in all models, the vertical permeability (Ky) was assumed to be 0.1 times the horizontal permeability (KH). * Chemical reactions: none of the simulation cases accounted for chemical reactions between rock and fluids. It is necessary to conduct precise laboratory tests to evaluate such reactions accurately. * Wellbore diameter: in all simulation cases it was assumed equal to 19 cm, which is the default value in the software. * Simulation area: all simulations were conducted in the upper Surmeh reservoir, due to its higher porosity value, which is a crucial factor for accurate modeling. Based on the estimations made, the fracture pressure of the rock is 6100 psi, which is equivalent to 420 bars. Therefore, it is important to note that as the pressure approaches 400 bars (with a safety margin of 20 bars), the risk of rock fracturing arises. In the first model, the horizontal permeability was 1 mD, and the vertical permeability was 0.1 mD. Figure 14 shows the trend of the bottom-hole pressure with an injection rate of 200,000 Sm\({}^{3}\)/d or 7 MMSCFD. Figure 14 depicts the well's bottom-hole pressure profile for the injector in the implemented model. The pressure initially started at 270 bars and reached a maximum of 386 bars over the 100-year injection period. This rapid pressure rise is influenced by the compressibility of both fluids and rock, and it depends on the type of well and the length of completion. As more gas is injected, the bottom-hole pressure gradually increases due to the increasing gas saturation. The initial sharp spike in the pressure is caused by the low relative permeability of the gas at the beginning of the injection process [30]. The pressure changes at the well affect the pressure at the cap rock, which is crucial for maintaining the seal integrity. The slow, long-term increase in the well's bottom-hole pressure shown in Figure 14 is a result of the net accumulation of fluid within the formation. It was anticipated that injecting a flow rate of 300,000 Sm\({}^{3}\)/d could potentially cause fractures in the formation, given its low permeability. The upper limit for this permeability is determined to be 200,000 Sm\({}^{3}\)/d. As observed, the reservoir permeability is quite low to accommodate an injection rate of 180 MMSCFD. Therefore, achieving high well injectivity becomes crucial to enable the injection of such a flow rate. However, it is important to ensure that the bottom-hole pressure does not exceed 400 bars to maintain the integrity of the reservoir. According to the information provided, the initial bottom-hole pressure of 270 bars increases to 386 bars over a span of 100 years. Considering the typical Vertical Flow Performance curves, the corresponding pressure drop along the wellbore would be estimated to be between 1000-1300 psi (68-90 bars). Consequently, the resulting wellhead pressure is projected to be within the range of 352-475 bars. Permeability = 0.1 mD: Based on the simulation results for a permeability of 1 mD, it can be concluded that lower permeability tends to result in reduced injectivity. In this case, to prevent formation damage, the simulation suggests that an injection rate of 20,000 Sm\({}^{3}\)/d (0.7 MMSCF/D) can be safely maintained.