A Simulation Study on Evaluating the Influence of Impurities on Hydrogen Production in Geological Carbon Dioxide Storage

In this study, we examined the effect of CO2 injection into deep saline aquifers, considering impurities present in blue hydrogen production. A fluid model was designed for reservoir conditions with impurity concentrations of 3.5 and 20%. The results showed that methane caused density decreases of 95.16 and 76.16% at 3.5 and 20%, respectively, whereas H2S caused decreases of 99.56 and 98.77%, respectively. Viscosity decreased from 0.045 to 0.037 cp with increasing methane content up to 20%; however, H2S did not affect the viscosity. Notably, CO2 with H2S impacted these properties less than methane. Our simulation model was based on the Gorae-V properties and simulated injections for 10 years, followed by 100 years of monitoring. Compared with the pure CO2 injection, methane reached its maximum pressure after eight years and eleven months at 3.5% and eight years at 20%, whereas H2S reached maximum pressure after nine years and two months and nine years and six months, respectively. These timings affected the amount of CO2 injected. With methane as an impurity, injection efficiency decreased up to 73.16%, whereas with H2S, it decreased up to 81.99% with increasing impurity concentration. The efficiency of CO2 storage in the dissolution and residual traps was analyzed to examine the impact of impurities. The residual trap efficiency consistently decreased with methane but increased with H2S. At 20% concentration, the methane trap exhibited higher efficiency at the end of injection; however, H2S had a higher efficiency at the monitoring endpoint. In carbon capture and storage projects, methane impurities require removal, whereas H2S may not necessitate desulfurization due to its minimal impact on CO2 storage efficiency. Thus, the application of carbon capture and storage (CCS) to CO2 emissions containing H2S as an impurity may enable economically viable operations by reducing additional costs.