Exploring CO₂-H₂S Storage in Deep Saline Aquifers: A Case Study from an Offshore Gas Field in Malaysia. From Lab to Numerical Simulation

Most carbon dioxide (CO₂) storage schemes rely on storing CO₂ in its supercritical state, free from impurities (SNC-Lavalin Inc., 2004). The X field reservoir model, like many other existing reservoir models, assumes pure CO₂ injection for its numerical simulation of CO₂ storage. However, one of the gas sample analyses from the X field revealed the presence of trace amounts of hydrogen sulfide (H₂S,) ranging from 500 to 1000 ppm. Given the limitations of the separation technology, there is a potential scenario where CO₂ might be co-injected with H₂S for storage. Understanding the impact of this H₂S within the injected CO₂ stream is crucial for ensuring the success of Carbon Capture and Storage (CCS) operations (Basava-Reddi et al., 2014; Wang et al., 2011). There is a possibility of CO₂ being co-injected with this H₂S for storage. The effect of the contaminant in the injected CO₂ stream needs to be accessed to ensure the success of the CCS operation. The alterations in the base CO₂ solubility can ultimately influence storage integrity and capacity (Ahmad et al., 2023). While abundant solubility data for CO₂ in water or brine exist in the literature (A Chapoy et al., 2004; Valtz et al., 2004; Ahmadi & Chapoy, 2018), limited data are available for this ternary CO₂- H₂S-Brine system. Therefore, the need to quantify the impact of H₂S impurities on CO₂ solubility is evident. In this context, extensive laboratory experiments were undertaken to address these uncertainties and further refine the X field dynamic model for enhanced accuracy.