Evaluating the financial implications of injectivity risk in compartmentalized reservoirs for CCS

Injectivity is a major driver of risk in CCS projects. Risk mitigation efforts are focused on leakage and well remediation, while operational issues from past CCS projects have shown injectivity is frequently caused by the mischaracterization of compartmentalized reservoirs Sub-seismic faults, misinterpreted facies changes and a host of other factors can induce unexpected compartmentalization. The financial penalty due to the disruption of CCS operations is a large, depending on the agreement between the site operator and capture source. This paper explores the effect of compartment size and boundary condition on injectivity, and the subsequent financial implications. Risk profiles of injectivity are generated through reservoir simulations in CMG-GEM, constrained by preliminary statistics from a CCS prospect on the Gulf Coast. A financial tool is built to understand the impact on project value when an injectivity issue occurs and an offset well needs to be drilled. CO₂ offtake price and insurance mechanisms are considered in the tool. We observe that even in relatively closed boundary conditions, pressure can dissipate in the reservoir to allow injection over the project life. The economic feasibility of a CCS project that does face an injectivity issue depends on the year of the injection issue, with projects able to overcome financial liability and mitigation costs if an injection issue occurs in the latter half of the project life. To date, there is no CCS literature on financial risk specifically regarding injectivity. Making CCS projects bankable requires robust assurance, and thus understanding injectivity risk, project contingency, and the feasibility of mitigation options can help to expand CCS deployment.