In the context of climate change, one way to reduce atmospheric emissions of carbon dioxide is Carbon Capture and Storage (CCS) in both depleted hydrocarbon reservoirs and saline aquifers. The injectivity index is one of the most important parameters to monitor and forecast carbon storage; it determines how rapidly CO2 can be injected, which then determines the rate of storage.
This paper verifies the feasibility of a methodology to monitor the well injectivity of a CO2 injector well during its lifetime. In the oil industry, this is based on the acquisition of downhole pressure and temperature during a well test that is interpreted using Pressure Transient Analysis (PTA). Here we investigate if the same techniques could be applied to CO2 injection, considering the complex interaction between CO2, rock, and reservoir fluids.
The study was performed running a simplified full-scale reservoir compositional model, representative of a depleted gas reservoir of an Eni CCS project. The so generated bottomhole flowing pressures, were analyzed using PTA to estimate the mechanical skin factor, accounting for the reduction in permeability near the wellbore, which potentially limits the amount of CO2 that can be injected.
The work confirmed that the monitoring of the bottom-hole pressure through permanent downhole gauges or even with temporary acquisition memory gauges run-in-hole with a slick-line is crucial for the monitoring in real-time of the well injectivity. Analytical PTA tools provide a sound characterization of the well status: static pressure, permeability-thickness product, permeability, and mechanical skin. Under the assumptions of this study, no significant skin component due to the interaction of the CO2-rock-reservoir fluids was detected; its presence may be apparent in more complex scenarios (i.e., considering induced salt precipitation).