A Model to Estimate CO2 Leakage and Identify CO2 Hydrate Stable Conditions for Offshore CCS

Abstract

Offshore CCS (Carbon Capture and Storage) is an attractive option to clamp down on carbon emissions. Two major advantages are 1) existing infrastructure for injection and 2) well characterized reservoirs due to previous oil and gas operations. One of the biggest concerns is the possibility of leakage. Leakage is likely when CO2 plume encounters improperly abandoned wellbores, pre-existing conductive faults, or reactivated faults amongst others. The hazard of leakage strongly depends on the leakage fluxes and rates. Hydrates may form and throttle leakage if the pressuretemperature conditions within the pathway reach hydrate stable conditions. Thus, a useful component of risk assessment is to model CO2 leakage and assess potential for hydrate formation conditions. In this short paper, we describe a model for flow of CO2 along a leakage pathway. We assume single phase flow of CO2 with variable fluid properties and a continuous leakage pathway with constant thickness. These assumptions help obtain worst-case estimates of leakage fluxes and rates. Expected leakage fluxes and rates are estimated along with the effect of pathway permeability and reservoir overpressure on it. Pressure-temperature conditions are checked if they fall within the CO2 hydrate stable conditions for typical Norwegian Continental Shelf (NCS) Storage projects (Sleipner, Snøhvit and Aurora projects). Formed hydrates reduce the permeability of the pathway and has the potential to temporarily block leakage or redirect leakage in different directions. The aim of this study is to understand the relationship between pathway properties, regional conditions, leakage pressure profile and hydrate formation on leakage fluxes and rates.