Transient CO2 leakage and injection in wellbore-reservoir systems for geologic carbon sequestration


  • This article is a US Government work and is in the public domain in the USA


At its most basic level, the injection of CO2 into deep reservoirs for geologic carbon sequestration (GCS) involves a system comprising the wellbore and the target reservoir, the wellbore being the only conduit available to emplace the CO2. Wellbores in general have also been identified as the most likely conduit for CO2 and brine leakage from GCS sites, especially those in sedimentary basins with historical hydrocarbon production. We have developed a coupled wellbore and reservoir model for simulating the dynamics of CO2 injection and leakage through wellbores, and we have applied the model to situations relevant to geologic CO2 storage involving upward flow (e.g. leakage) and downward flow (injection). The new simulator integrates a wellbore-reservoir system by assigning the wellbore and reservoir to two different sub-domains in which flow is controlled by appropriate laws of physics. In the reservoir, we model flow using a standard multiphase Darcy flow approach. In the wellbores, we use the drift-flux model and related conservation equations for describing transient two-phase non-isothermal wellbore flow of CO2-water mixtures. Applications to leakage test problems reveal transient flows that develop into quasi-steady states within a day if the reservoir can maintain constant conditions at the wellbore. Otherwise, the leakage dynamics could be much more complicated than the simple quasi-steady-state flow, especially when one of the phases flowing in from the reservoir is near its residual saturation. A test problem of injection into a depleted (low-pressure) gas reservoir shows transient behavior out to several hundred days with sub-critical conditions in the well disappearing after 240 days. © 2011 Society of Chemical Industry and John Wiley & Sons, Ltd