Since the founding of CMI, the Celia group has developed a hierarchy of analytical, semi-analytical, and numerical models that allow simulation of CO2 injection and leakage, with a particular focus on leakage along old wells. Geared toward quantitative estimation of leakage on large scales, the group’s methods are very efficient and allow for simulations that include hundreds to thousands of leaky wells across many layers of geological formations.
Large-scale model development
This year, Michael Celia and colleagues continued to develop their models and apply them to a number of potential injection sites. These models now predict pressure buildup in the formation, movement of both CO2 and brine within the injection formation and across confining units into other formations, capillary trapping of CO2, and dissolution of CO2 into the brine phase (that is, solubility trapping – see Figure 15 for an example). In 2012, studies examined the impact of different modeling choices on practical simulations of CO2 fate and transport and the limitations of the Vertical Equilibrium (VE) assumption. A range of models, including the VE models, were also applied to several sedimentary basins that have practical importance, including the Illinois Basin, the Michigan Basin, and the Alberta Basin, as well as the Basal Aquifer of central North America. These simulations have focused on very large-scale systems at scales of injection that can have an impact on the climate problem.
The researchers have also developed a model which eliminates the Vertical Equilibrium assumption while still maintaining its essential computational efficiency – that model is based on dynamic reconstruction of the vertical pressure and saturation profiles, in the context of multi-scale modeling. Development of VE models in the context of multi-scale analysis allows this extension – the idea is described in detail in their recent textbook, Geological Storage of CO2 : Modeling Approaches for Largescale Simulation. The team is also developing a macro-scale percolation model with collaborators at Lawrence Berkeley National Laboratory. Collectively this suite of modeling approaches gives the group substantial flexibility in modeling different aspects of the CO2 problem.
Active reservoir management and CO2 utilization
Celia and colleagues also apply their models to consider ways to make carbon capture and storage more effective and economical. In a study of the potential advantages of brine production at CCS sites for the purpose of pressure control, the researchers found that brine production reduced pressure build-up at the CO2 injection well, thus substantially reducing the Area of Review for given injections as well as the risk of leakage, while possibly enabling higher injectivity.
They have also looked more broadly at possible CO2 utilization, in the context of Carbon Capture, Utilization, and Storage (CCUS). While produced brines can provide some benefits in terms of water usage, a potentially more important use is associated with heat extraction and the use of CO2 in pressure support for geothermal production. In conjunction with collaborators at the Lawrence Livermore National Laboratory, they have investigated how a CO2 injection operation could be integrated into a large-scale geothermal production system (Figure 16). As opposed to earlier studies, CO2 is not used as the heat-carrying fluid, but instead the injection is used in a pressure support role and the resident hot brines are produced as the working fluid. Eventual CO2 breakthrough in allowed and is accounted for in the overall analysis. The system may be promising in regions of the country with existing geothermal capacity.