Multiphase Flow Simulation with Applications for CO2 Storage

Geological storage of carbon dioxide (CO2) has potential to significantly reduce atmospheric emissions of greenhouse gases. However, challenges exist to the successful establishment of this process. These include estimating and understanding storage capacity as well as its economic viability. A large proportion of Europe’s potential storage capacity is to be found in large open aquifers. However, in times when the European carbon price is low, storage in depleted oil reservoirs may be required to make early commercial projects economically viable. Regulation will require that storage in these sites is well understood and it currently requires conformity of actual with modelled behaviour. In this thesis we consider two areas with direct implication for these issues. Firstly, we consider the effect of top-surface structure and heterogeneity upon the storage capacity of open aquifers. It is found that top-surface structure is more likely to decrease storage efficiency in models with low average reservoir dip and/or permeability. Heterogeneity is seen to reduce injectivity and reduce capacity in low permeability models but increase lateral spread of CO2 and storage efficiency in higher permeability cases. Both features can change storage capacity by more than a factor of two. Secondly, we undertake investigation into 1D solutions for three-phase flow problems representative of CO2 storage in depleted oil reservoirs. We begin by trying to determine rigorously the physical solution to three-phase flow problems that may have non-unique solutions using the third-order essentially non-oscillatory (ENO) numerical method. However, we demonstrate that ENO only produces first-order convergence in discontinuous solutions, which means rigorous analysis using our proposed methodology is not possible. We do, however, benchmark compositional three-phase, three-component ENO simulations against analytic solutions for the first time and demonstrate that ENO is still preferable to low-order numerical methods. Finally, we demonstrate the convergence of three-phase numerical solutions by comparing solutions with water-wet and oil-wet capillary pressure functions as the magnitude of the capillary pressure functions become small