Perturbative Studies to Calculate the Permeability and Porosity of a CO2 Storage Formation in a Data Shortage Context

Abstract

Injection of CO2 in geological formations is widely recognized as a promising technology within the set of strategies to be developed to reduce the concentration of atmospheric CO2. The management of long-term safety related with Geological Storage of CO2 (CGS) should be an iterative and interactive on-going improvement process throughout the life of the project. This process, through application of appropriate methodologies, should establish a robust and reliable framework for identifying, assessing and managing each project phase. It plays a key role in both the definition and planning of CO2 injection strategies at any scale and in its operational, closure and post-closure stages.A key element to calculate the probability of leakage risk includes the interaction of the CO2 plume with potential flow paths or with risk elements. This requires obtaining the temporal evolution of the injected CO2 plume (dynamic probability). Sufficient understanding of the CO2 plume migration within the reservoir is essential to assess the risks of leakage for different injection scenarios. The stochastic simulation can be a valuable tool to achieve a sufficient understanding of the underlying mechanisms that control the behaviour of a system. However, it is not uncommon that using probabilistic modelization to make predictions of future behaviour of a system (predictive modelization) turns out to be a complex process. The CO2 plume evolution and structural and hydrodynamic trapping mechanisms are key elements in the safety of a site. These are determined by the number of gravity, Γ, a dimensionless parameter that measures the ratio between buoyancy and viscous forces, and which is defined from both operating and reservoir parameters and, among others, is a function of the injection rate.The models used in this work are based on published studies on CO2 injection from a single well into a deep permeable aquifer saturated with saline fluid (saline aquifer). The type of solution obtained is a function of the relationship between buoyancy and viscous forces. According to the injection rate, in viscous forces domain cases it is possible to decouple the petrophysical variables of the system that determine the advance of the plume (porosity and permeability) depending on the shape ratio of the plume (rmin/rmax or ratio between the radii at the bottom and top of the CO2 plume).This is a methodology that makes sense for applying it to the initial stages of characterization of potential CO2 geological storage sites in situations of shortages of data, which it is a common feature of deep saline aquifers. Hontomín site intends to be a demo site for CO2 injection in carbonate formations, these being the probable most promising CO2 geologic storage formation type in Spain. A basic characteristic of these sites is the lack of deep carbonate formations porosity and permeability data, critical variables especially in risk studies. This methodology has its scope in the injection phase for a preliminary characterization, before the start of a possible systematic characterization of the site prior to a potential industrial use. So, a study has been conducted to explore the possibility of using the perturbation of the system by the CO2 injection to get an upscaling of both porosity and permeability en grand of the storage formation from the in situ or laboratory characterization phases through stochastic modelling of the CO2 plume and the appropriate injection strategies within the range of viscous forces domain cases. This provides a reduction of the uncertainties in the calculation and adjustment of dynamic probabilities of both the plume advance and the pressure increase due to the injection of CO2. As a whole it will result in an improvement in the storage safety assessment