An experimental and numerical investigation into permeability and injectivity changes during CO₂ storage in saline aquifers

• Main Author: Bacci, Giacomo
• Other Authors: Durucan, Sevket ; Korre, Anna
• Published: Imperial College London 2011
• Subjects: 622
• Online Access: http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.538253

CO2 storage appears as one of the best solutions to effectively decrease carbon emissions into the atmosphere in the short to medium term. CO2 can be stored in different types of geological formations. Among the various storing options, deep saline aquifers have the greatest capacity. As supercritical CO2 is injected in the aquifers, a number of strongly coupled chemical and physical processes occur. Among these various mechanisms, dissolution and precipitation of minerals, in particular carbonates, and halite deposition due to vapourisation of water require particular attention as they can lead to significant reduction in injectivity. This research investigated the mechanisms involved in injectivity losses through experimental and theoretical methods. The impact on injectivity of permeability changes occurring at various distances from the wellbore was studied using an idealised 1-D CO2 injection well flow model. A new experimental set-up was used to investigate the effect on dissolution/precipitation mechanisms of the pressure and temperature changes that the fluid is subjected to as it advances from the wellbore. Additional CO2 core flooding experiments were conducted on limestone and sandstone cores saturated with saline water in order to study the effects of water vapourisation. These vapourisation experiments aimed to provide a relationship between porosity changes and resulting permeability variations representing the effect of salt precipitation due to vapourisation. Such relationship was used to obtain more accurate results from a 2-D radial CO2 injection well flow model studying the effect of salt precipitation on the field. Numerical modelling of the injection wellbore have shown that changes in the petrophysical properties of the reservoir several metres away from the wellbore can still have a significant impact on injectivity. As indicated by the experimental research carried out, pressure and temperature gradients that exist inside the reservoirs may lead to re-precipitation in the far field, however no significant permeability and porosity changes were detected to suggest major losses of injectivity due to these effects. The results of vapourisation experiments have shown that small reduction in porosity can induce significant impairments in permeability. Results of the 2-D model showed that without appropriate injection strategies the technical and economical feasibility of CO2 storage projects can be compromised due to this effect. The numerical study also highlighted the possibility of the progressive formation of a layer of halite scaling in the interface between host-rock and cap-rock which would work as an extra sealing protection in the near wellbore area.