Sequential storage and in-situ tracking of gas in geological formations by a systematic and cyclic foam injection- A useful application for mitigating leakage risk during gas injection

Abstract

Geological storage of Carbon Dioxide (CO2) can safely and permanently store a huge amount of anthropogenic greenhouse gases. However, the possible leakage of mobile gases through the cap rock that confines them within the reservoir is a cause of safety concerns. Residual and solubility trapping of the injected gas in the pores of the rock can reduce the amount of mobile gas lying below the cap rock. These trapping mechanisms will only begin at the end of several decades of gas injection, which implies that there is an imminent risk of discharge of large amount of gas in the event of a leak. This paper presents a method to fast-track and enhance residual and solubility trapping process while gas injection is in progress, such that only a fraction of the injected gas will migrate and be trapped beneath the cap rock after injection ceases. The method involves cyclic injection of gas and water (containing small amount of foaming agent). Foams are known to have gas trapping characteristics during flow in porous medium. A series of laboratory experiments was conducted on representative rock samples at different reservoir conditions. The results show a sequential and cumulative growth in trapped gas during cyclic injection of gas and foam based on in-situ and real time measurements of gas saturation in the samples using electrical resistivity tool. The amount of trapped (residual) gas depends on the type of gas (N2 or CO2), water salinity, concentration of the foaming agent, and temperature. The highest residual gas saturations (50%–70% of reservoir pore volume) occurred at a temperature and water salinity typical of a deep saline aquifer (45 °C and 58,000 ppm water). At a high water salinity of 242,000 ppm, the residual gas saturation was significantly lower (27%–30%). Similarly, at a high temperature of 90 °C, the residual gas saturation reduced to 27%. Residual gas could not be sustained when CO2 is injected compared to N2 because of the low interfacial tension between CO2 and water, which reduces the foam quantity and strength. The importance of foam stabilizing agents (e.g. polymers and nanoparticles) in addressing the observed shortcomings in CO2 foam and for foam injection in high salinity - high temperature reservoirs is discussed. A field scale application of this method is also highlighted.