Impact of Fluid Distribution and Petrophysics on Geophysical Signatures of CO2 Storage Sandstone Reservoirs

Abstract Carbon Capture and Storage (CCS) is a key element to achieving net‐zero energy challenge timely. CCS operations require the integration of geophysical data, such as seismic and electromagnetic surveys, numerical reservoir models and fluid flow simulations. However, the 10–100s m resolution of seismic imaging methods complicates the mapping of smaller scale rock heterogeneities, while borehole measurements commonly show large fluctuations at sub‐cm scales. In this study, we combine laboratory data, well‐logging, rock physics theories and a proof‐of‐concept time‐lapse seismic modeling to assess the effect of pore‐scale fluid distribution and petrophysical heterogeneities on the expected performance of whole‐reservoir CCS operations in deep saline aquifers, by analogy to the Aurora CCS site, North Sea. We monitored the elastic and electrical properties of three sandstone samples with slightly different physical and petrographic properties during carbon dioxide (CO 2 ) flow‐through tests under equivalent in situ effective pressure. We inferred the CO 2 ‐induced damage in the rocks from the variations of their hydromechanical properties. We found that the clay fraction, CO 2 ‐clay chemical interactions, and porosity were the main factors affecting both the CO 2 distribution in the samples and the hydromechanical response. We used seismic modeling of well‐log data and the laboratory results to estimate the reservoir‐scale time‐lapse seismic response to CO 2 injection and to assess the effect of the rock heterogeneities in our interpretation. The results show that disregarding the effect of rock heterogeneities on the CO 2 ‐brine fluids distribution can lead to significant misinterpretations of seismic monitoring surveys during CCS operations in terms of both CO 2 quantification and distribution.