Micro-scale experimental investigations of non-Newtonian polymeric flow in carbonates

The growing energy demand has been accelerating the improvement of extraction techniques of energy re-sources. In the oil and gas industry, understanding the behavior of drilling fluids in the inner filter cake zone and cake displacement during production may impact formation damage, and consequently, financial and environ-mental risks. To address this issue, the present work was designed to investigate the effect of fluid rheology and pore space topology on cake formation and rearrangements at pore levels. Two sets of experiments were con-ducted with different concentrations of xanthan gum (XG) solutions and variable oil flow rates. Variable oil flow rates were used to mimic different production scenarios. Miniature cores were drilled from a carbonate core sample with petrophysical characteristics analogous to the Brazilian pre-salt formations. Placed inside of X-ray transparent core holders, these miniature core plugs were injected by different fluids using an ex-situ core flooding setup. Core holders were imaged at different stages of an experiment using a Heliscan micro-CT imaging system. The non-destructive imaging technique enables visualization of the pore space and its fluid occupancies at different stages of an experiment, i.e., different saturations, using high-resolution imagery. To accurately segment both phases (oil and XG solution), two different sets of images were acquired at each saturation stage, i. e., reference and target stages. These images were then registered carefully in three dimensions using the Thermo ScientificTM PerGeos software after some image preparation steps. Image preparation tends to improve image registrations, which is often challenging in images of carbonates with wide pore size distributions and a dopant agent. We introduced several novel workflows to segment microporosity regions and their contributions to the total porosity. The reference-state images obtained after XG injection were used to segment the resolvable pore space. During drainage, oil-to-XG displacements decreased the number of pores with XG in their centers. In the experiment with a less permeable core, we observed a high frequency of small residual polymer clusters. The small pores and thin throats hindered polymer displacement. We identify and subsequently quantify the disconnected oil phase. The results of this experimental study further expand our knowledge of rock/fluid interaction during drilling operations by considering the rheological and petrophysical properties of the drilling fluid and reservoir rock in the inner filter cake formation.