A Laboratory Study to Develop Co2-Foam Formulation for High Temperature and High Salinity Carbonates Reservoirs in Abu Dhabi

Abstract

Abstract Specifics challenges for chemical enhanced oil recovery (cEOR) exists in high temperature and high salinity carbonate reservoirs in Abu Dhabi especially with intermediate to high permeability range (10 – 100s mD). CO2-Foam process was investigated through a careful laboratory approach. This involves extensive laboratory work including coreflood experiments to select the most effective process in terms of foam characteristics and behavior. Foam formulations in various brine (sea water, formation brine) were selected based on a workflow relying on bulk measurements such as solubility, stability, foam properties with/without oil, and solubility robustness versus brine and temperature variations. Sandpack tests were conducted to characterize the foam rheological behavior of various formulations at various gas fraction. A formulation based on formation brine was then selected. Coreflood on restored reservoir cores were conducted to fully characterize its behavior toward interstitial velocity and gas fraction variation in porous media without crude oil. CO2 foam behavior in reservoir core was finally investigated in presence of oil. The selected CO2 foam shows promising foaming behavior for such harsh conditions. It exhibits a usual shear-thinning behavior in porous media showing promising mobility reduction factor (MRF) at in-depth interstitial velocity. Critical shear-rate was observed in sandpack experiments. High quality foam forms only for higher velocity and is maintained when velocity is decreased. This critical interstitial velocity in 40 mD reservoir cores is very low (below 0.3 ft/day) whereas it is above 20 ft/day in the higher permeability sandpack. The behavior toward gas fraction shows a stable MRF from 0.5 to 0.8-0.9 with a critical Fg between 0.8 and 0.9. Foam behavior in presence of oil was evaluated in reservoir cores. Though foam quality is significantly impacted by oil, foam was found to form. Comparison of alternate injection and co-injection shows the necessity to fine tune slug sizes in case of an alternate injection to ensure a lasting foam. A significant selective mobility reduction (SMR) was observed when moving from high permeability sandpack to intermediate permeability reservoir cores. CO2-Foam mobility reduction increases by an order of magnitude with the permeability, showing higher MRF in high permeability. This applied laboratory study on intermediate permeability, high temperature, and high salinity carbonate core sample shows that a foaming formulation was found in such challenging conditions. This formulation in formation brine was proved to develop foam at low shear-rate with low MRF at reservoir conditions in reservoir cores and a high MRF in high permeability sandpack. More work is still needed to increase the resistance to oil and evaluate the SMR effect in reservoir cores.