We establish a comprehensive description of the patterns formed when a wetting liquid displaces a viscous fluid confined in a porous medium. Building on model microfluidic experiments, we evidence four imbibition scenarios all yielding different large-scale morphologies. Combining high-resolution imaging and confocal microscopy, we show that they originate from two liquid-entrainment transitions and a Rayleigh-Plateau instability at the pore scale. Finally, we demonstrate and explain the long-time coarsening of the resulting patterns.

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.

In heavy oil reservoirs operated by steam injection, foam has a double benefit. By improving the steam sweep efficiency within the reservoir, foam increases oil recovery while reducing the amount of injected steam. However, in the field, this technology is not always very effective due to the fact that it is difficult to find foaming agents that can withstand temperatures above 200°C. Moreover, the agents that form stable foams at such temperatures are often insoluble at ambient temperature, and therefore difficult to solubilize in the field. Thus, a compromise between good solubility in surface conditions and high temperature foaming performances in the reservoir has to be found. In this study, we show that it is possible to boost chemicals that form foam at very high temperature with an additive to greatly improve their solubility at ambient temperature while maintaining their high foaming performance at high temperature. Two foaming agents of increasing degree of hydrophobicity (H and HH) were initially selected for this study. The first one shows high foaming performances in porous media and in a high-pressure cell at temperatures comprised in between 150 and 220°C. The second one, more hydrophobic, is particularly performant at temperatures comprised in between 220°C and at least 280°C. Using a robotic platform, the temperature at which the foaming solution for agents H and HH needs to be heated to be solubilized, was evaluated with an accuracy of 5°C in four brines (varying salinity and hardness). We found that the temperature at which both agents become soluble is above 60°C, still too high for a field application. In the second part of the study, these hydrophobic molecules were coupled to a pre-selected additive. The resulting mixtures were again qualified in terms of solubility and foaming performances. We show that by coupling these hydrophobic agents with an additive, we are able to maintain their excellent foaming performances while decreasing their solubilisation temperature down to room temperature. To the best of our knowledge, this is the first time that very high temperature foam stability assessment up to 280°C is combined to solubility measurements to design performant foaming solutions that will be easy to handle in the field for steam foam applications. Interestingly, we show that the hydrophobicity of agents that is required for high temperature foam generation can be balanced by a more hydrophilic agent without reducing their foaming performances.