This paper investigates surfactant flooding using a microfluidic device. Its purpose is to validate the results obtained in recent core experiments reported by Janssen et al. (2019) and provide mechanistic interpretation. In these experiments authors injected a surfactant slug into sandstone cores, initially brought to residual oil saturation. Low oil/water IFT leads to oil mobilization and the formation of emulsions. Furthermore, authors found that oil is more effectively mobilized when the injected surfactant is at optimum salinity. In this study the following experiments are subsequently conducted in a microfluidic device to validate this optimum surfactant slug: primary drainage, waterflooding and surfactant flooding. In case of the surfactant flooding experiment, the micro-emulsion formation was observed at 1.5 PV and 1.25 PV for the under-optimum and optimum conditions respectively. In both conditions, an increased oil mobilization was obtained, compared to the waterflooding experiment. However, the optimum condition, with a slug salinity of 2.0 wt% NaCl outperformed the under-optimum condition with a slug salinity of 0.4 wt% NaCl in terms of oil recovery. The increased salinity in case of the optimum condition results in an lower IFT compared to the under-optimum condition, which in turn results in an higher capillary number. The obtained results indicate a dependency between the capillary number and the amount of oil droplets. The optimum capillary number can be found at the lowest oil saturation with the largest amount of droplets. Based on the results obtained from the conducted experiments on this microfluidic device, upscaling is considered to be a viable and educated recommendation.

Chemical Enhanced Oil Recovery (CEOR) methods can increase the oil recovery of a reservoir to more than 60% of the volumes originally in-situ. Typical oil recoveries range from 20% to 40% of OIIP under traditional primary and secondary recovery stages. The understanding of the mechanisms that control such complex processes is essential considering the continuously growing worldwide energetic demand. History matching of core flooding experiments data through numerical modeling is a powerful tool to understand the physical parameters and mechanisms that control the flow of fluids in novel recovery strategies as Foam-Assisted Chemical Flooding (FACF) in which the effects of oil/water interfacial tension generated by surfactant are combined with mobility control provided by foam.
This report presents the mechanistic modeling study of seven experiments on different core flooding techniques including continuous gas injection, Water-Alternating-Gas injection (WAG), surfactant injection and Foam-Assisted Chemical Flooding (FACF) on Bentheimer sandstone cores. CT scan images were acquired to monitor the evolution of saturation distributions, starting from the primary drainage stage. A 1D model was built for each experiment to history match the saturations revealed by the CT scan imaging through the cores at different pore volumes injected, pressure drops, production fractions, and oil recovery. Good agreement between simulation results and experiments was obtained, with minor mismatches in breakthrough times (0.04 ± 0.02 PVI) for some experiments.
For the history match of primary drainage and forced imbibition, the parameters of the Brooks-Corey equation for calculating relative permeabilities were obtained from a regression analysis on the available observed data. Actual residual saturations were lower than the average saturations reported at the end of each flooding stage.
History-matching of the continuous gas injection at waterflooding residual oil saturation and WAG at connate water saturation experiments demonstrated that the initial water saturation in secondary and tertiary gas injection strategies is a parameter that greatly controls gas mobility. Gas trapping and its effect on the flooding was confirmed for the WAG experiment.
The mechanistic modeling of surfactant injection at under-optimum salinity conditions showed that the geochemical modeling to determine initial ionic concentrations in the aqueous phase can be neglected in absence of naphthenic acids in the oleic phase, even when alkali is present in the solution. The shape and size of the oil bank formed after mobilization of residual oil are controlled by the proper numerical representation of the phase behavior in the oil/microemulsion system, whilst other features as oil bank velocity are controlled by surfactant adsorption. Relative permeability curves at low trapping numbers (forced imbibition) and high trapping numbers (under-optimum salinity conditions) were obtained.
Finally, history match of the drive foam in FACF led to the conclusion that the local equilibrium model for foam model implemented in UTCHEM may not be able to cover the entire range of possible mechanisms controlling the foam formation, specifically, the mechanism by which foam is generated due to increase in interstitial velocity and local pressure drop in zones of reduced effective porosity near a previously formed oil bank.