This paper presents a novel integrated approach for numerical simulation of foam core-flood experiments in the absence and presence of oil. The experiments consisted of the co-injection of gas and Alpha-Olefin Sulfonate (AOS) surfactant solution into Bentheimer sandstone samples initially saturated with the surfactant solution [see Simjoo & Zitha (2013)]. The foam model implemented is based on a local equilibrium and describes dependency of foam mobility reduction factor using several independent functions, such as liquid saturation, foam velocity, oil saturation and capillary number. First, a series of numerical simulation was conducted to investigate the effect of surfactant concentration on pressure drop across the core for the foam flooding in the absence of oil. To this end, the dry-out and gas velocity functions in the foam model were determined from the experimental data obtained at low and high-quality regimes of foam flow at a constant injection velocity. Next, pressure drop profiles of foam flooding at two different surfactant concentrations were modelled to determine the parameters of the surfactant-dependent function in the foam model. The simulation results fit the experimental data of pressure drops very well. Then, the numerical simulations investigated the oil displacement, by foam where the main goal was to determine the foam model parameters dedicated to the oil saturation-dependent function. The pressure drop across the core, oil-cut, and oil recovery factor were modelled, and an excellent match was obtained between the pressure profile and the oil recovery obtained numerically compared with those obtained from the corresponding core-flood experiments.

The objective of this study is to discover a synergistic effect between foam stability in bulk and micro-emulsion phase behaviour to design a high-performance chemical system for an optimized alkaline–surfactant–foam (ASF) flooding for enhanced oil recovery (EOR). The focus is on the interaction of ASF chemical agents with oil in the presence and absence of a naphthenic acid component and in situ soap generation under bulk conditions. To do so, the impact of alkalinity, salinity, interfacial tension (IFT) reduction and in situ soap generation was systematically studied by a comprehensive measurement of (1) micro-emulsion phase behaviour using a glass tube test method, (2) interfacial tension and (3) foam stability analysis. The presented alkali–surfactant (AS) formulation in this study lowered IFT between the oil and aqueous phases from nearly 30 to 10⁻¹–10⁻³ mN/m. This allows the chemical formulation to create considerably low IFT foam flooding with a higher capillary number than conventional foam for displacing trapped oil from porous media. Bulk foam stability tests demonstrated that the stability of foam diminishes in the presence of oil with large volumes of in situ soap generation. At lower surface tensions (i.e. larger in situ soap generation), the capillary suction at the plateau border is smaller, thus uneven thinning and instabilities of the film might happen, which will cause acceleration of film drainage and lamellae rupture. This observation could also be interpreted by the rapid spreading of oil droplets that have a low surface tension over the lamella. The spreading oil, by augmenting the curvature radius of the bubbles, decreases the surface elasticity and surface viscosity. Furthermore, the results obtained for foam stability in presence of oil were interpreted in terms of phenomenological theories of entering/spreading/bridging coefficients and lamella number.

Strong foam can be generated in porous media containing oil, resulting in incremental oil recovery; however, oil recovery factor is restricted. A large fraction of oil recovered by foam flooding forms an oil-in-water emulsion, so that costly methods may need to be used to separate the oil. Moreover, strong foam could create a large pressure gradient, which may cause fractures in the reservoir. This study presents a novel chemical-foam flooding process for enhanced oil recovery (EOR) from water-flooded reservoirs. The presented method involved the use of chemically designed foam to mobilize the remaining oil after water flooding and then to displace the mobilized oil to the production well. A blend of two anionic surfactant formulations was formulated for this method: (a) IOS, for achieving ultralow interfacial tension (IFT), and (b) AOS, for generating a strong foam. Experiments were performed using Bentheimer sandstone cores, where X-ray CT images were taken during foam generation to find the stability of the advancing front of foam propagation and to map the gas saturation for both the transient and the steady-state flow regimes. Then the proposed chemical-foam strategy for incremental oil recovery was tested through the coinjection of immiscible nitrogen gas and surfactant solutions with three different formulation properties in terms of IFT reduction and foaming strength capability. The discovered optimal formulation contains a foaming agent surfactant, a low IFT surfactant, and a cosolvent, which has a high foam stability and a considerably low IFT (1.6 × 10^-2 mN/m). Coinjection resulted in higher oil recovery and much less MRF than the same process with only using a foaming agent. The oil displacement experiment revealed that coinjection of gas with a blend of surfactants, containing a cosolvent, can recover a significant amount of oil (33% OIIP) over water flooding with a larger amount of clean oil and less emulsion.