Investigation of Chemical-Foam Design as a Novel Approach toward Immiscible Foam Flooding for Enhanced Oil Recovery.

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.

Investigation of certain physical-chemical features of oil recovery by an optimized alkali-surfactant-foam (ASF) system.

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.

Gas permeability of foam films stabilized by an alpha-olefin sulfonate surfactant.

The gas permeability of equilibrium foam films stabilized with an alpha-olefin sulfonate surfactant was measured. The permeability coefficient, K (cm/s), was obtained as a function of the electrolyte (NaCl) concentration, surfactant concentration, and temperature. The addition of salt to the film-forming solution leads to a decrease of the film thickness, which was complemented by an increase of K up to a certain value. Above that critical salt concentration, the gas permeability decreases even though the film thickness also decreases. We explain this effect as a result of interplay of the film thickness and the adsorption monolayer permeability for the permeability of the whole film, i.e., the thermodynamic state of the film. The classical theories that explain the process were applied. The gas permeability of the film showed an unexpected increase at surfactant concentrations well above the critical micelle concentration. The origin of this effect remains unclear and requires further studies to be clarified. The experiments at different temperatures allowed the energy barrier of the permeability process to be estimated.

The effect of pH on coupled mass transfer and sol-gel reaction in a two-phase system.

The coupled mass transfer and chemical reactions of a gel-forming compound in a two-phase system were recently analyzed in detail [Castelijns et al. J. Appl. Phys. 2006, 100, 024916]. In this successive work, the gel-forming chemical tetramethylorthosilicate (TMOS) was dissolved in a mineral oil and placed together with heavy water (D2O) in small cylinders. The transfer of TMOS from the oleic phase to the aqueous phase was monitored through nuclear magnetic resonance (NMR) relaxation time measurements of hydrogen in the oleic phase. The rate of gelation was measured through NMR relaxation time measurements of deuterium in the aqueous phase. The temperature, the initial concentration of TMOS, and the type of buffer in the aqueous phase were varied in the experiments. The mass transfer is driven by the rate of hydrolysis, which increases with temperature. The hydrolysis rate is the lowest at a neutral pH and is the highest at a low pH. In the aqueous phase, a sharp decrease in the transverse relaxation time (T2) of 2H is observed, which is attributed to the gel reaction. The plateau in T2 indicates the gel transition point. The gel rates increase with increasing temperature and increasing concentration, and are the highest at a neutral pH.