In this study, the surface of silica nanoparticles (NPs) synthesized using the Stober method was modified with 3-aminopropyltriethoxysilane and hydrolyzed polyacrylamide (HPAM). The surface modification of the silica NPs was confirmed by Fourier transform infrared spectroscopy, field emission gun scanning electron microscopy, and thermogravimetric analysis. The characteristics of the nanopolymer sol were evaluated using rheology, viscosity retention ratio, interfacial tension, and contact angle measurements. The core flooding experiments were performed at 56 °C using Berea core plugs with Klinkenberg permeabilities of 450 and 478 mD and a porosity of ∼21%. The nanopolymer sol was prepared in injection brine (0.24 wt % TDS) with 550 ppm of the nanohybrid, while the polymer solution was prepared with 750 ppm of HPAM. The displaced fluid was dead oil with a viscosity of 60 cP (@56 °C and 7.3 s −1 ). The results show that the nanopolymer sol reduces the capillary forces and increases the viscous forces compared to the HPAM solution. These improved properties of the nanopolymer sol were suitable for increasing the cumulative oil recovery in 2.2% OOIP in comparison with the HPAM solution at a lower concentration.

Understanding of high viscous fluid flow in porous media is very important in the accurate development plan for heavy oil reservoirs. Viscous fingering and effects of unstable flow are phenomenon that must be considered during displacements of heavy oil by water in reservoirs. Experimental problems in rock tests with high viscous fluids (due to exaggerated increases in pressure differential, early breakthrough times, large differences in mobility ratios) are some of the technical difficulties showed during the acquisition of relative permeability curves by unsteady state in heavy oil reservoirs. At the same way, difficulties in conventional interpretation (JBN interpretation is supposing uniform displacement) are challenges that numerical interpretations must be try to solve for modeling accurately what is happening inside rock. This paper presents a number of "best practices" for defining a reliable relative permeability curve in heavy oil reservoirs related to numerical modeling and experimental modeling. Description of phenomenon in a Colombian heavy oil reservoir field are shown for three petrophysical quality rocks (less than 500 mD, around 5000 mD and larger than 10000 mD). Capillary pressure effects are included in the modeling and its importance in the displacement is analyzed. Finally, results of sensibilities to different mobility ratios in crudes with different viscosities (5, 25, 100 and 1000 cp) are presented in the same group of rocks mentioned previously. The results of this study help to understand the influence of viscosity and its impact in total recovery. Introduction The ability of two or more immiscible fluids to flow through a reservoir depends on both the absolute permeability of the formation and on the saturations of the fluids. The concept of absolute permeability is used to describe the flow of a single fluid through rock. When two or more fluids are flowing through a rock, the concepts of effective permeability and relative permeability are useful in describing the flow. Relative permeability curves can be used to convert single phase equations into multiphase estimations at a given saturation. Relative permeability curves can be used to perform reservoir waterfloods or gasflood displacement calculations. Since multiphase-flow equations in reservoir simulators are directly dependent on relative permeability values, accurate measurements are necessary to model and predict reservoir performance. Difficulties in conventional interpretation during waterfloodings (JBN interpretation is supposing one dimensional flow with no fingering and also suppose capillary pressure end effects as negligible) are challenges that numerical interpretations must be try to solve for modeling accurately what is happening inside rock. Use of more flexible capillary and relative permeability correlations for adjust the experimental data with mathematical models, have been developed in the past few years for taking into account the effect of different phenomenon that happen in the interaction rock-fluid.

Desde el año 2008, el Ministerio de Educación Pública, ha propiciado la participación de docentes y estudiantes en el proyecto colaborativo, denominado "Aulas Hermanas", una experiencia convocada por la Red Latinoamericana de Portales Educativos (RELPE). Mediante este artículo, se pretende visualizar la vinculación de esta experiencia con la metodología de proyecto colaborativo y el desarrollo de ella dede la experiencia de Aulas Hermanas, de los docentes y estudiantes de Costa Rica. Así mismo visualiza cual es el alcance de dicha metodología en la puesta en prática del trabajo colaborativo en los grupos entre pares.

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