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.

Petroleum reservoirs under primary, secondary or tertiary recovery processes usually experience simultaneous flow of three fluids phases (oil, water and gas). Reports on some mathematical models for calculating three-phase relative permeability are available in the Literature. Nevertheless, many of these models were designed based on certain experimental conditions and reservoir rocks and fluids. Therefore, special care has to be taken when applying them to specific reservoirs. At the laboratory level, three-phase relative permeability can be calculated using experimental unsteady-state or steady state methodologies. This paper proposes an unsteady-state methodology to evaluate three-phase relative permeability using the equipment available at the petrophysical analysis Laboratory of the Instituto Colombiano del Petróleo (ICP) of Ecopetrol S.A. Improvements to the equipment were effected in order to achieve accuracy in the unsteady-state measurement of three-phase relative permeability. The target of improvements was directed toward to the attainment of two objectives:1) the modification of the equipment to obtain more reliable experimental data and 2) the appropriate interpretation of the data obtained. Special attention was given to the differential pressure and uncertainty measurement in the determination of fluid saturation in the rock samples.  Three experiments for three-phase relative permeability were conducted using a sample A and reservoir rock from the Colombian Foothills. Fluid tests included the utilization of synthetic brine, mineral oil, reservoir crude oil and nitrogen. Two runs were conducted at the laboratory conditions while one run was conducted at reservoir conditions. Experimental results of these tests were compared using 16 mathematical models of three-phase relative permeability. For the three-phase relative permeability to oil, the best correlations between experimental data and tests using Blunt, Hustad Hasen, and Baker's models were obtained at oil saturations between 40% and 70%.

Implementation of probabilistic methods, in the analysis of the reservoir variables allow obtaining more realistic models and identifying opportunities that generate greatest impact on the models.This finally leads to obtain better a developing plan, supported in ranked desitions. Colombian Petroleum Institute (ICP) in 2003 developed the methodology ASIA (Advanced System Analysis for Injection) wich is an adaptation of CGM technic for the analytical modeling of water injection.Within it Areal and vertical distribution of water in the reservoir is modelated by the history match of the oil water ratio behavior. This paper shows the strategy used to incorporate the risk and uncertainty analysis to the ASIA methodology in order to obtain an assisted history match and a panoramic review of the parameters behavior.

A naturally fractured reservoir is composed by a system of fractures created by breakdown of the layers, caused by tectonic movements. Although all reservoirs have some fractured grade, only are considered naturally fractured, those where the system of fractures presents any effect upon flow of fluids.Whole core analysis is critical for characterizing directional permeability in heterogeneous, fractured reservoirs. Whole core measurements are essential for heterogeneous reservoirs because small-scale heterogeneity may not be appropriately represented in plug measurements. For characterization of multiphase flow properties in heterogeneous rock, routine and special core analysis in whole core is also required.In this paper, we provide an overview of routine and special core-analysis measurements on whole cores. Improved experimental equipments for measurement of routine core analysis on whole core (fluid saturation, clean, directional permeability, and porosity) under a maximum confining stress of 10,000 psi, were made in the ECOPETROL-ICP's routine and special core laboratories. The advantage of these equipments is that allows evaluating directional permeability (x, and, z) considering variations in permeability caused by fractures and other heterogeneities. Finally we discussed results from routine core analysis on whole cores for Colombian heterogeneous sandstone. Also in this paper the effect of scale (sample size) on the measured properties are also shown.

El suministro de propantes a yacimientos no convencionales es uno de los mayores desafíos que enfrentan las empresas petroleras para completar los pozos a tiempo, buscando minimizar los costos. Teniendo en cuenta esto, en el presente trabajo se busca plantear alternativas para abastecer el material apuntalante al pozo, y evaluar a través de simulación Monte Carlo cuál de ellas es la mejor basados en el criterio de menor costo. Los resultados muestran que bajo las condiciones y supuestos dados, la mejor alternativa es la de importación directa por parte de la empresa operadora, teniendo en cuenta que su costo es más bajo comparado con las opciones de comprarlo a una compañía de servicio técnico o a un intermediario importador.Palabras clave: yacimientos no convencionales, propantes, simulación de Monte Carlo. Evaluating cost alternatives for supplying proppants to an unconventional reservoir in Colombia ABSTRACTThe supply of proppants to unconventional reservoirs is one of the biggest challenges that oil companies are facing in order to complete wells on time while minimizing costs. With this in mind, this article seeks to propose alternatives for supplying proppants to wells and to develop an evaluation using Monte Carlo simulation, which is one of the best tools based in lowest cost criteria. Results of this research show how under the given conditions and estimations, the best alternative the direct import is done by the oil company, considering that the cost is lower compared with other options such as buying the oil from a technical service company or from a third-party import company.