J.D. Ortiz, Advanced Petroleum Research Institute (APRI); U.E. Guerrero, APRI; S.F. Muñoz, APRI, Universidad Industrial de Santander
Categoría: Marque con una “X” • • • Artículo Técnico Tesis Pregrado Tesis Posgrado X
Derechos de Autor 2011, ACIPET Este artículo técnico fue preparado para presentación enel XIV Congreso Colombiano del Petróleo organizado por ACIPET en Bogotá D.C. Colombia, 22 - 25 de Noviembre de 2011. Este artículo fue seleccionado para presentación por el comité técnico de ACIPET, basado en información contenida en un resumen enviado por el autor(es).
Abstract Although the recovery factor of any hydrocarbon reservoir depends on its geology and the properties of the fluidscontained within, proper field management practices supported by the proper characterization of the reservoir rock is the key to success in improving the recovery for a field. The primary tools for reservoir characterization are wellbore logging and limited core derived laboratory measurements for calibrating field logs and establishing relationships between log responses and the petrophysicalproperties of interest. However, from the very early days of hydrocarbon exploration and production, core samples have been regarded as “ground truth” and used as identifying reservoir samples for determining important physical properties such as porosity, permeability, grain density, and important rock-fluid interaction properties such as wettability, capillary pressure and relative permeability. Indifferent cases, operational difficulties during the coring process make it impossible to retrieve quality samples, if any. In addition, if logs are not calibrated against real core samples, then the interpretation may introduce considerable uncertainty in the reservoir description. In an effort to find alternatives to coring, sidewall cores and drilled cuttings have been used to obtain somepetrophysical information. However, the conventional core analysis tools and methods are not designed for amorphous and/or very small rock samples. Therefore, a significant reduction in the level of uncertainty requires the development of techniques to accurately characterize rock microstructure and to relate this information to measured petrophysical properties. Computed Assisted Tomography (CAT) hasprovided the oil industry with many important rock and rock-fluid properties in a nondestructive manner. Although CAT scanners have seen constant improvement in speed since their inception, the spatial resolution has not improved from the typical 350 – 450µm range. Typical pore sizes of reservoir rocks vary from sub-micron to few microns and therefore the oil industry has been looking foralternatives such as micro CAT scanners (µ-CAT). This paper presents a comprehensive review of the state-of-the-art in µ-CAT-based petrophysical research. The various techniques used for image reconstruction, artifact reduction, network extraction, and pore size distribution leading to the building of realistic pore network models and then determining different petrophysical properties are described. Thepaper also discusses the application of digital core analysis in Colombia and future directions in Pore Network Modeling (PNM) as a tool to predict multiphase flow properties in complement to special core analysis (SCAL). Introduction The oil and gas industry is increasingly reliant on more effective reservoir characterization to reduce the risks associated with new field development, betterdelineate producing fields and identify new reserves. Traditionally, the main tools for reservoir characterization have been wellbore logging and limited core derived laboratory measurements. Well logging tools have successfully provided the industry with valuable petrophysical data. Properly calibrated logging tools can give reasonable estimates of formation density, porosity, lithology, presence of...