The Importance of Outcrop Reservoir Characterization in Oil-Industry Facies Modelling Workflows - a Case Study from the Middle Jurassic of the Maciço Calcário Estremenho, Portugal
Authors: Ferreira Joana , Azerêdo Ana C. , Bizarro Paulo , Ribeiro Maria Teresa , Sousa Ana 
Published: November 2016

Abstract
Characterizing highly heterogeneous carbonate reservoirs requires the integration and detailed analysis of petrophysics, facies, diagenesis, geometry, depositional environments and lateral and vertical variability. This is often challenging to conceptual models at oil-field scale, as this thorough analysis is hard to fully reproduce at reservoir-scale models. In order to improve skills and interpretations on both approaches, we addressed a case study from a Middle Jurassic outcrop of Portugal as an analogue for a carbonate reservoir.
The outcrop exhibits three barrier shoreface lithofacies: L1 - oolitic and bio-intraclastic grainstones (divided into: L1a- with planar stratification or unstructured; L1b - with diverse cross-stratification styles); L2 - coarser grained grainstones/rudstones; and L3- coral/algal biostromes. Outcrop analysis was combined with petrographic/diagenetic studies of rock samples. Regarding petrophysical properties, three methods were used to determine the porosity: thin-section impregnation with blue-dyed epoxy resin, rock-slab water saturation and, for a few samples, plug measurements in a Helium gas expansion porosimeter. The plugs were also used to acquire permeability values using a digital gas permeameter.
The results show that the outcrop is a tight reservoir, since most levels have low porosity (~3.5% average) and permeability (mostly &lt;0.1md), though higher values (φ~10-15% and K~160md) occur locally. Most levels are classified as hybrid 1 or diagenetic reservoirs, according to Ahr (2008). L1b shows the highest porosity (mostly WP and CH), while the highest permeability is neither related to facies nor the most common porosity, but with certain late diagenetic processes, such as dissolution along stylolites and fracturing. It was concluded that the layers with the greatest reservoir potential exhibit channel porosity as the dominant type and, in a few rare cases, connected vuggy pores are seen in thin-section. In order to create a facies model that honors the geological observations and analysis, it is mandatory to consider the geometry of the carbonate bodies observed in the field. When the defined bodies are introduced and propagated using the modelling software, a better visualization of the reservoir (including potential stratigraphic/diagenetic traps) is achieved. The biostrome bodies often display a lenticular configuration, whereas oolitic bodies display lateral variations/interfingering with coarser/tempestite levels, thus isolating the levels with increased permeability.
Normal industry workflows often do not fully consider geological data and conceptual models, and instead rely heavily on geostatistical propagation of well data. The results obtained indicate that there is an improvement in reservoir understanding with an integrated reservoir characterization and modelling process that accounts for actual depositional and diagenetic trends, as well as the distribution of the sedimentary bodies.