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The recently discovered super-giant Mamba field is located in the Area 4 deep water block, offshore northern Mozambique and hosts over 80 TCF of natural Gas in place within Paleogene deepwater deposits. The Coral reservoir unit represents the Lower Eocene depositional sequence of the Mamba field and is formed by sand-rich turbidite channel and lobe complexes of proximal deepwater fan accumulations. Generally, the coarse and massive reservoir sandstones are extraordinarily thick, clean and homogeneous compared to similar deep water plays, e.g. Gulf of Mexico, West Africa. High quality 3D seismic and data from three wells, including wire line logs and over 100m of core, indicate that the excellent reservoir quality of the Mamba complex can be related to the presence of strong, deep water bottom currents that influenced the deposition of gravity-flows. An integrated sedimentological approach on multiple scales, which comprises detailed sedimentological core descriptions, seismic stratigraphy and seismic attribute analysis, provides new insights into the depositional processes and the reservoir architecture of a fascinating deepwater play. The depositional model suggests Lower Eocene bottom currents crossing the sand rich gravity flows perpendicularly. This results in significant flow-stripping and deviation of the turbulent, fine-grained suspension cloud. The process accumulates the greatest amount of fines on the leeward part of the channel complex and creates unilateral drift-mounds instead of bi-lateral levee complexes. This leads to relatively mud-free facies types and a characteristic low angle offset stacking of the amalgamated channel complexes. However, dependent on associated flowvelocities and grain sizes, also the depositional lobes show exceptionally good reservoir properties, characteristic geometries and stacking patterns. The integrated and process-oriented approach allowed detailed mapping and modeling of the reservoir bodies, which permits the prediction of reservoir quality and optimization of the field development.

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Core data and logs - wireline and while-drilling - were processed and integrated with a sedimentological model to provide consistent log-facies classification and petrophysical characterization as input to a 3D geological model of an off-shore deep-water turbidite reservoir. The studied reservoir belongs to a channel system, and consists of channel sands cut into background shaly deposits, and of thin beds that can be ascribed to levee and crevasse-splays. Chaotic slump deposits are also found locally. A complex fault system, related to mud-diapirs, subdivides the reservoir into hydraulically separated blocks, thus resulting in multiple hydrocarbon accumulations. Log curves from five different wells were environmentally corrected, depth-shifted and calibrated at the reservoir scale in order to ensure the overall consistency of log recordings. They were used as input to a quantitative log evaluation process that resulted in the computation of the volumes of mineralogical components (sand, silt, shale) and effective porosity along the wells. The computed curves were in turn statistically processed (cluster analysis) and compared with the sedimentological description of cores, to provide a classification of the reservoir into five log-facies, each with a well-defined sedimentological meaning. The results of NMR log interpretations and a detailed thin layer analysis carried out on high-resolution resistivity curves - available on different subsets of the studied wells - were also integrated, eventually leading to a thorough petrophysical characterization (distributions of porosity, permeability, irreducible water saturation) of each log-facies. Finally, the full-field sedimentological model - derived from 3D seismic data - and the above described petrophysical characterization provided the input for a 3D geostatistical reservoir model that was built with an object-based approach. The statistics calculated from a large number of realizations allowed a probabilistic quantification of the OHIP distribution for use as an input for future field development scenarios. Introduction Hydrocarbon production from ‘easily characterized and produced’ reservoirs has slowly declined worldwide in the last decades: as a consequence, exploration and production targets progressively shifted towards more challenging environments and/or more ‘difficult’ reservoirs. Turbidite deposits in deep and ultra-deep water offshore are a typical example. Besides their overall architectural complexity (amalgamated channels, channel-levee systems, channel-lobe systems), some of these deposits include heterolithic facies consisting of thin, cm- or mm-sized, alternating horizons of sandstone, siltstone and mudstones, which deserve accurate petrophysical characterization. This paper describes a facies reservoir characterization workflow whose objective is the integration of core data and log curves with different vertical resolutions. The workflow was applied to a deep-water turbidite reservoir. The resulting characterization proved to be a useful guide in the construction of the 3D geocellular model. In the beginning, the reservoir structural setting and the sedimentological conceptual model are presented. Next, the integrated petrophysical characterization workflow is presented: the quantitative interpretation of conventional logs, the interpretation of NMR logs, and a Thin Layer Analysis carried out on high resolution resistivity curves are first discussed; then, the log-facies classification and characterization relying on log and sedimentological interpretation is discussed. Finally, the construction of the 3D geological model is presented.

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