Foinaven is a Palaeocene, turbidite, oil field with subsidiary gas caps. The field comprises several reservoir intervals in an anticline, faulted into six fault panels. Located West of Shetland, off the north coast of Scotland, the field is a subsea development through an FPSO facility. Field development is a mix of depletion, with variable amounts of aquifer support and water injection support. This presentation discusses the interpretation of flow barriers in the main reservoir zone of Panel 0, an 80 m thick, stacked, partially amalgamated channel complex. Five producers are supported by three water injectors, and core data is available in two appraisal wells. Depositional setting for the sequence is of an overall prograding shelf/slope system with stacked, non-amalgamated, base of slope turbidite fans. Reservoir sands comprise channel complexes of various stacking and amalgamation architectures from more distal, distributary fan, lower units to more proximal, base of slope feeder channel, upper units. Individual channel elements, from facies and poroperm trends appear to be ca. 10-20m thick. The reservoirs are dominated by massive, amalgamated sands (no shales), with secondary heterolithic facies of non-amalgamated sands (ca. one metre sands with preserved turbidite shale caps, ca. 10cm), thin-bedded sands (poorer quality, cm-10's cm sand / shales) and shale conglomerates. Shale beds occur between and within the major sand units comprising 'background' hemi-pelagic deposition and slump/slide units. Reservoir quality is good, comprising fine to medium grained sandstones, with typical porosities of 23-30% and permeabilities of 500-2000mD. In Panel 0 pressure breaks observed in development wells (B08) can be related to heterolithic 'shale' package intervals identified in the well logs and correlated to facies in adjacent cored appraisal wells (19-3A). Correlation of pressure baffles and their relationship to key geological surfaces, i.e. channel erosive cuts, and facies associations, and thus to channel position and channel stacking architecture, help define the flow units of the reservoir. Note that only one well pair and one possible correlation is shown and discussed. The derived generic relationships are applied in guiding interpretation of the heterogeneity and flow unit / barrier architecture of the reservoir and population of the reservoir model. It can be seen from 204/19-3A that well log facies are not unique in terms of lithofacies. Interbedded sands and shales (Section 1) can have an identical log character to shale conglomerates (Section 3). Shale conglomerates, typically associated with channel bases, are unlikely to form pressure baffles. While channel bases with shale and slump drapes may form pressure breaks but have a higher risk of being discontinuous. Note that such surfaces may still form flow unit boundaries even if incomplete, as although they will not create a pressure compartment their low transmissibility may still control water sweep. Channel abandonment phases / off-axis marginal settings with non-amalgamated turbidites provide the greatest chance of extensive lateral preservation and thus forming pressure breaks and flow units. Where lithofacies can not be uniquely determined it is important to try and establish where a 'shale' package is in relation to the individual channel, i.e. channel cut or channel abandonment top, and its stacking arrangement.


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