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Heterogeneity in hydrocarbon reservoirs has significant impact on fluid flow during production and may lead to oil being trapped in low-permeability reservoir compartments.

This is particularly true for producing turbidite fields with significant thin-bedded turbidite (TBT; 3–10 cm [1.2–3.9 in.] sand and silt unit) and very thin-bedded turbidite (VTBT; 1–3 cm [0.4–1.2 in.] sand and silt unit) successions.

The principal geological attributes used to characterize TBT–VTBT include facies and facies associations, sandstone/mudstone ratio, bed geometry, sand connectivity, sediment texture, sedimentary structures, and vertical sequences of bed thickness. Their combination enables definition of four fundamental attribute indices that reflect the reservoir quality of TBT–VTBT successions. The attribute indices are sand connectivity index, sediment textural index, facies ratio index, and facies net-to-gross index.

Twenty TBT and VTBT facies are recognized in cores from North Brae field wells. The combination of results from the application of the attribute indices approach to core data from the field reveals six facies associations (FA), which may also be applicable elsewhere, each characterized by different attribute indices. FA1 has high-to-very-high sand connectivity and textural indices (mature, fine-medium-grained, well-sorted sand). Its core-based porosities and horizontal and vertical permeabilities indicate that it possesses the most favorable reservoir properties. For FA2, a lower sand connectivity index because of extensive mudstone lamination signals poorer quality reservoir features. FA3 and FA4 show moderate attribute indices and mixed reservoir quality facies, whereas more studies are needed to determine the suitability of FA5 and FA6 for potential shale gas exploitation in other areas.

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