Browsing by Author "Onaneye, Alfred Omololu"

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    Multi-disciplinary 3-D reservoir characterization and flow simulation of Aptian/Albian silicate sandstone reservoirs in Bredasdorp Basin, offshore South Africa
    (Stellenbosch : Stellenbosch University, 2014-12) Onaneye, Alfred Omololu; Mikes, Daniel; Rozendaal, Abraham; Stellenbosch University. Faculty of Science. Dept. of Earth Sciences.
    ENGLISH ABSTRACT: Geological models remain the required input in flow simulators for use by reservoir engineers to simulate performance and optimize oil recovery. The lack of complete subsurface information however, continues to pose a challenge to accurate geological characterisation. A 3-D geologic reservoir model of identified reservoir sand-bodies (WBRED-A, WBRED-B, WBRED-C and WBRED-D) was created to evaluate reservoir fluid-flow performance by way of a systematic workflow that integrates reservoir characterisation, reservoir modelling, upscaling and fluid-flow simulation using a range of data sets. These include: 2-D seismic profiles, well logs, cores, sedimentary logs, and well tests from three exploratory wells. The modelling /approach employed deterministic geological processes in a stochastic framework, hence combining benefits of both deterministic and stochastic modelling methods arranged in nested steps defined primarily by: (1) the creation of a 3-D reservoir model with an anatomy based on concepts of depofacies and their distribution and partitioning, (2) upscaling (i.e. selection of an optimal upscaling method) of the 3-D reservoir model for realistic and representative reservoir anatomy and (3) fluid-flow simulation (i.e. steady state simulation based on assigned two-phase flow parameters of depofacies). The juxtaposing and organisation of observed lithofacies features (sedimentary structures and facies associations) in a down-dip depositional profile allowed for the reconstruction of depositional lithofacies architecture and geometric elements. Six depofacies were recognised (proximal mouth bar, distal mouth bar, delta front, distributary channel, overbank/inter-channel and floodplain/inter-channel deposit), which are broadly grouped into four main lithofacies associations (massive sandstone, interbedded sandstone, claystone, and soft-sediment deformation). Reservoir sandbodies are indicative of a depositional system characterised by a succession of superimposed deltaic cycles which control vertical and horizontal reservoir connectivity. A description of reservoir petrophysics revealed that the WBRED-D presents the lowest average poro-perm results of the four units investigated. Moderate to excellent poro-perm relationship is confirmed within the two main reservoir types-distributary channel-fill and inter-channel reservoirs for WBRED-B, WBRED-C and WBRED-D. Effective porosity values in WBRED [A-D], ranges from 0.14 to 0.35 indicating moderate to very good reservoir quality, while permeability values ranges from 6mD to 602mD and is attributed to well sorted sands. The key control of effective porosity and permeability is the continuity and connectivity of the channel sands and inter-channel deposits. Besides, average water saturation values in the units range from 12% to 69% representative of a reservoir system considered satisfactory for hydrocarbon production. Ten stratigraphic flow units are mapped within WBRED [A-D] and define predictable hydraulic conductivity, storage and porosity of reservoir sandbodies. Flow unit 6 and 10 are identified as possible flow barriers. Upscaling results of WBRED-C show that to preserve reservoir connectivity, the upscaling of the inter-channel deposits proved important. Permeability and porosity upscaling using arithmetic mean and flow-based methods proved effective in generating an excellent agreement between upscaled and fine grid model for WBRED-C. Upscaling describes the replacement of a number of heterogeneous fine grid-blocks with one equivalent coarse homogeneous grid block. The impact of two-phase flow parameters, as modelled for three depofacies characterizing WBRED-C against cumulative production, reveal that relative permeability/wettability is the dominant two-phase flow property. Vertical and lateral facies heterogeneity governs successful mobile oil and gas productivity. To these ends, results of this study are of particular significance to Bredasdorp Basin where geological complexity exists and will assist in planning enhanced oil recovery strategies.