Aim: This study presents the log analysis results of a log suite comprising gamma ray (GR), resistivity (LLD), neutron (PHIN), density (RHOB) logs and a 3D seismic interpretation of Tymot field located in the southwestern offshore of Niger delta. This study focuses essentially on reserves estimation of hydrocarbon bearing sands. Well data were used in the identification of reservoirs and determination of petrophysical parameters and hydrocarbon presence. Three horizons that corresponded to selected well tops were mapped after well-to-seismic tie. Structural depth maps were created from the mapped horizons. The structural style is dominated by widely spaced simple rollover anticline bounded by growth faults, and this includes down-to-basin faults, antithetic faults and synthetic faults. The petrophysical values – the porosity, net-to-gross, water saturation, hydrocarbon saturation that were calculated yielding  an average porosity value  of 0.23, water saturation of 0.32 and an average net-to-gross value of 0.62. Three horizons H1, H2 and H3 were mapped. The three horizons marked the tops of reservoir sands and provide the structures for hydrocarbon accumulation. Hydrocarbon in-place was estimated. The total hydrocarbon proven reserves for the mapped horizons H1, H2, and H3 were estimated to be 39.04MMBO of oil and 166.13BCF for sand E.

This study integrated lithofacies, foraminifera and seismic data to develop a sequence stratigraphic approach to hydrocarbon exploration for Chiadu field. The application of lithostratigraphic approach led to correlation of diachronous lithofacies and wrongly defined an approximately accurate extent of the reservoirs. This study necessitated the use of sequence stratigraphic framework for the purpose of establishing chronostratigraphic concept and facies prediction. The genetic sequence model of Galloway was adopted for sequence stratigraphic interpretation of the field. The structural style is dominated by closely spaced simple rollover anticline bounded by growth faults, and this includes down-to-basin listric faults, collapsed crest structures, antithetic and synthetic faults. Result of foraminifera analysis showed that the analyzed interval is very rich in calcareous benthic but decreased in planktic and arenaceous benthic foraminifera. Lithofacies analysis shows that the continental lithofacies is made up of dominantly sand with thin bands of shales, while Agbada lithofacies is made up of alternating intervals of sandstones and shales to very thick shale unit in the lower section. The facies identified using log motifs and their stacking patterns include braided fluvial, crevasse splay, fluvial point bar, distributary/tidal channels, intertidal, subtidal and storm-dominated shelf facies. The presence of water depth indicator fossils confirmed the water depths of coastal deltaic, shallow inner neritic, inner neritic, middle neritic and outer neritic were based largely on the presence of environmentally restricted benthic foraminifera species.Integration of lithofacies and biofacies data suggests depositional environments ranging from coastal deltaic to outer neritic environment. Sequence stratigraphic analysis identified three complete sequences with accompanying system tracts over the interval 7922.3-14,856.34 ft. The transgressive system tracts (TSTs) within these sequences are dominated by marine shales and thin sands. Reservoir quality sands are found in highstand system tract and shelfal lowstand system tract, while the shales of TSTs and HSTs form potential source and seal units. The delineation and correlation of sequence stratigraphic surfaces enable us to build an approximate chronostratigraphic framework, which is essential for determining facies relationships. Reacquisition and/or processing should be done to improve seismic data quality for better imaging and interpretation/ mapping, especially hydrocarbon prospect at deeper horizon.

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