Integrating Gravity and Seismic Methods with Petroleum System Modelling to Assess Exploration Risk Factors in Offshore Lamu Basin, Kenya

Abstract

Lamu basin is located in South Eastern Kenya and covers onshore (about 85 000 km2) and offshore (about 170 000 km2) with a total area of about 255 000 km2. Carbonates, shales, and sandstones constitute the sediments of the area. Tectonic movements, which brought about Gondwana's breaking up, control the region’s geology. East Africa’s potential for hydrocarbon is indicated by the significant oil and gas discoveries in Mozambique and Tanzania and the heavy oil deposits in Madagascar’s conjugate margin. Unfortunately, many of the drilled wells in the Lamu Basin turned dry save for gas and oil shows from a few of the Lamu Basin's twenty (20) drilled exploration wells. This study, therefore, assessed exploration risk factors of the Lamu shallow offshore by evaluating the basin’s evolution and analyzing the development of the petroleum system using one dimension petroleum system modelling integrated with gravity and seismic geophysical methods. Major and minor subsurface structural features have been delineated through filtering, processing, and regionally interpreting gravity Isostacy data. The features like the ridges, troughs, and faults mainly trending in the North West- South East direction are discernable from the regional anomaly map. The developed models show the basement highs and lows with a possibility of anticlinal and synclinal structures and thick sedimentary successions likely to represent good hydrocarbon source kitchens. Appropriate seismic attributes have been leveraged to extract subsurface properties from the seismic data and have guided the interpretation to delineate closed structures and potential subsurface traps. Reservoir zones delineated through petrophysics and rock physics analyses were characterized. The resulting petrophysical properties indicate a good range of reservoir characteristics: low shale volume (0.07-0.26), low water saturation (0.23-0.56), high effective porosity (0.12- 0.25), and a net thickness (18.95 m- 43.224 m). The rock physics cross-plot models delineated the reservoir lithology and discriminated the fluid content. The probable zones discriminated include the hydrocarbon-bearing zone with low water saturation, gamma radiation, and high porosity compared to brine-saturated sand and shale zones. Gassmann fluid substitution was used to calculate the fluid effect on elastic rock properties from the rock frame properties. The behaviour of clean reservoir zone saturation scenarios resulting from the brine, oil, and gas fluid substitution models was measured. The values indicate that fluid substitution has a greater effect on compressional velocity than on shear velocity and density () significantly decreased when hydrocarbons replaced water saturation in the wells. Shear wave velocity (Vs) indicated a slight change in all the wells. Petroleum system modelling was applied to evaluate the geological conditions necessary for a successful charge by reconstructing the burial, thermal, and maturity histories. The models were calibrated using geochemical analysis's measured Vitrinite Reflectance and generative properties. Calculations from the simulated models were correlated with the measured values, from which inferences were made. From the upper cretaceous maturity maps, the results seem to favour near coastal regions where average total organic carbon is about 1.4 wt%, Vitrinite reflectance is more than 0.5%, transformation ratio is more than 10%, and temperatures range from 80 0c to 160 0c. Greater uncertainty rests on the source rock's presence and viability tending toward the deep offshore. Combining gravity and seismic methods for regional structural interpretation, petrophysics and rock physics for reservoir delineation and characterization, and petroleum system modelling for source rock characterization improved the understanding of the occurrence of the petroleum system elements and processes necessary for hydrocarbon accumulation. Appropriate points where wells may be drilled with reduced exploration risk have been suggested.