Abstract
The discovery of Kudu gas-condensate accumulation and recent wells drilled offshore in the Namibian margin have successfully de-risked source rock presence and maturity (Hodgson and Intawong, 2013). Both the acquisition of an extensive 2D seismic dataset in 2012 and a recently acquired cross-border survey 2015 off¬shore Namibia and South Africa have facilitated the evaluation of source rock maturity distribution for the Early Aptian and Cenomanian-Turonian source rocks along this margin (Figure 1). Conventionally, we have no tools to interrogate heat flow and geothermal gradient in an undrilled basin and have to rely on extrapolation from offset wells, imposing models on a structural interpretation of the basin margin. Near-surface geotherm estimation derived from seismic measurement of the thickness of a gas hydrate accumulation with respect to the water depth found in the Luderitz Basin has been employed as a preliminary approach for the initial evaluation of source rock maturity in this margin (Hodgson et al., 2014). The approach remains an under-utilised seismic method for initial evaluation of source rock maturity in undrilled basins. Public domain heatflow data (Davies, 2013), knowledge of subsurface thermal conductivity and crustal heat production can be used to predict geotherms and thus temperature spatially away from control points. Petroleum system modelling is the most efficient way of systematically investigating the thermal maturity of sedimentary basins. This can be tailored to available constraints, which in the case of the deepwater Luderitz Basin include shallow temperature data derived from BSR (60°C/km in the upper 500 mbsf) and heatflow measurements (40-60 mW/m2; Davies 2013). The uppermost sediments have a thermal conductivity of < 1 W/m/K, which is 2-3 times lower than deeper (compacted) clastic sediments. That would provide an average geothermal gradient of 30°C/km as previously proposed by Hodgson et al. (2014).
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