© 2014 EAGE www.firstbreak.org 103 special topic first break volume 32, March 2014 Modelling/Interpretation 1 Spectrum ASA, Woking, UK. 2 University of Manchester, Manchester, UK. * Corresponding Author, E-mail: neil.hodgson@spectrumasa.com A seismic tool to reduce source maturity risk in unexplored basins Neil Hodgson 1* , Anongporn Intawong 1 , Karyna Rodriguez 1 and Mads Huuse 2 present a pow- erful new seismic method for estimating heat flow in undrilled basins. R ecent exploration drilling has derisked the presence and maturity of Aptian source rock in the northern and southern basins offshore Namibia, yet the deep- water of the central Luderitz Basin remains undrilled. While modern regional seismic demonstrates the presence of the Aptian source rock in this basin, conventionally we have no tools to interrogate heat flow in an undrilled basin and have to resort to closeology, trendology and even structural- analogy to derive comfort for source maturity. However, geotherm estimation derived from the pres- ence of bottom-simulating reflections (BSR’s) is a powerful, under-utilized seismic method for evaluating source rock maturity in undrilled basins, and is applied here to the Luderitz basin. A seismically derived geothermal gradient map conflated with new depth mapping of the source rock in this deepwater basin provides a method for defining an oil generative window – the ‘Goldilocks Zone’, and constraining source rock maturity (or ‘effectiveness’) risk. This technique is not exclusive to Namibia, and its applica- tion in many other deepwater clastic basins provides a tool for stimulating explorers to create a constrained geotherm and source rock atlas of countless undrilled frontier basins around the world. Setting the scene As revealed in a previous First Break article (Hodgson and Intawong, FB Dec 2013), recent exploration wells operated by HRT in Namibia during 2012 and 2013 have significantly reduced Aptian source risk in the north (South Walvis Basin: Wingat-1 and Murombe-1 wells) and south (Orange River Basin: Moosehead-1 well) deepwater offshore Namibia. Mature Aptian source was reported in all three wells and light oil was recovered from the Wingat-1 well. The distribu- tion of these basins and wells is shown on Figure 1. A brief discussion of the geological history of the forma- tion of these basins was presented previously (Hodgson and Intawong, FB Dec 2013). We note here only that the sedimentology and basin-fill of these three basins is different, reflecting variations in sediment supply volumes, shelf uplift and destabilization episodes. Any or all of these factors could affect the localized heat flow within the basin, yielding source rock maturity ‘cold spots’ – even at an equivalent depth to that seen in wells drilled in offset (adjacent) basins. There is no better method for confidently evaluating heat-flow and geothermal gradient than carefully measured borehole temperatures. However, in an undrilled basin explorers are left relying on extrapolation to offset wells (closeology – even if these wells lie in inappropriate settings), evaluating structural form of the basin margin and imposing models so constrained (trendology – interpretation reliant) and modelling syn-rift vs. post-rift heat flows from other margins which are more fully explored (structural-analogy). All of these methods can help to some degree; however, they do leave uncertainty on basin modelling constrained by such assumptive models, which translates inevitably into residual exploration risk. Figure 1 Spectrum dataset, basin distribution and location of the wells dis- cussed in this article.