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Organic-rich “hot shales” of the Lower Silurian Tanezzuft formation are regarded as the principal source rocks for Palaeozoic oil fields in North Africa. Thus, the evolution of the petroleum system of the Murzuq basin, Southern Libya, is largely controlled by the lateral extension, thickness, organic geochemical characteristics and maturity of the Tanezzuft hot shale. In this context the petroleum generation potential of Tanezzuft hot shale samples from the Murzuq basin was studied by geochemical and petrological methods and a numerical modelling study was performed taking into account the structural evolution and thermal history of this basin[1]. Core and cutting samples of the Lower Silurian interval were selected from two wells of the northern and central part of Murzuq basin. High TOC contents and HI-values from Rock-Eval pyrolysis indicate organic-rich source rocks with moderately hydrogen-rich organic matter, classified as Type II kerogen, at different maturity levels. To enhance the geochemical source rock characterisation as well as to predict hydrocarbon phases and generation [2], bulk and phase kinetics were performed by open system- and closed system pyrolysis. The bulk kinetic analysis confirmed the early to mid mature level for the northern part and immature to early mature level for the central part of the basin. The activation energy distribution for the samples is characterised by a smooth bell-shaped, Gaussian-like distribution, typical of marine type II kerogen. Temperature and timing of petroleum generation were calculated using activation energies and frequency factors with a linear geological heating rate of 3.3 K/my [2]. The compositional kinetic analysis was performed to assess the composition of generated petroleum. The results show that 75 % of hydrocarbons is generated as oil and 25 % as gas fraction. The gas-oil ratio was calculated and found to increase with increasing the maturity. [1] Belaid, A., B. Krooss and R. Littke, 2009, Thermal history and source rock characterization of a Palaeozoic section in the Awbari Trough, Murzuq Basin, SW Libya, Marine and Petroleum Geology, doi: doi:10.1016/j.marpetgeo.2009.06.006. [2] di Primio, R., Horsfield, B., 2006, From petroleum type organofacies to hydrocarbon phase prediction. AAPG Bulletin, v. 90, no. 7, p.1031 - 1058

Combining compositional predicting PhaseKinetcs with state of the art migration methods such as mapbased ray-tracing, pressure driven Darcy-flow and capillary pressure driven invasion percolation, allows to take into account the influence of petroleum composition and its phase behavior even during hydrocarbon generation, migration and accumulation. In combination with these migration models different adsorption methods and different critical saturations as well as secondary cracking processes inside and outside the source rock and different API calculation methods are applied. The question is: which minor processes can be calibrated independently and can therefore be validated? Or is the system over-determined and minor processes are just helpful to calibrate and manipulate the system? In the present study area, the geochemical composition of the Egret source rock and the accumulated quantities in the Jeanne d’Arc basin are well known. Therefore, we can test and quantify the processes, which affect the fluids during primary and secondary migration. Chemical properties of the source rock have been investigated based on 38 samples and PhaseKinetics were determined. The first step was the evaluation of a heat-flow history through time, using different crustal- and stretching-models. The heat-flow maps were then calibrated based on available vitrinite reflectance, bottom hole temperature and apatite fission track data. In a second step different fluid flow simulators were combined with different types of kinetic data. Additionally, we tested the influence of different equations of states (EOS), namely Peng-Robinson and the Soave-Redlich-Kwong EOS, on the ensuing phase behavior and physical properties (e.g. API gravity) of the migrating fluids in the models. We demonstrate also that some other minor processes are not completely taken into account such as the real nature of the hysteresis effect of drainage and imbibition for capillary pressure vs. saturation and that real interfacial tension maps for both gas and oil should be used instead of two constant IFT values. However, defining all minor processes in detail does not always lead to more accurate results due to the generally high uncertainties in basin modeling, which causes also a very poor determination of losses during primary and secondary migration. However, to reproduce and calibrate the general pattern of generation, migration and accumulation these minor processes can be used very well.