ORGANIC GEOCHEMISTRY OF THE LOWER SILURIAN TANEZZUFT FORMATION AND BIOMARKER CHARACTERISTICS OF CRUDE OILS FROM THE GHADAMES BASIN, LIBYA

The Ghadames Basin of NW Libya contains more than 10 B brls oil-equivalent in Palaeozoic siliciclastic reservoirs which are charged by organic-rich "hot shales" in the Lower Silurian (Rhuddanian) Tanezzuft Formation. Geochemical analysis of 85 shale samples and ten oils from three fields (NC2, NC4 and NC7) in the central and northern part of the basin provides a robust description of the Tanezzuft - Mamuniyat/Acacus petroleum system in this region, and of the associated source facies and oil families. The shale samples underwent total organic carbon (TOC) analysis and Rock-Eval pyrolysis, and the ten crude oil samples were analysed by gas chromatography - flame ionization detection (GC-FID) and GC-mass spectrometry (GC-MS) of the saturated and aromatic hydrocarbon fractions, accompanied by stable carbon isotopic analysis. Organic matter ranges from Type II to mixed Type II/III kerogen with varying oil and gas generation potential in the early to main stages of the oil generation window. The analysed oils are characterised by low sulphur, nickel and vanadium contents, and relatively high API gravity (34.9-46.8 degrees API). Biomarkers suggest that they were generated from marine shales containing abundant Type II to mixed Type II/III kerogen deposited in mildly anoxic - suboxic conditions with a dominance of C-29 over C-27 or C-28 steranes, indicative of a source rich in brown algae and cyanobacteria. Their close stratigraphic association and biomarker characteristics support a Tanezzuft "hot shales" source for the Mamuniyat and Acacus oils in the three fields. Maturity-related parameters based on terpanes, steranes, aromatic hydrocarbons and low molecular-weight hydrocarbons, suggest generation from marine shales in the early to peak oil-generation window. The ZE3-NC7, A19-NC7 and A20 NC7 oils from the NC7 oil field are significantly more mature than those from the NC2 and NC4 fields. This indicates a difference in expulsion timing and may be related to the presence of two "hot shales" or to fault-triggered vertical migration preceding and during the Neogene.