Hydrocarbon potential characterisation and kinetic models for source rocks in the Bonaparte and Gippsland Basins, Australia

A detailed geochemical study was performed on potential source rocks in the Bonaparte Basin (Australian North West Shelf) and the Gippsland Basin (Australian southeastern margin). Both of these basins have been the focus of attention for extensive exploration activity that has led to the discovery of numerous economic gas and oil accumulations. The hydrocarbon generation characteristics of potential source rocks in each of these two basins remain uncertain. This study involved the integration of several techniques and approaches, such as Rock-Eval pyrolysis and open-system pyrolysis-gas chromatography (Py-GC) to assess the petroleum potential and to define petroleum organo-facies. Pyrolysis experiments under open-system conditions were applied to simulate the timing of hydrocarbon formation for a range of source rocks in these Australian basins. The bulk kinetics of petroleum formation were determined by pyrolysis experiments under closed-system conditions to predict and provide insights on phase behaviour and compositional properties of generated hydrocarbons. Two case studies were carried out within the Bonaparte Basin (the Vulcan Sub-basin and the Laminaria High), from which 61 and 14 source rock samples were analysed, respectively. Py-GC results indicate that the overall molecular compositions of the organic matter preserved in the Bonaparte Basin do not differ significantly between the Upper Jurassic and Lower Cretaceous kerogens. The low abundance of phenolic compounds in these kerogens indicates a contribution from marine material. In contrast, the Middle Jurassic Plover Formation is more enriched in straight chain hydrocarbons with a higher carbon-number range and exhibits higher phenolic and aromatic content, suggesting high input of terrigenous organic matter in the source facies. Additionally, there is a significant variation in petroleum-type organofacies, which ranges from gas/condensates to Paraffinic-Naphthenic-Aromatic. This variability in organic richness, petroleum potential and organic facies type is interpreted to be a direct result of the varied sedimentary environments in which these facies were deposited, reflecting the transition from fluvial-deltaic during the Middle Jurassic, to open marine settings during the Late Jurassic to Early Cretaceous in response to fault activity and regional subsidence. Similarly, bulk and compositional kinetic analyses reveal variable degrees of heterogeneity in thermal stability and composition. The compositional kinetic model predictions also indicate that under geological conditions, a greater proportion (~80%) of the hydrocarbons were generated as oil. Counterintuitively, however, our results indicate that the marine Lower Cretaceous Echuca Shoals Formation has greater ability to form gas (43%) than the other source rocks, due to inertinite dominating its maceral assemblage. The kinetic dataset developed from the Laminaria High area was incorporated into a 3D petroleum system model using the Schlumberger PetroMod 3D software packages to investigate the hydrocarbon charge history of the Laminaria High-Nancar Trough region. The modelling results indicate that most of the potential structures could have received oil charge from the Nancar Trough kitchen, where the Middle Jurassic source rocks are mature with respect to the oil generation window. When buried deep enough to reach sufficient thermal maturity, the Lower Cretaceous source rocks can provide additional sources for oils with a marine affinity. The onset of hydrocarbon generation in the Nancar Trough commenced during the Early Cretaceous, and during the mid to late Cenozoic for the Laminaria High, in response to elevated heat flow during the syn-rifting phase. The second and main phase of hydrocarbon generation and expulsion occurred in the mid-Eocene and continued until the present day, being controlled by the deposition of the thick Cenozoic carbonate shelf, which resulted in deep burial of Mesozoic source rocks. This latter phase of expulsion coincided with the reactivation of fault-bounded traps, which implies that some or all of the initially trapped hydrocarbons could escape out of charged structures. Having excluded the majority of wells drilled either off structure or with trap integrity issues such as inadequate reservoir and/or seal, vertical leakage from faults that are open at the present-day is the most likely explanation for structures that are now completely or partially emptied of hydrocarbons. It has been long suggested that the Latrobe Group coals are the main contributors to hydrocarbon accumulations in the Gippsland Basin. Results from the analysis of 91 source rock samples used in this study show that shales and coaly shales, rather than coal, have more potential for liquid hydrocarbon generation. No substantial variability in kinetic parameters was observed in shales and coaly shales containing Type II/III kerogens, which suggests that the Upper Cretaceous to Paleocene source rocks can be considered as a continuous but organically-heterogeneous facies, deposited in fluvio-deltaic to marginal marine settings. However, four representative samples show that there is a noticeable difference in terms of the compositional models that predict variable potential for gas (17-32%) versus oil generation (68-83%). Kinetic differences are also translated into the physical properties, where the highest GORs (213-1443 Sm3/Sm3) were measured for the Paleocene (L. Balmei biozone) carbonaceous shales, and the lowest ratios (120- 175Sm3/Sm3) were measured for the Turonian (P. Mawsonii biozone) shales. The incorporation of the developed kinetics into 3D petroleum system models that account for different kinetic characteristics would enable pre-drill prediction of petroleum quality and refinement of the filling history of the Gippsland Basin.