Thermal History and Potential of Hydrocarbon Generated from Jurassic to Early Cretaceous Source Rocks in the Malita Graben, Northern Bonaparte Basin, Australia
- 1 Key Laboratory of Tectonics and Petroleum Resources, China University of Geosciences, MOE, Wuhan, China
- 2 Key Laboratory of Tectonics and Petroleum Resources, China University of Geosciences, MOE, Wuhan, China
- 3 Key Laboratory of Tectonics and Petroleum Resources, China University of Geosciences, MOE, Wuhan, China
- 4 Department of Earth Science and Environment, Faculty of Science, University of Mahajanga, Mahajanga, Madagascar
Abstract
The Malita Graben is located in the northern Bonaparte Basin, between the Sahul Platform to the northwest and the Petrel Sub-basin and Darwin Shelf to the south. The wells Beluga 1, Heron 1, Evans Shoal 1, Evans Shoal 2 and Seismic Line N11805 are selected to determine the thermal history and potential of hydrocarbon generated from the Plover, Elang, Frigate Shale (Cleia and Flamingo), and Echuca Shoals formations source rocks. The modeling was performed by using Basin Mod 1-D and 2-D techniques. The model results show that the geothermal gradients range from 3.05 to 4.05 ° C/100 m with an average of 3.75 ° C/100 m and present day heat flow values from 46.23 to 61.99 mW/m 2 with an average of 56.29 mW/m 2 . The highest geothermal gradient and present-day heat flow values occurred on a terrace north of the Malita Graben. These most likely indicate that hot fluids are currently variably migrating into this structure. The lower geothermal gradient and heat flow values have been modeled in the southeast sites in the well Beluga 1. The northern Bonaparte Basin experienced several deformation phases including lithospheric thinning; hence, heat flow is expected to vary over the geological history of the basin. The higher paleo-heat flow values changing from 83.54 to 112.01 mW/m 2 with an average of 101.71 mW/m 2 during Jurassic rift event (syn-rift) were sufficient for source rocks maturation and hydrocarbon generation during Cretaceous post-breakup sequence (post-rift) in the study area. The Tuatara (Upper Frigate Shale) Formation source rock with type II & III kerogen dominantly showing mixed oil- and gas-prone, and Plover Formation with type III and gas prone have never reached the peak mature oil window in the well Beluga 1. This area indicates that the maturity of source rocks is low and considered to be from poor-to-good organic richness with poor-to-fair potential for hydrocarbons generation. The post mature Cleia (Lower Frigate Shale) and Echuca Shoals formations source rocks in the well Evans Shoal 1 and an early mature oil window Echuca Shoals formation source rock in the well Evans Shoal 2, characterized by type III kerogen dominantly showing gasprone are a fair-to-very good source richness with poor potential for hydrocarbons generation. The low to high maturity of Echuca Shoals and Petrel (Frigate Shale) formations source rocks in the well Heron 1, Plover Formation source rock in the Evans Shoal 1 well, and Cleia (Lower Frigate Shale) and Plover formations in the well Evans Shoal 2, showing gas-prone with type III and II & III kerogens predominantly, have reached the late mature oil and wet gas generation stages at present day. These last five formations source rocks are seen from poor-to-very good organic richness with poor-to-very good potential for hydrocarbons generation in the Malita Graben.
- Preston, J.C. and Edwards, D.S. (2000) The Petroleum Geochemistry of Oils and Source Rocks from the Northern Bonaparte Basin, Offshore Northern Australia. Australian Petroleum Production Exploration Association Journal, 1, 257-282.
- Abbassi, S., George, S.C., Edwards, D.S., di Primio, R., Horsfield, B. and Volk, H. (2015) On the Filling and Leakage of Petroleum from Traps in the Laminaria High Region of the Northern Bonaparte Basin, Australia. Marine and Petroleum Geology, 59, 91-113. http://dx.doi.org/10.1016/j.marpetgeo.2014.07.030
- Ambrose, G.J. (2004) The Ongoing Search for Oil in the Timor Sea, Australia. In: Ellis, G.K., Baillie, P.W. and Munson, T.J., Eds., Timor Sea Petroleum Geoscience, Proceedings of the Timor Sea Symposium, Darwin, Northern Territory, 19-20 June 2003, 2-22. Northern Territory Geological Survey, Special Publication 1.
- Edwards, D.S., Boreham, C.J., Zumberge, J.E., Hope, J.M., Kennard, J.M. and Summons, R.E. (2006) Hydrocarbon Families of the Australian North West Shelf: A Regional Synthesis of the Bulk, Molecular and Isotopic Composition of Oils and Gases. AAPG International Conference and Exhibition, Perth.
- Geary, G. (2008) Farmin Opportunity Presentation NT/P68 & Amp; WA-361-P. MEO Australia Limited, PESA Farmin Seminar.
- Labutis, V.R., Ruddock, A.D. and Calcraft, A.P. (1998) Stratigraphy of the Southern Sahul Platform. APPEA Journal, 1, 115-136.
- Shuster, M.W., Eaton, S., Wakefield, L.L. and Kloosterman, H.J. (1998) Neogene Tectonics, Greater Timor Sea, Offshore Australia: Implications for Trap Risk. The APPEA Journal, 1, 351-379.
- Cadman, S.J. and Temple, P.R. (2004) Bonaparte Basin, NT, WA, AC & JPDA, Australian Petroleum Accumulations Report 5. 2nd Edition, Geoscience Australia, Canberra.
- Pickard, G.L. (1964) Descriptive Physical Oceanography: An Introduction. Macmillan, New York.
- Hardenbol, J., Thierry, J., Farley, M.B., Jacquin, T., de Graciansky, P.C. and Vail, P. (1998) Mesozoic and Cenozoic Sequence Chronostratigraphic Framework of European Basins. In: Graciansky, P.C., et al., Eds., Mesozoic and Cenozoic Sequence Stratigraphy of European Basins, SEPM Special Publication 60, Tulsa, Charts 1-8, 3-13.
- Haq, B.U. and Al-Qahtani, A.M. (2005) Phanerozoic Cycles of Sea-Level Change on the Arabian Platform. GeoArabia, 2, 127-160.
- Haq, B.U. and S.R. Shutter. (2008) A Chronology of Paleozoic Sea-Level Changes. Science, 322, 64-68. http://dx.doi.org/10.1126/science.1161648