The 1st AAPG/EAGE PNG Geosciences Conference, PNG’s Oil and Gas Industry:
Maturing Through Exploration and Production

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A Summary of The Petroleum Distribution and Potential Of PNG


The Papuan Basin of PNG is a major hydrocarbon province with the giant Hides Gas field (1013 MMBOE URR) under production into the PNG LNG Project since 2014 and the Kutubu, Agogo and surrounding Oil Fields under production since 1992 (approx. 870 MMBOE URR) (IHS, 2019). A number of discoveries including the giant Elk/Antelope Field and the P’nyang and Pasca Fields are under development planning. Total discovered resource is estimated at 7 billion boe (IHS, 2019). Mean yet to find oil is estimated at >11 billion boe, suggesting that over half of hydrocarbon endowment of the Papuan Basin has been discovered. These numbers do not include the deep-water offshore part of the basin or other basins north of the PNG thrust belt. Regional Geological mapping of the Oxfordian unconformity across the Northern Australia-East Indonesia Super Gas Province shows the depocentres that coincide with the most productive hydrocarbon provinces from the Carnarvon Basin to the Browse Basin, the Bonaparte Basin and the Papuan Basin with additional depocentres in West Papua and to the south in the Cooper-Eromanga Basin. Interestingly each of these basins is connected to LNG export facilities indicating the scale of the gas resources present. It is apparent that all these basins have a similar stratigraphic development with Triassic to Mid-Jurassic rifting and development of extensive fluvial-deltaic successions followed by development of a passive margin that initially consists of near-shore parallelic and shore face sections that deepens over time into the Lower Cretaceous deep marine section. In the Australian marine basins this transitions from the mid-Cretaceous into carbonate shelf deposition that continues to the present day. The Papuan basin diverges from its Australian counterparts as a result of significant uplift, erosion and non-deposition as a result of the Coral Sea rifting event in the Late Cretaceous to Palaeogene. In PNG carbonate shelf development does occur during the Tertiary and continues today offshore but has been interrupted onshore by the collision tectonics since the Miocene that have given rise to extensive uplift and erosion of the basin depocentre in the PNG foldbelt. Like other Mesozoic basins across the “Northern Australia-East Indonesia Super Gas Province” (Barber and Winterhalder, 2012) the Papuan Basin is overwhelmingly gas prone as a result of mixed terrestrial organic material accumulated in pre-, syn- and post-rift lower delta plain coals in the late Permian to Jurassic. Localised Oxfordian-Kimmeridgian rhomboid syn-rifts, such as the Dampier, Vulcan and PNG foreland basins contain more oil prone source rock material. Exploration activity onshore PNG has been hampered by the difficult logistical challenges that arise due to a harsh environmental landscape. Consequently, 2D seismic is expensive and data quality generally poor and no 3D seismic has been attempted. Surprisingly given the paucity of seismic data the technical success rates from exploration drilling have been high (~40%), but due to the logistics of development this has translated into few commercial fields. Drilling density, measured in wells per 1000 square kilometre, show that the Papuan Basin is 3 times lower than the Carnarvon Basin. Creaming curves defined for the Foldbelt, the Eastern Carbonate Province and the Foreland province suggest that there remains potential in each of these areas for further discoveries with significant volume still likely to be found in the Foldbelt and Eastern Carbonate Trend. Discovery size in the Foreland Area is expected to be smaller than the other areas and unlikely to justify threshold volumes for a stand-along LNG development. These resources may however be useful add-ons to existing LNG developments once ullage is available.