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

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An Overview of Geochemical Exploration of Hydrocarbons in Papuan Basin, Papua New Guinea


Papua New Guinea has five sedimentary basins of which only one (Papuan basin) is a producing basin. Exploration efforts in the larger Papuan basin has been in progress for decades. The larger Papuan basin is characterized by varied geology, age, tectonics and depositional environments. Hydrocarbon shows, oil and gas discoveries in commercial, sub-commercial and non-commercial quantities have been made. Petroleum production is limited to the highlands of Papuan fold belt at present. Exploration for hydrocarbon in Papuan basin is challenging due to structural complexity, poor−fair quality seismic and limited dataset. The purpose of this study is to evaluate source rock and hydrocarbon geochemical data available to improve our understanding of burial history, maturity, timing of hydrocarbon generation and migration. This will help constrain opportunities to develop new petroleum charge models for geological features across the Papuan basin and to lower exploration risk. The present-day oil accumulations in the Papuan fold belt fields such as Kutubu (Iagifu, Hedinia) and Gobe are thought to be derived from clay-rich, Jurassic marine source rocks containing mixed algal−terrigeneous organic matter that were deposited in oxic environments possibly along shelf slopes. The co-reservoired natural gases suggest a substantial gas input from the basinal facies further to the north/northwest, reflecting relatively more marine-influence, high maturity and cracking-genesis attributes. The basinal facies of Jurassic source rocks may have only contributed highly mature gas-condensate to the current deposits (Hides, Juha, P’nyang), however, implying a loss of the earlier-generated black oils. Published data for geochemical characteristics of recovered oils, oil extracts, fluid inclusion oils, condensates, and oil/gas seeps suggest two major families of hydrocarbons occurring in both the western and eastern Papuan basin regions. Hydrocarbons in the western region (Papuan foreland) were likely sourced from Late Triassic and Late Jurassic clay-rich marine source rocks containing terrigeneous higher plant derived organic matter (OM) deposited in a sub-oxic to oxic environments. Five oil families and two charge events have been modelled based on the geochemical data. Hydrocarbons distributed in the eastern region were generated from Cretaceous or younger marine carbonate source rocks deposited in an anoxic to sub-oxic conditions. Biomarker characteristics of solid bitumen extracts from Late Cretaceous Pale and Subu sandstones indicate two separate oil charges. One (family A) is from a strongly terrestrially influenced marine source rock that may well be Jurassic in age whereas the other (family B) originated from a marine source rock with a calcareous component, with a high proportion of prokaryotic OM and a low proportion of terrestrial higher plant inputs. The Mesozoic rift basin of Gulf of Papua (GoP) contain more gas than oil because the Middle-Upper Jurassic or Lower Cretaceous marine source rocks have mixed gas-oil potential. The quality of source rocks are fair to good, typically averaging 150−300 mg HC/g rock HI and 1−2% TOC, with good average thickness of 2−3km. The Jurassic source rocks in the GoP have generated petroleum in two discrete pulses, the first at the end of the Cretaceous and the second at the end of Cenozoic where the end-Cretaceous pulse was volumetrically more important. Mesozoic hydrocarbons draining into Tertiary reef traps were limited because reefs were not present however, the gas-condensates accumulation in Tertiary reefal carbonates were derived from the depleted Jurassic source rocks during the Late Cenozoic generation and migration. Numerous studies on hydrocarbon characteristics from the larger Papuan basin indicate that the hydrocarbons are not homogeneous and display variabilities. The variabilities are likely to be a function of lateral and vertical changes in both organic facies and source rock maturity.