Charge Histories of Petroleum Reservoirs in the Gippsland and Taranaki Basins — Evidence From the Analysis of Oil Inclusions and Crude Oils H. Volk 1 , S.C. George 1 , M. Lisk 1 , S.D. Killops 2 , M. Ahmed 1 and R.A. Quezada 1 ABSTRACT Two case studies from the Blackback (Gippsland Basin) and the McKee oilfields (Taranaki Basin) demonstrate the potential of the Molecular Composition of Inclusions (MCI) technique to provide detailed charge histories of petroleum reservoirs. In Blackback-2, source and maturity-related differences between a fluid inclusion oil (FIO) and the MDT oil from the main sandstone reservoir interval in the Eocene Latrobe Group indicate a two-phase filling history. A first charge of oil derived from a marine source rock at a maturity of about 0.6 - 0.7% vitrinite reflectance equivalent (VRE) was partly biodegraded and trapped as inclusions. A second charge was sourced once the fluvial and coastal deposits of the Latrobe Group reached the upper oil window (VRE≈1.1%). This volumetrically more important oil charge diluted the first charge of marine oil. This result is of great significance because it provides the best evidence yet of a generative marine source rock in the Gippsland Basin that is capable of producing oil columns. Two FIOs from Toetoe-2 and a crude oil from Toetoe-2D (McKee oilfield, siliciclastic reservoir rocks of the Eocene McKee Formation) are similar, but differ slightly from a crude oil from Toetoe-1A, indicating some reservoir compartmentalisation. However, within the Toetoe-2 and –2D samples there are some subtle differences in the biomarker distributions which indicate that an early petroleum charge, still preserved in the FIOs, has been diluted by petroleum from a somewhat more coaly source rock facies. In particular, the greater abundance of tricyclic terpanes in the FIOs suggests an early diagenetic influence of marine, saline water followed by a reworking of organic matter by halophilic bacteria, consistent with early generation from a marine-influenced coal. The similarity of the MCI data and the overall similarity of these data compared to the production oils gives confidence in the applicability of the MCI technique in areas where there are more major geochemical differences between inclusion and crude oils, such as at the Blackback oilfield. INTRODUCTION Petroleum reservoirs are often charged by oil that has been expelled from different source rocks over a considerable maturity range. Over geological time, different oils in a petroleum reservoir tend to form a homogeneous mixture (England et al. 1987). In addition, early oil charges may be displaced by subsequent gas charges or mixed with subsequent oil charges, or may be altered by biodegradation or water-washing prior to later oil charge. All these processes blur geochemical differences and often make it difficult to reconstruct the detailed charge history of a petroleum reservoir based on the analysis of recovered oils alone. The geochemical analysis of oil-bearing fluid inclusions offers an opportunity to obtain information on the composition of petroleum during an earlier stage of the fill history. Oil inclusions are encapsulations of palaeo-oil that are commonly formed in diagenetic cements and in healed fractures cross-cutting detrital grains and cements in petroleum reservoirs. Their size ranges commonly from sub-micron to ca. 40 μm in diameter, and they protect the geochemical composition of oil at the time of trapping from subsequent processes such as biodegradation, water-washing, displacement or mixing. Numerous geochemical studies have shown source and maturity differences between fluid inclusion oils (FIOs) and crude oils (e.g. Karlsen et al. 1993; George et al. 1997a, b; Isaksen et al. 1998). Most of these studies have indicated a lower maturity for the FIOs compared to associated crude oils. Therefore it is likely that oil inclusions are mainly trapping oil from a first charge of petroleum. The Molecular Composition of Inclusions (MCI) technique allows high quality geochemical data to be obtained from fluid inclusion oils, as a standardised sample work-up procedure and rigorous testing against system blanks rules out the possibility of background contamination. In this paper, the potential of the MCI technique to identify and characterise oil charge histories will be outlined using case studies in the Gippsland Basin (Blackback oilfield) and the Taranaki Basin (McKee oilfield). GEOLOGICAL SETTING AND SAMPLES The reservoirs are the siliciclastic Eocene sediments of the Latrobe Group and the McKee Formation for the Blackback and the McKee oilfields, respectively. For both oilfields a terrestrial source is likely (e.g. Moore et al. 1992; Cook 1988; Killops et al. 1994). In addition, palaeogeographic reconstructions show that these areas were adjacent to each other until ca. 80 Ma ago, when rifting in the Tasman Sea began to separate the basins (e.g. Mutter et al. 1985; King 2000). Therefore it is particularly interesting to compare charge histories on each side of the Tasman Sea, as the depositional environment and the palaeo-latitudes in which source and reservoir rocks were deposited are very similar in the Gippsland and Taranaki Basins. Gippsland Basin The Gippsland Basin is a major hydrocarbon province extending on-shore from Gippsland/Victoria into the shelf area of the Northern Platform (Figure 1). Whereas gas fields dominate in the near-shore areas, there is a trend towards liquid hydrocarbon occurrences in the more offshore regions. All oil and gas fields are believed to be sourced from terrestrial source rocks within the Latrobe formation (Moore et. al. 1992). The Blackback/ Terakihi oilfield (Vic/P24) is the most offshore oilfield in the Gippsland Basin (Figure 1). Details of the exploration background of the Blackback oilfield can be found in Gross (1993). In the discovery well (Hapuku-1), a 44 m gross oil leg was discovered in Paleocene sandstones below the top of the Latrobe Group unconformity. The age of this unconformity increases towards the south-east, from where a marine transgression shifted the palaeo-shoreline towards the north-west (Moore et al. 1992). Therefore, there is a greater chance of finding marine source rocks in the south-eastern deep water part area of the Gippsland Basin. At present only a few wells have been drilled further to the south-east, and recent bidding for new exploration permits in the deep water part area of the Gippsland Basin makes geochemical investigations in the deep-water part of the oilfield particularly interesting. A FIO was extracted from quartz grains of a sub-arkosic sandstone core sample in the current oil zone in Blackback-2 (2,842.3 mRT; GOI = 7.8%) and was compared to currently reservoired oil (MDT run #2, 2,841.5 m) from a similar interval in the same well (George et al. 1998a). PESA Eastern Australasian Basins Symposium Melbourne, Vic, 25 - 28 November 2001 413 1. CSIRO Petroleum, PO Box 136, North Ryde NSW 1670. 2. Institute of Geological & Nuclear Sciences, PO Box 30368, Lower Hutt, New Zealand.