Geochemical interpretation of partially filled hydrocarbon traps in the nearshore Gippsland Basin
Nick Hoffman A and James Preston BA 3D-GEO
B The CarbonNet Project
The APPEA Journal 54(1) 107-118 https://doi.org/10.1071/AJ13013
Published: 2014
Abstract
This study aims to analyse the relative importance of competing processes in determining the distribution of liquid and gaseous hydrocarbon accumulations in the nearshore Gippsland Basin. These processes include primary source/charge factors such as kerogen type and maturity at the time of expulsion, fractionation processes during migration, and secondary alteration effects such as biodegradation and/or water-washing in the presence of a strong low-salinity water-wedge that has pushed out 20–40 km from the coastline during Quaternary time.
The authors find that small accumulations of liquid petroleum predominate west of Emperor, Snapper, and Bream. These small accumulations show evidence of primary charges of wet-gas, and various stages of in-reservoir alteration. Compared to liquids in the Central Deep and in the basal oil-legs of the giant wet-gas fields at Snapper and Marlin, wax contents are low, and API gravities are high, close to the Emperor-Bream line, but then decrease westwards towards the coastal region. Oil bubble-point pressures decrease westwards (despite shallower burial than the Bream, Snapper, and Marlin fields, further offshore), due to increasing under-saturation with respect to dissolved gas.
The authors note that the dominance of gas in the Barracouta Field is probably due to strong recharge with unaltered wet gas but that dry gas in the Golden Beach Field suggests biogenic methane, as proven for the Baleen gasfield by carbon isotopes. The authors infer that the presence or absence of thin oil-legs in the Barracouta, Snapper, Marlin and Bream wet gas fields reflects a balance of water-washing and fresh charge.
Residual oil shows below the Dolphin and Perch OWCs, and a lost column at Amberjack–1, demonstrate volume reduction following peak charge. The authors, therefore, conclude that observed underfill of structures is generally a result of in-reservoir processes post-charge, rather than a deficiency of charge or seal.
Nick Hoffman has over 25 years’ international oil industry experience, including substantial time with BP in Europe, BHP in Australia and worldwide. For much of the past decade, he was a director of a private geoscience consulting house—3D-GEO, specialising in basin evaluation and reservoir studies. He joined CarbonNet in 2011 as part of the start-up technical team to lead the geoscience evaluation over CarbonNet’s portfolio of nearshore CO2 sequestration targets. He is an expert geophysicist, sequence stratigrapher, and basin geologist with significant experience interpreting depositional environments, structural evolution, and reservoir distribution from 3D and 2D seismic, and from well data. Nick integrates a wide range of basin data to understand present-day and palaeo-fluid flow and the distribution of fluids in the basin. nick.hoffman@dsdbi.vic.gov.au |
James Preston received his BSc (Hons) degree in geology from the University of Birmingham, and MSc from the University of Leicester, in the UK. He worked as a petroleum geologist at BHP Billiton Petroleum in Melbourne from 1988–91, then as a specialist in petroleum geochemistry from 1991–2002. From 2002–7, he worked as an independent consultant (director of Exploration Geochem Consulting P/L), as Senior Petroleum Systems Analyst at Woodside Energy in Perth from 2007–8, and since 2009 as Manager for Petroleum Geochemistry and Basin Modelling for 3D-GEO P/L, based in Melbourne. In all of these roles, he provided expertise in the geochemical evaluation of petroleum systems to numerous exploration projects in Australia and internationally. Member: The Petroleum Exploration Society of Australia (PESA) and the Petroleum Exploration Society of Great Britain (PESGB). jim@3d-geo.com |
