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2D modelling of Petroleum Prospectivity in Offshore Frontier Basins using PetroModTM: Capel and Faust Basins, Lord Howe Rise

Thomas James Morgan, 2013

Honours Degree of Bachelor of Science (Petroleum Geology and Geophysics)

Australian School of Petroleum

The University of Adelaide


There is one truth: there is a finite amount of hydrocarbons left to discover. Oil production began
onshore in the late twentieth century and had progressively been moving offshore into deeper, more
technically challenging areas. So far, the vast majority of offshore oil fields are located in shallow
water (White et al., 2003). With increasing demand, declining production from mature oilfields,
favourable market conditions and emerging technologies, petroleum exploration has been
increasingly focused on the poorly understood deep-water frontier basins.

Geoscience Australia (GA) provided 23 2D seismic lines from the 2006-2007 GA-302 and 3 2D lines
from the 1998 GA-206 survey. Papers from Colwell et al (2010), Hashimoto et al (2011), Higgins et al
(2011) and Funnell and Stagpoole (2011) provided interpreted migration pathways and intrusion
models that formed the basis of research for this project.

Multiple sensitivities were run on Schlumberger's PetroMod 2D software package. They were
designed to test how varying total organic carbon (TOC) percentage, fault parameters and the
addition of an intrusion can affect hydrocarbon migration, leakage and accumulation volume.
The simulations run validate migration pathway interpretations made by Colwell et al (2010) and that
hydrocarbon migration could a driving force for their distribution. TOC content is inherently linked to
hydrocarbon leakage through the seal. The presence of seismic character that suggests fluid
migration may provide clues to hydrocarbon volume by setting the lower limit required for fluid flow.
The inclusion of an igneous intrusion produced mixed results. Its formation depth determined whether
its presence had a positive or negative effect on the petroleum system. If it occurred within already
mature source rocks it both reduced hydrocarbon accumulation volume by 7-8% and increased
vapour liquid ration by 5-18%. If contained in an immature source rock, it resulted in an increase of up
to 3% in total accumulated hydrocarbons.

Across the study, closed fault systems were favourable for hydrocarbon accumulations. However, due
to restricted well control broad assumptions of lithology have been made (packages up to 1 km thick)
and no fault-bounded reservoirs exist. In practice, this would not be the case.
Deep well control with TOC, seal and reservoir properties is required before an accurate 2D model
can be constructed. Before these uncertainties are overcome the risk of exploration is high, but if
successful, the reward potentially enormous (White et al., 2003).

Australian School of Petroleum



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