Geological Evaluation of the Eocene Latrobe Group in the Offshore Gippsland Basin for CO2 Geosequestration
Doctor of Philosophy
University of Adelaide
A geological evaluation of the Eocene Latrobe Group in the offshore Gippsland Basin was carried out to assess the technical feasibility of CO2 geosequestration, which is a practical solution for reducing greenhouse gas emissions to the atmosphere.
The study area is characterised by a regional anticline plunging to the east-south-east with large-scale internal architecture comprising transgressive, retrogradationally stacked stratigraphy that dips gently landward and is unconformably truncated by overlying sealing units. The primary reservoir/aquifer targets for CO2 injection are palaeo-shoreline parallel nearshore sandstone bodies characterised by high porosity and permeability (average ~25% and 100s mD) and good interconnectivity. The key regional sealing unit is the Lakes Entrance Formation, which consists of mudstone and marl capable of sealing large columns of CO2 (~750 m).
A geocellular model was constructed for volumetric estimates and numerical flow simulation of CO2 injection and storage. Rock properties were spatially populated in the model using depositional analogues and geostatistical techniques to represent realistic geological variability.
The proposed strategy for CO2 geosequestration is to inject CO2 outside four-way structural closure to allow up-dip fluid migration to the north then west governed by the structure of regional sealing units. This approach is associated with several advantages including: structural trapping in depleted hydrocarbon fields along the migration path; CO2 migration perpendicular to stratigraphy to retard the rate of up-dip migration; and the leveraging of unconventional trapping mechanisms including residual gas trapping behind the mobile CO2 plume and dissolution of CO2 into formation water. Probabilistic estimates of CO2 capacity utilising the proposed strategy indicate that 1395 – 2575 Mtonnes could be sequestered.
Numerical flow simulation of CO2 injection at 10 Mtonnes/yr for 20 years showed that the proposed strategy was technically feasible with an expected arrival time of CO2 at the first hydrocarbon field along the migration path 20 – 200 years after the end of injection, depending on the level of permeability heterogeneity. The key trapping mechanism was structural trapping in the short term and dissolution of CO2 into formation water in the long term. After 2000 years ~40% of the injected CO2 was dissolved in the formation water and CO2 had not reached the westernmost hydrocarbon field indicating considerable extra capacity.