ABSTRACT

Reliable estimates of the hydraulic properties, such as porosity and permeability, are essential for construction of robust dynamic reservoir models. A variable density, non-isothermal, hydrodynamic model of the Gippsland Basin is being developed to simulate impacts of CO2, injection into the Latrobe Formation on the aquifer pressures and migration of the saline formation water. For this study relationships between porosity and permeability derived from conventional core analysis and mercury injection capillary pressure tests, and the shale volume derived from gamma logs have been used. Shale volume has also been derived from inversion of 3D seismic data using constrained sparse spike inversion to facilitate distribution of porosity and permeability in 3D space. Formation water density distribution has been estimated based on salinity interpreted from self potential logs to assist in model calibration.

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