Abstract The migration architecture of the Gippsland Basin, Australia, is dominated by two highly connected, filled-to-spill fill and spill (fill-spill) chains — the northern chain (gas dominated) and the southern chain (oil dominated) — that extend east–west across the basin and link at its far western nearshore part, forming a convergent chain that then extends onshore. The reservoir units across the basin are sealed by smectite-rich marine claystones that have very high seal potential within the central basin but become less effective toward the basin flanks and onshore. Decreasing top-seal potential along the convergent fill-spill chain onshore has localized the formation of a 25-km-long zone of leakage and seepage; here, leaking hydrocarbons are expressed as gas chimneys, as natural seeps, and as a prominent zone of shallow uranium enrichment. Active seepage, documented by a combination of chimney mapping and water-column geochemical sniffer data, also occurs in several areas offshore — mostly along the basin margins at the conjunction of well-developed migration fairways and zones of failing top and fault seal. Fluid inclusion and migration-modeling data reveal that the first major hydrocarbon charge in the basin, including that into the giant gas fields that dominate the northern fill-spill chain, was oil; this charge appears to have filled the traps to spill point, probably in the Late Miocene. Gas subsequently entered many of these traps in the Pliocene and displaced the oil, pushing it farther along the fill-spill chains. A lack of gas charge into the eastern portion of the southern fill-spill chain preserved the early oil charge along that trend. The integration of basin-scale fluid-flow modeling with assessments of seal integrity, charge history, and leakage-seepage processes provides a powerful, generic, predictive approach for assessing not only the petroleum systems and hydrocarbon prospectivity of a basin but also its ultimate CO 2 geostorage potential.

Abstract The subsurface geological storage of CO 2 is influenced by many variables. Stratigraphic architecture and reservoir heterogeneity primarily affect the migration pathway of CO 2 . Therefore, an understanding of these parameters can assist with devising an injection strategy to maximize the efficiency of the geological storage of CO 2 . An example is presented from the Kingfish field area in the offshore Gippsland Basin, southeastern Australia. The potential injection targets are interbedded sandstones of the Paleocene–Eocene upper Latrobe Group, which are sealed regionally by the Lakes Entrance Formation. Sequence stratigraphy suggests that several packages of sandstone reservoirs exist separated by locally effective, but regionally nonextensive, intraformational seals. Seal capacity analyses indicate that the intraformational seals can retain an average CO 2 column height of around 500 m (1640 ft). Thus, the interbedded siltstones and shales will behave as flow baffles and barriers that will hinder or slow vertical migration, encouraging the CO 2 to migrate laterally, and create localized traps throughout the stratigraphy, which reduces the reliance on the top seal. Numerical simulations demonstrate how these siltstone and shale baffles reduce the effective vertical permeability, thereby creating a more tortuous pathway for CO 2 migration. This increased pathway length enables a greater volume of pore space to be accessed, increasing the potential for residual gas trapping and dissolution of CO 2 to occur along the migration pathway, and may provide more time for geochemical reactions to occur. These effects all increase the potential CO 2 storage capacity and containment security and should be considered when devising injection scenarios to optimize the CO 2 geological storage process.