SignificanceThe Late Ordovician mass extinction (LOME) terminated one of the greatest biodiversity radiations in Earth history eliminating ∼85% of marine animals, and it is coincident with the first major glaciation of the Phanerozoic. To evaluate LOME origins, we use uranium isotopes from marine limestones as a proxy for global-ocean redox conditions. Our results provide evidence of an abrupt global-ocean anoxic event coincident with the LOME onset and its continuation after the biologic recovery, through peak glaciation, and the following early Silurian deglaciation. These results also provide evidence for widespread ocean anoxia initiating and continuing during icehouse conditions.

Atlantis is a giant oil field with challenges that require a multi-disciplinary and phased approach to reservoir development. Initial development focused on the better-imaged extra-salt segment of the structure after eight appraisal penetrations revealed over a 1,500 ft oil column contained in several high quality thick pay sands. Signals of the reservoir complexity that would be associated with Atlantis were seen from the beginning. The early wells found variable fluid contacts, fluid compositional variations, large previously undetected faults, and what turned out to be perched water. Development drilling continued while the facilities were being fabricated. The drilling results strengthened confidence that there were large inplace resources but heightened concerns about complexity. In response, the development plan was modified to include ocean-bottom-seismic, downhole-flow-control completions, and a second production drill center. Initial reservoir performance revealed sub-seismic baffles that resulted in lower stabilized well productivity and more complex compartmentalization than expected. Integrated analyses of static and dynamic data enabled the integrated team to demonstrate that recovery per well was similar to pre-drill expectation and modification to the development plan would allow sustained production growth. Challenges going forward include appraisal and development of remaining segments of the field to effectively grow production and extend production plateau, and efficient operation of the wells, subsea architecture and production facilities.

The Gorgon gas field lies 70 km west of Barrow Island in 200 m of water. The field is jointly owned by ChevronTexaco Australia, Shell Development Australia and Mobil Exploration and Producing Australia and has certified proven hydrocarbon gas reserves of 272.69 Giga cubic metres (Gm3) (9.63 trillion cubic feet (Tcf)). Carbon dioxide (CO2) comprises about 14 mole % of the raw gas resource.The Gorgon joint venture is committed to the responsible management of greenhouse gas emissions and this ongoing commitment is reflected in the plan to inject Gorgon CO2 into the Dupuy Formation beneath Barrow Island, unless it is cost prohibitive or technically unfeasible.This paper summarises the Phase 1 assessment made by the Western Australian Department of Industry and Resources (DoIR) into the technical feasibility of the Gorgon CO2 storage project. Technical feasibility is defined as the ability to inject CO2 in a manner that has acceptable safety, environmental and reservoir risks based on assessments made by both the Gorgon joint venture and regulatory bodies.DoIR and ChevronTexaco Australia agreed to regularly review the technical work for due diligence purposes. To assist in the assessment, DoIR engaged the services of Curtin University. The Phase 1 review was completed in June 2003 and provided technical assurance on the feasibility of CO2 storage beneath Barrow Island. This provided one of the criteria for the WA State Government’s decision to grant in-principle access to Barrow Island for the project.The Phase 1 review provided a comparative risk analysis and recommendations related to improving the sub-surface definition of the earth model, further assessment of seal and fault integrity, injectivity, near-well bore reactions and CO2 surveillance and monitoring technologies. Key DoIR recommendations included the need for additional geological data and a long-term monitoring strategy for reservoir management and contingency planning. The second Phase of due diligence commenced in February 2004.

Atlantis is a giant oil field with challenges that require a multi-disciplinary and phased approach to reservoir development. Initial development focused on the better-imaged extra-salt segment of the structure after eight appraisal penetrations revealed over a 1,500 ft oil column contained in several high quality thick pay sands. Signals of the reservoir complexity that would be associated with Atlantis were seen from the beginning. The early wells found variable fluid contacts, fluid compositional variations, large previously undetected faults, and what turned out to be perched water. Development drilling continued while the facilities were being fabricated. The drilling results strengthened confidence that there were large inplace resources but heightened concerns about complexity. In response, the development plan was modified to include ocean-bottom-seismic, downhole-flow-control completions, and a second production drill center. Initial reservoir performance revealed sub-seismic baffles that resulted in lower stabilized well productivity and more complex compartmentalization than expected. Integrated analyses of static and dynamic data enabled the integrated team to demonstrate that recovery per well was similar to pre-drill expectation and modification to the development plan would allow sustained production growth. Challenges going forward include appraisal and development of remaining segments of the field to effectively grow production and extend production plateau, and efficient operation of the wells, subsea architecture and production facilities.