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|Title:||Simulation of the cumulative impacts of CO2 geological storage and petroleum production on aquifer pressures in the offshore gippsland basin|
|Citation:||International Journal of Greenhouse Gas Control, 2013; 19:310-321|
|Karsten Michael, Mark Bunch, Sunil Varma|
|Abstract:||Geological carbon dioxide storage (GCS) has been identified as an important strategy for reducing greenhouse gas emissions. Due to their potentially large CO₂ storage capacity, deep saline aquifers have been investigated globally with respect to storage suitability, injectivity and potential impact on the environment and other basin resources. The relatively large area of pressure impacts associated with large-scale GCS has been identified previously as an important issue. One aspect of GCS in saline aquifers that has previously not been considered widely in the assessment of injection impacts and storage capacity is the history of regional production-induced underpressuring in many petroleum-producing sedimentary basins. The Latrobe aquifer in the Gippsland Basin in southeastern Australia is a potential candidate for large-scale GCS. The Latrobe Group forms a major freshwater aquifer in the onshore Gippsland Basin and contains hydrocarbon reservoirs in the offshore parts of the basin up to 6000m below the seafloor. The emphasis of the current modelling was to examine the cumulative impacts of CO₂ injection and petroleum production on the regional flow and displacement of formation water. With respect to the Gippsland Basin specifically, the simulations suggest that GCS has the potential to partially reverse the recent trend of water level declines in the onshore area of the Latrobe aquifer, thereby reducing impacts on water resources and the risks of land subsidence. Also, CO₂ injection may provide pressure support for the significantly underpressured petroleum-producing regions in the offshore portion of the Latrobe aquifer. The Latrobe aquifer has adequate storage capacity and injectivity for storing a total of at least 2000MtCO₂, which would be sufficient for storing Victoria's annual CO₂ emissions from large stationary sources for the next 20 years and, most likely, beyond. The radius of increased pressures in response to injecting the required volume of CO₂ in the centre of the basin would be on the order of 20km, if the production-induced pressure decline in the Latrobe aquifer is taken into account. In comparison, injecting the same amount of CO₂ in an unstressed aquifer would result in pressure impacts at a distance of up to 80km from the storage site; hence a significantly larger area would need to be monitored.Generally, the CO₂ injectivity for a pressure-depleted aquifer is likely to be higher than that for a hydrostatically-pressured aquifer, and the difference should be related to the volumes of previous petroleum and associated water production. CO₂ injection and petroleum production operating independently can result in significant over- or underpressuring in a basin, potentially causing land uplift/subsidence or contamination of groundwater. The simulation results in this study suggest that, given the right injection concept, unwanted pressure changes and associated impacts could be significantly reduced when CO₂ injection and petroleum production operated conjunctively.|
|Keywords:||Saline aquifer storage; Basin-scale flow simulations; Gippsland Basin; Pressure management; Area of impact|
|Rights:||Crown copyright © 2013|
|Appears in Collections:||Australian School of Petroleum publications|
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