Numerical Simulation Model of Geological Storage of Carbon Dioxide in Onshore Gippsland Basin, Victoria
- Ahmed Tawfiq Buali (Saudi Aramco) | Mohammed Hussain Alali | Mustafa Radhi Alzaid (U. of Adelaide) | Mark Alexander Bunch (CO2CRC) | Saju Menacherry
- Document ID
- Society of Petroleum Engineers
- SPE European Formation Damage Conference, 7-10 June, Noordwijk, The Netherlands
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 5.1.5 Geologic Modeling, 4.3.4 Scale, 5.1.1 Exploration, Development, Structural Geology, 1.8 Formation Damage, 5.10.1 CO2 Capture and Sequestration, 5.2 Reservoir Fluid Dynamics, 5.4 Enhanced Recovery, 5.5 Reservoir Simulation, 5.4.2 Gas Injection Methods, 5.2.1 Phase Behavior and PVT Measurements, 5.8.8 Gas-condensate reservoirs, 2.2.2 Perforating, 6.5.7 Climate Change
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Carbon dioxide sequestration within the subsurface is an emerging field of research to mitigate the problem of increasing concentrations of atmospheric CO2. The onshore/nearshore Gippsland Basin in the state of Victoria, SE Australia, contains deep saline formations that have been identified as potential targets for CO2 storage. Intensive and careful examinations are to be carried out to evaluate these targets. Numerical simulations presented in this study, which were developed using ECLIPSE software, have been designed to investigate certain parameters that influence CO2 behaviour within the subsurface structures. Analysis of results from these simulations will ultimately aid the evaluation of the Gippsland Basin as a suitable prospect for CO2 storage.
Parameters of interest are the ratio of vertical to horizontal permeability, injection rate and the location/depth of perforation. Each one was varied based on a typical range. A 30-year period of CO2 injection followed by a 70-year monitoring period was used as the timeframe for each simulation run. Results of this study indicate that high values of vertical to horizontal permeability are favourable from a trapping efficiency point-of-view. However, they are not appealing from a containment perspective because they enhance buoyant migration of CO2 towards the top seal resulting in a high possibility that ultimate containment will be lost. With respect to injection rate, altering the injection rate does not have apparent effects on trapping efficiencies, namely storage by dissolution and residual gas saturation trapping. Although high values are preferable for dealing with an increased storage volume of CO2, a critical point has to be emphasized. Simulation results suggest that high reservoir injectivity rates cause CO2 to travel faster under buoyancy towards cap rock. Low injection rate decreases the storage volume of CO2.
Therefore, a prudent design of injection rate is critical in order to optimise these counterbalancing factors. Additionally, perforation of the lowest section of the reservoir maximises trapping and containment efficiency as far as the injection rate is not compromised. Further emphasis should be placed on improving the resolution, accuracy and thus, the reliability of the geological model as it will directly impact numerical simulation results.
Many studies have been conducted to investigate feasible solutions that can mitigate the risk associated with increasing concentrations of atmospheric CO2. Sequestration of CO2 within deep saline geological formations, has been examined and accepted globally as one of the potential solutions with most promise. The Gippsland basin in Australia is under ongoing study and evaluation for the purpose of CO2 storage.
The Gippsland basin is located in the eastern part of the state of Victoria (Figure 1). It is a rift-basin that trends east-west (Gibson-Poole et al., 2006). The structural and stratigraphic properties are believed to be similar; continuous and broadly similar for both onshore and offshore parts (Chiupka, 1996). According to Bunch et al. (2009), the onshore part occupies around 30% of the total area of basin, which is almost 16,000 km2. The offshore part, thus, covers an area of approximately 40,000 km2. Prolific oil and gas reservoirs occur within the Latrobe Group and are located within the offshore part of the basin; the onshore basin has not been as prospective, providing reasonable explanation for why there are few data available and little exploration research conducted onshore.
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