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dc.contributor.authorFlett, Matthew Alexander
dc.contributor.supervisorDr. Geoff Weir

The injection of carbon dioxide (CO2) into saline formations for the purpose of limiting greenhouse gas emissions has been proposed as an alternative to the atmospheric venting of carbon dioxide. In the evaluation process for selecting a potential target saline formation for the disposal of carbon dioxide, flow characterisation of the disposed plume should be undertaken by reservoir simulation of the target formation. The movement of injected carbon dioxide in the saline formation is influenced by many factors including the physics of carbon dioxide at deep formation depths and pressure, physical interactions with formation rock and pore water and variations in the rock flow pathways through changes in formation heterogeneity. This thesis investigates the roles of physical interactions on the disposal of carbon dioxide and the ability to contain the injected gas through evaluation of trapping mechanisms such as dissolution of CO2 in formation water and residual gas trapping through the process of gas-water relative permeability hysteresis. Variable formation heterogeneity is evaluated for its impact on the migration of injected CO2 plume movement and the role of formation heterogeneity in impeding or accelerating the immobilisation of injected carbon dioxide. Multiple reservoir simulation studies were conducted to evaluate, initially, the role of different trapping mechanisms in immobilising the movement of injected carbon dioxide and subsequently, the role of variations in formation rock in the migration and trapping of and injected plume of carbon dioxide. The major simulation study shows that the selection process for identifying appropriate saline formations should not only consider their size and permeability but should also consider their degree of heterogeneity endemic to the formation.A set of reservoir performance metrics were developed for the CO2 disposal projects. The metrics were applied to compare plume migration of injected CO2 (both vertically and laterally) and containment (through dissolution and residual phase trapping) in these studies. The findings demonstrate how formation heterogeneity has a significant impact on the subsurface behaviour of the carbon dioxide. Formation dip influences the rate of migration, with low formation dipping reservoirs having slower rates of vertical migration. Increasing the tortuousity of the migration flow path by either increasing the shale (non-reservoir) content or lengthening the shale baffles in the formation (corresponding to a gradual decrease in reservoir quality), can progressively inhibit the vertical flow of the plume whilst promoting its lateral flow. The increase in the tortuosity of the CO2 migration pathway delays the migration of CO2 and increases the residence time for the CO2 in the formation. Thus, formation heterogeneity impedes the onset of residual gas trapping through hysteresis effects. Ultimately less carbon dioxide is likely to collect under the seal in heterogeneous formations due to increased reservoir contact and long residence times, thereby reducing the risk of seepage to overlying formations.Given sufficient permeability for economic injection of CO2, then low to mid net-to-gross heterogeneous saline formations with low formation dip and lengthy intra-bedded shales are desirable for selection for the geological disposal of CO2. Detailed reservoir characterisation of any potential geological disposal saline formations is required in order to accurately predict the range of outcomes in the long term flow characterisation of injected CO2 into those formations.

dc.publisherCurtin University
dc.subjectgreenhouse gas emissions
dc.subjectsaline formation
dc.subjectcarbon dioxide (CO2)
dc.subjectreservoir simulation
dc.subjectvariable formation heterogeneity
dc.subjectatmospheric venting
dc.subjectphysical interactions
dc.titleSubsurface re-injection of carbon dioxide for greenhouse gas control: influence of formation heterogeneity on reservoir performance
curtin.departmentDept. of Petroleum Engineering
curtin.accessStatusOpen access

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