Physical and chemical effects of CO2 storage in saline aquifers of the southern North Sea
One of the most promising mitigation strategies for greenhouse gas accumulation in the atmosphere is carbon capture and storage (CCS). Deep saline aquifers are seen as the most efficient carbon dioxide (CO2) storage sites, mainly because of their vast size and worldwide distribution. Injecting CO2 into brine filled media will cause a physical and chemical disequilibrium in the formation. This PhD thesis documents the investigation of some of the resulting effects which occur at the beginning of the injection, during the injection period and millions of years after injection. When CO2 is injected into a brine filled reservoir, large amounts of in situ brine will be displaced away from the injection well. This causes a pressure increase in the vicinity of the well which may compromise the injection process. The simulation of this pressure increase was performed with the black-oil simulator Eclipse10 (Schlumberger) while using a number of recent formulas to predict the mutual dissolution and the fluid properties of CO2 and brine. The results show that the pressure increase can exceed the maximum sustainable pore pressure and will cause fracturing of the reservoir formation. The pore pressure increase is dependent on parameters such as temperature and salinity because they change the fluid properties of the CO2 and brine, but also the capability of the fluids to dissolve mutually. The mutual dissolution has generally a pressure reducing effect although its impact is regarded to be overestimated. This is mainly because reservoir engineering software cannot simulate the shock front realistically. Undulations, which appear on the injection pressure profile are not a result of model instabilities but can either be related to enhanced mutual dissolution due to grid effects, or to the software which may overestimate or underestimate the pressure and dissolution. A detailed investigation of those undulations is vital for the interpretation of the injection pressure. High fluid pressure can be an important parameter for the estimation of the CO2 storage capacity of saline aquifers such as the offshore Bunter Sandstone Formation, in the UK southern North Sea. Based on fluid pressure, the 1 storage capacity was calculated using the ECLIPSE compositional simulation package and a simple analytical equation. The estimated storage capacity is 6.55 to 7.17 Gt of CO2 calculated with the analytical and the numerical approach respectively. By comparing the results, the differences are relatively moderate and therefore the application of the numerical simulator is not regarded as necessary. This is mainly due to the effective pressure flow which prevents pressure accumulations underneath the cap rock. Although the CO2 storage capacity of the Bunter Sandstone Formation remains high, a previous survey, which was not based on fluid pressure, calculated a storage capacity approximately twice as high as the results presented here. In theory, due to the increase in CO2 concentration, CO2 bearing carbonate minerals could precipitate when CO2 is injected into an aquifer such as the Rotliegend aquifer in the southern North Sea. Geochemical models often predict a relatively rapid growth of carbonate minerals as the most secure form of long term engineered CO2 storage. But validation of model-results remains difficult due to the long periods of time involved. Natural analogue studies can bridge the gap between experiments and real-world storage. The Fizzy field, a southern North Sea (UK) gas accumulation with a high natural CO2 content (c. 50%) provides an ideal opportunity to study the long term effect of CO2 related mineral reaction. However all such reservoirs contain ‘normal’ diagenetic dolomite, so that distinguishing sequestration related dolomite is a challenge. CO2 was stepwise extracted from dolomite from both the Fizzy field and the Orwell Rotliegend sandstone in order to reveal any zonation of the crystals which could be related to enhanced dolomite precipitation due to the high CO2 concentration. According to the method between 0 and 22 % of the dolomite in the Fizzy field precipitated due to the high CO2 concentration. Therefore, between 0 and 19 % of the CO2, which is related to the relatively recent high CO2 concentration, is ‘trapped’ in the ‘sequestration dolomite’. The wide range of this estimate is mainly related to rock heterogeneity.