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Interferometric Synthetic Aperture Radar (InSAR) data, gathered over the In Salah CO2 storage project in Algeria, provide an early indication that satellite‐based geodetic methods can be effective in monitoring the geological storage of carbon dioxide. An injected mass of 3 million tons of carbon dioxide from one of the first large‐scale carbon sequestration efforts, produces a measurable surface displacement of approximately 5 mm/year. Using geophysical inverse techniques, we are able to infer flow within the reservoir layer and within a seismically detected fracture/fault zone intersecting the reservoir. We find that, if we use the best available elastic Earth model, the fluid flow need only occur in the vicinity of the reservoir layer. However, flow associated with the injection of the carbon dioxide does appear to extend several kilometers laterally within the reservoir, following the fracture/fault zone.

Sleipner is a commercial CO2 storage site in the North Sea with good constraints from monitoring data, but also with some significant uncertainties regarding temperature, pressure and gas/brine behavior. At Sleipner, we have used high-quality repeated seismic and gravimetric surveys for monitoring and calibrating the reservoir uncertainties. To model the CO2 behavior we have used two main approaches: a) traditional reservoir simulations, using black oil and compositional fluid descriptions; and b) invasion percolation simulations, using threshold pressure and fluid density descriptions that assume the dominance of capillary and gravity forces. The key findings from the study are: The invasion percolation simulation gave the best initial match to observed data, leading us to reassess the input assumptions for the black oil and compositional simulations. By taking into account gravity segregation and modifying the reservoir simulation input data, we were able to get a much better match for the black oil and compositional simulations. There is still scope for further optimization and history matching, however, this study has reduced the range of domain variables leading to an improved understanding of the flow processes involved in geological storage of CO2 in saline formations. The study has led us to conclude that we can make realistic and predictive CO2 storage models provided that the site-specific conditions are honored, including reservoir and fluid property characterization. The necessary tight constraints on input parameters are achieved by calibration against monitoring data. Our study illustrates both a rather novel approach to modeling CO2 storage and the need for improved input to conventional simulators. Application of our approach to other CO2 storage sites will help in achieving more realistic understanding of CO2 storage, thereby contributing to the maturation of CO2 storage technology worldwide.

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