Understanding fluid/fluid and rock/fluid interactions in a reservoir are required to evaluate CO2 storage potential and safety. This paper examines the effect of salinity of reservoir brine on CO2 storage and the level of salinity best for CO2 storage. Relative permeability imbibition and drainage curves were generated to further understand the interaction between CO2 and brine in a reservoir.

A core flooding set up was built to replicate reservoir conditions of the Farnsworth Unit (FWU) in Texas, USA. The research involved three reservoir pay zone rocks obtained from depths of about 7687ft that were pieced together to undergo core flooding at 4400psi and a temperature of 168°F. During the 6 tests conducted the core was flooded with supercritical CO2 and brine of salinities 3000ppm, 6000ppm and 35000ppm to generate relative permeability curves to represent imbibition and drainage. Imbibition and drainage relative permeability curves are generated from the co-injection of CO2 and brine of varying salinity at different ratios and volumes.

After analyses of the imbibition and drainage relative permeability curves for the different salinities it is seen that the relative permeability curves looked very similar, in that all three relative permeability curves looked the same for imbibition tests and also for all the drainage tests regardless of the brine salinity. The volume of CO2 stored in the core was almost the same for the six different tests. From this research it can be concluded that CO2 storage, at least for these particular reservoir rocks, is not affected significantly by the salinity of the formation brine. It appears that the interaction between supercritical CO2 and different salinities of brine is not substantially different for the same rock sample.

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