Figure 1. Typical relative permeability curve for CO,-brine systems, drainage and imbibition Figure 2. Typical capillary pressure curve for CO,-brine systems, drainage and imbibition For the purpose of analytical description of the residual trapping mechanism during CO) storage in the saline aquifers, two phenomena are considered; injection of CO, into the subsurface formations and the behaviour of the CO, after injection. Then, further development of the model is obtained by adding a dip angle to the formation layers. *based on weight %. Table 1. Fluid properties at laboratory condition Ranges of fluid properties for the CO,-brine systems are different for various reservoir conditions but the overall ranges are reported in the literature. CO, and brine densities and viscosities are strongly dependent on the OS Ti i ee ae Ee Se ee ee n this study, two sets of fluids are chosen for experiments at laboratory conditions. The fluid selection is based on scaling analysis. This means that density difference and viscosity ratio are chosen in the range of CO>-brine conditions at the reservoir. The second fluid set has the same scaling ratios but the difference is the wettability behaviour to the porous material. The viscosities of the fluid sets are measured by Brookfield LVDV-I+Pro viscometer, and are measured at atmospheric pressure and 22 °C (Tablel). The DV-II+Pro consist of a rotating spindle that is placed in the chamber full of the testing fluid. After calibrating the spring, the viscous drag of the fluid against the spindle is measured by the spring deflection. Table 2. Fluid properties of CO, and brine taken from Nordbotten et al. (2005) Figure 3. Set-up picture Figure 5. Schematic of the relative permeability set-up Figure 4. Separator and glass beads chamber Figure 9. Contact angle measurements, fluid set 1 Figure 6. A droplet of heptane in glycerol and water mixture, fluid set 1 Figure 7. A droplet of dodecane in glycerol and water mixture, fluid set 2 Figure 10. Contact angle measurements, fluid set 2 Figure 11. Contact angle measurements for two sets of fluids Figure 12. Amott cell imbibition cell results Table 4. Stabilized pressure for each injection rate The results are in good agreement with the correlation given by Rump and Gupta (1975) that is for estimating the absolute permeability in glass bead packs. Table 5. Experimental conditions Table 6. Absolute permeability measurements Figure 13. Pressure difference for different rate in injection The absolute permeability is used as an adjusting parameter in simulations by the Sendra software to match the experimental pressure drop observed in the relative permeability measurements. The absolute permeability calculation is based on injection of wetting fluid of fluid set 1 by different injection rates. The pressure drop created by the injection is plotted in Figure 13. The stabilized pressure in each step gives a point in the pressure versus rate plot, and by use of the Darcy equation absolute permeability is obtained. Figure 14. Pressure difference versus injection rate Table 7. Experiments in this study 3.2.1 Results for Fluid Set 1 Figure15. Drainage test, history matching of differential pressure, injection rate of 0.1 cc/min Figure19. Imbibition test, history matching of differential pressure, injection rate of 0.1 cc/min Figure17. Drainage test, injection rate=0.1 cc/min Figure 16. Drainage test, history matching of water production, injection rate of 0.1 cc/min Figure 20. Imbibition test, history matching of water production, injection rate of 0.1 cc/min Figure 18. Drainage tests, effect of injection rate Table 8. History matching data - fluid set 1 3.2.2 Results for Fluid Set 2 Figure 21. Imbibition tests, effects of injection rate Figure 22. Imbibition tests, effects of injection rate — logarithmic Figure 25. Drainage test, injection rate=0.1 cc/min Figure 23. Drainage test, history matching of differential pressure, injection rate=0.1 cc/min Figure 27. Imbibition tests, effect of injection rate Figure 24. Drainage test, history matching of water production, injection rate=0.1 cc/min Figure 26. Drainage tests, injection rate=0.1 cc/min Figure 28. Imbibition tests, effect of injection rate- logarithmic Table 9. History matching data - fluid set 2 4. Discussions The nature of flooding brine with CO, and imbibition process afterwards makes it to be difficult to control. Very low viscosity of CO, and high density difference results in unfavourable mobility ratio. Viscous fingering seems to be an evitable process in such systems. Some former studies are done at conditions that lead to onset of viscous fingering in displacement tests. Peters and Flock (1981) have presented a dimensionless instability number to estimate the onset of viscous fingering in immiscible displacement processes: Table 10. History matching data, eliminating effect of rate, modified relative permeability Figure 29. Relative permeability to CO», effect of imbibition rate and wettability Figure 30. Swi, effect of drainage rate and wettability calculated for the experiments. Figure 32 shows the residual CO) saturation obtained from the experiment and is plotted against capillary number. Former simulation studies of Utsira brine formation of Sleipner and Viking formation (Canadian brine formation) revealed the range of capillary number using inter-block velocity in simulation model (Soroush et al., 2013). Figure 31. Residual COz, effect of imbibition rate and wettability Figure 32. Residual CO, saturation effect of imbibition rate and wettability Figure 33. Modified relative permeability, fluid set 1 Figure 35. Drainage relative permeability, fluid set 1 and 2, effect of wettability Figure 36. Imbibition relative permeability, fluid set | and 2, effect of wettability Figure 34. Modified relative permeability, fluid set 2
