|dc.description.abstract||CO2 injection in geologic formations (hydrocarbon reservoirs as well as aquifers) is increasingly considered as a method for increasing oil recovery and, at the same time, storing CO2 in these formations to reduce the CO2 emissions, which are considered to be the main cause responsible for global warming or the greenhouse phenomenon. Among many parameters significantly impacting the flow and distribution of CO2 in the formations is relative permeability (KrCO2).
The protocols being used to measure CO2 relative permeability are facing a lot of challenges and problems. In this study, an assessment package tool has been designed and applied in order to verify the protocols and data resulted from CO2 relative permeability experiments published, with recommendations to avoid errors, all that to prospectively help in determining lab measurements which need to be defined, and thus getting reliable CO2 relative permeability data to be used for obtaining accurate prediction of the flow properties to CO2 through (CGS) or (EOR). Moreover, introducing some vital notices whereby the CO2 relative permeability curves could be read and interpreted correctly was an additional work which has been done.
Another issue is that the capillary properties like wettability, IFT and viscosity are considered as the main factors controlling the shape of CO2 relative permeability curve and subsequently its value; however, it is found that any set of rock samples, even extracted from the same formation or from different formations with the same rock type and developing the same capillary properties as well, will produce different CO2 relative permeability curves. This phenomenon had been attributed to rock pore structure or quality, no details of the physics has been described in producing variant CO2 relative permeability curves for the set of samples assumed. In this study, we introduced an interpretation of how the rock internal structure or quality leads to producing variant CO2 relative permeability curves, and it was presented as an upgraded concept called ‘pore and throat distributions’. This new concept has been verified using a set of pore-network models with variant pore and throat distributions. Using theoretical modelling, rather than the empirical or experimental one, was inevitable as to avoid the side effects of the interactions1 (among the CO2, brine and rock contents) on CO2 relative permeability, and also to put aside the effect of other capillary properties mentioned. Going back to Darcy’s law, the CO2 relative permeability is a decisive parameter that controls the CO2 injection rate, but what should be mentioned here is that Darcy’s law just introduces the KrCO2 relative permeability as a term which affects CO2 injection rate and never goes beyond this term to parameters or factors controlling the KrCO2 value and investigates their impact on CO2 injection rate. In this study and by using KrCO2 data published and a real aquifer model we found that the normal pore and throat distributions with similar connection (a new concept introduced before) produced the best injection rates comparing with other cases of abnormal distributions.
The difference among the relative permeability of CO2 and other gases, like methane (CH4) and Ethane (C2H6), has also been studied using a theoretical model. The results illustrated that there was no difference among the relative permeabilities related to CO2 and other gases (CH4, C2H6).
Finally, the wettability distribution concept has been introduced as a factor controlling the magnitude of CO2 endpoint relative permeability for rock samples having the same rock and capillary properties. Some differences between the systems of gas-oil and CO2-Brine, in terms of interfacial tension, have been interpreted depending on the notion of free and adherent layers thickness.||en_US