Carbonate Reservoir Characterization: Part 13
1. How exactly to take into account the inertial effects associated with the high-permeable carbonate reservoirs?
Whether, the bottom-hole shut-in tool would remain to be effective in eliminating wellbore storage and inertial effects?
And, how important are wellbore temperature effects; and the interference of neighboring wells producing pressure changes at the tested well?
2. Do we require to have a two different relative permeability curves (one for the fracture and the other for the matrix) for a fractured carbonate reservoir, as the fracturing plane between two matrix units develops a discontinuity in the multi-phase flowing process?
Whether the relative permeability curve for rock-matrix would remain to be representative in relation to the shape of relative permeability curves and the magnitude of their endpoints (irreducible saturation in the wetting and non-wetting phases and the respective relative permeability values at these critical saturations)?
Whether the fracture network relative permeability curves would remain to be significantly different from rock-matrix relative permeability curves – due to the very high values of intrinsic permeability associated with the high-permeability fractures?
Whether these high permeable fractures would have a dominant control of gravity forces in multi-phase fluid flow in fractures?
3. As it is known, in a sandstone reservoir, the capillary pressure at static conditions is associated with the transition zone, while, at dynamic conditions, the capillary forces remain to play a more limited role as the fluid displacement process essentially remains to be controlled by viscous forces. On the contrary, do we require an enhanced understanding of the displacement process, as the displacement process is critically controlled by gravity and capillary pressure forces, which make the interpretation of capillary pressure curve behavior to remain to be extremely challenging?
Whether, capillary pressure behavior with both drainage and imbibition displacement processes, are required to be combined with gravity displacement behavior, which would possibly allow better estimation of fracture-matrix fluid exchange?
4. Whether the displacement of oil from rock-matrix remain to be dependent on fluid saturations, fluid wettability and saturation history in a fractured carbonate reservoir?
5. Whether the shape of a drainage capillary pressure curve would be able to provide the distribution of fracture and fracture aperture thicknesses?
Suresh Kumar Govindarajan
https://home.iitm.ac.in/gskumar/
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