Carbonate Reservoir Characterization: Part 04
1. To what extent, the concept of total permeability of a coupled fracture-matrix system in a carbonate reservoir would remain to be meaningful?
2. To what extent, the estimation of horizontal permeability in a carbonate reservoir as a function of fracture permeability; matrix permeability; fracture spacing; and fracture dip would remain to be meaningful?
3. If fractures are just acting as a conduit to transport the oil, while, all the oil remains stored in low permeability rock-matrix, then, to what extent, fracture permeability, will be of any use, in estimating the OOIP in a carbonate reservoir?
4. Can we expect the flow to remain to be in laminar regime in high permeable fractures?
5. Whether the withdrawal of oil from low permeable rock-matrix would end up with an increase, or, reduction in fracture aperture width?
6. Given the fact that natural fractures rarely remain to be parallel, then, to what extent, the concept of cubic law, where, the pressure drop remains to be proportional to the cube of the fracture aperture width would remain to be justified in a carbonate reservoir?
7. If the fracture walls or fracture surfaces remain to be rough, then, to what extent, the resulting head loss associated with fracture surfaces would remain to be sensitive?
8. When exactly the concept of absolute roughness and relative roughness on flow through induced fractures would remain to be sensitive? How about the sensitivity of ‘head loss due to fraction’ with reference to the ‘potential head’?
9. Whether cubic law be applied irrespective of the size of the fracture aperture thickness? For example, what exactly controls the fluid flow when the fracture aperture thickness remains to be (a) 0.1 micron; (b) 1 micron; (c) 10 micron; and (d) 100 micron? When exactly, (a) pressure gradient dominates the fluid flow; and (b) capillary forces dominate the fluid flow? Why does even cubic law fail to work at low fracture aperture thicknesses?
10. To what extent, the carbonate reservoir characterization is becoming difficult resulting from the presence of highly directional permeability; and that too, permeability remaining drastically different in one direction from those in another direction – associated with the geologic stresses imposed upon the reservoir rocks?
11. Whether, fracture spacing could be obtained from well-test analysis?
12. To what extent, fault morphology and boundaries of genetic carbonate units really (a) influence the continuity of a carbonate reservoir; and (b) influence the volumetric sweep efficiency?
Suresh Kumar Govindarajan
https://home.iitm.ac.in/gskumar/
https://iitm.irins.org/profile/61643