Pore Throat Size controls Saturation and Permeability - Petrophysics Training & Courses

 Because pore size is a factor in saturation and permeability, it seems logical to use saturation-related parameters to predict permeability. This is not possible in all geological or petrophysical models. We instead acquire NMR logs, core analyze flow zones, and rock types to attempt to use porosity for permeability variations. However, we ignore what we have in order to make a more accurate, cheaper prediction of permeability. The hydrocarbon pore volume is a better default prediction of intergranular permeability across different reservoir types, and different rock types than porosity and even saturation. Sw Swi should first be evaluated by fluid zones. Petrophysicists know that good rocks contain more hydrocarbons than poor rocks at the same capillary pressure (height). But they don't use it!

For Saturation Height, Capillary Pressure Mercury Injection Data is (MCIP).

Additionally, mercury data cannot be used to calculate Sw-Height in clayy, low-permeability rocks without Cation Exchange Capacity corrections and Clay Bound Water corrections. A mercury experiment does not require a water phase to wet clays or fine pores. The mercury bulldozer can physically pierce clay-lined throats with its mercury bulldozer. Mercury data can be used to determine the size of pore openings for rock typing. This is particularly important in cases where Clay + Capillary Bound Water makes up a substantial fraction of total porosity. The 100% + difference between mercury data and air-brine HPVs for the same reservoir height is an indication of this. These mercury data are not able to provide a usefully accurate dmm-m scale wholerock storage capacity in rocks below 30mD or high CEC water shaly reservoirs. High HPV can be explained by using MCIP data that is not corrected for clay and capillary bound waters.

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