Producible porosity, defined as the pore volume available to hydrocarbon emplacement, has been computed from log measurements by modelling capillary pressure irreducible water saturation as a function of permeability and maximum hydrocarbon column height. Producible porosity has been also measured directly by NMR when the T2 relaxation time distribution cut-off is calibrated to the maximum capillary pressure in the reservoir. The producible pore volume imposes a calibration constraint on the maximum hydrocarbon pore volume that can be computed from logs. Producible porosity contains no immobile or irreducible water. Total, effective, isolated, macro and micro pore volumes are all used to characterise porosity based on specific definitions, criteria and measurement techniques. Total porosity computed from logs should match core porosity where core porosity represents the total interconnected pore volume, however, total porosity in shaley sandstone reservoirs computed from the crossplot of bulk density and neutron porosity logs has been shown to overestimate core porosity. By modelling formation mineralogy based on a calibration set and solving the log response equations through least squares inversion, total porosity from logs accurately matches core porosity.

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