Application Guide
How mercury injection capillary pressure (MICP), gas adsorption, and related tests characterize pore throats in reservoir rocks and shales — and how lab data are converted to reservoir conditions.
Hydrocarbon storage depends on porosity, but flow and recovery depend on the size and connectivity of the pore throats that link pore bodies. Mercury intrusion — called mercury injection capillary pressure (MICP) in petroleum work — measures exactly that: the throat size that controls entry into each part of the pore network.
Conventional sandstones and carbonates typically have porosities of roughly 10–30 % and permeabilities from millidarcies to darcies. Shales and tight rocks have much smaller pores (largely nanometre-scale) and permeabilities that can be in the nanodarcy range, which pushes characterization toward high-pressure MICP and gas adsorption.
Pressure is converted to throat diameter with the Washburn equation, d = −4γ cos θ / P, commonly using γ = 485 mN/m and θ = 130–140° for mercury on rock. Instruments reaching about 414 MPa (60,000 psi) intrude throats down to roughly 3 nm.
Empirical correlations link MICP-derived throat sizes to permeability. The widely used Winland relation (developed by H. D. Winland at Amoco and first published by Kolodzie, 1980) is log r35 = 0.732 + 0.588 log k − 0.864 log φ, with r35 the throat radius in µm at 35 % mercury saturation, k in mD, and φ in percent. Such correlations are field- and rock-type-specific; calibrate against measured core permeability.
Use the calculators to convert test pressures to pore sizes, or email a short description of your sample and what you need to measure.