Characterization of pore systems in seal rocks using Nitrogen Gas Adsorption combined with Mercury Injection Capillary Pressure techniques

Porous microstructure parameters of seal rock samples originating from different depths within Brazilian geological formations were correlated to empirical models which predict the intrinsic permeability. Mercury Injection Capillary Pressure (MICP) and Nitrogen Gas Adsorption (N2GA) were applied in combination as complementary techniques; MICP to obtain the porosity values and the size distribution of meso- and macropores, and N2GA associated with the Brunauer, Emmett and Teller (BET) theory to determine the specific surface area (So). The Barret, Joyner and Hallenda (BJH) theory was applied to find the size distribution of the micro- and mesopores. The combination of the MICP and N2GA curves showed that the samples analyzed present a polymodal pore size distribution (PSD) and a total porosity ranging from 0.33 % to 10.44 %. The So values measured by N2GA were higher than those calculated by MICP, due to the majority of the samples having a mean pore size of 20–1000 Å. The intrinsic permeability could also be predicted applying the measured parameters, So, PSD curves and total porosity in the Carman–Kozeny and Series–Parallel models. The ranges of permeability values obtained were 4.09 × 10−24–4.96 × 10−21 m2 and 9.48 × 10−27–9.14 × 10−22 m2, respectively. These results were compared with values reported in the related literature and those obtained for four samples submitted to pressure pulse decay permeability (PDP) tests.

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► Combination of N2 adsorption and Hg intrusion to characterize gas and petroleum seal rocks.
► BJH and Washburn equations providing pore diameters ranging from 20 Å to 100 μm
► BET surface area measured between 1.13 and 19.23 m2 g−1.
► Seal capacity evaluated with empirical permeability confirmed by PDP analysis.