The influence of partial hydrocarbon saturation on porosity and permeability in a palaeogene lacustrine shale-hosted oil system of the Bohai Bay Basin, Eastern China

Abstract

Abstract Palaeogene calcareous (>40% carbonate) mudstones (Ro from 0.56 to 0.88%) from the Bohai Bay Basin were studied by combined petrographical, geochemical and petrophysical analysis in order to assess and quantify the pore space, pore filling and its influence on gas transport capacity. TOC contents ranged from 1.44% to 5.12% and porosities (ΦHe) determined by helium pycnometry, from 1.3% to 6.4%. Bitumen-filled porosity (ΦS1) was estimated to range between 0.3 and 2.0% based on Rock-Eval S1 values and an assumed bitumen density of 0.90\u202fg/cm3. The “true” total porosity (Φtotal\u202f=\u202fΦHe\u202f+\u202fΦS1) amounts to 1.9–8.5%. The in-situ oil saturation (So) was estimated to range between 25% and 52%, with two samples (L69-1B and L69-2) having relatively high oil saturation (71% and 91%). The conductivity of the remaining “open” pore space was measured on three samples with different orientations and oil saturations from 17 to 24%. The effective Klinkenberg-corrected gas permeability coefficients range between 63 and 2000 nDarcy, and permeability is highest parallel to bedding. Upon loading from 10 to 40\u202fMPa confining pressure the intrinsic permeability coefficients decreased by one order of magnitude, revealing a relatively high exponential stress sensitivity coefficient (0.069\u202fMPa−1) and much lower zero stress permeability (1.416\u202f×\u202f10−6\u202fmD) than most gas shales. This could be due to pore plugging by ductile bitumen.