Nano-scale physicochemical attributes and their impact on pore heterogeneity in shale

Abstract

Heterogeneity in shale due to distribution of mineral and organic matter controls the disposition of pores in them. While the effect of vertical anisotropy is accounted for most cases of porosity estimation, the effect of bedding parallel heterogeneity is often ignored. This study dives deep into the shale fabric using bedding parallel sections, and the pore volume distribution is estimated in shales of varying thermal maturity and organic carbon content (2.6% − 38.2 %). Three among the five shales used in this study are early mature (Tmax: 439–444 °C), whereas the remaining two are over-mature, signified by very high S4Tpeak (670–685 °C). The higher thermal maturity indicates thermal alteration induced by igneous intrusion. The pore volume, functional groups, and organic matter distribution are systematically derived in different positions of the bedding parallel section using a combination of 3D imaging, spectroscopy, small-angle scattering and low-pressure gas adsorption techniques. These spot-specific properties are further compared with bulk properties to quantify the extent of heterogeneity. It is observed that the over-mature shales with higher aromaticity contain 150–200% more bulk accessible pore volume than the lesser-mature shales. It is also evident that the smaller mesopores (∼10 nm pore width) are more inaccessible compared to their coarser (∼20 nm pore width) counterparts. Higher matured shales show increased inaccessibility of mesopores up to 228 % due to bitumen deposition in pores during thermal maturation, resulting in a sharp decline in mesopore surface fractal dimension. The uniformity of the functional group and organic matter distribution in different parts of the shale depends on the maturity, and reflects the extent of variation in pore volume across the specimen. The 3D tomography-derived spatial abundance of organic matter in over-mature shales show higher deviation (±15-20%) from the average than lesser-mature shales (5–10%). This study proposes a multiscale methodology which can evolve and develop as a protocol for systematic, reservoir-scale maturity-dependent heterogeneity quantification in gas-shales.