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Abstract In this study, we use Broad Ion Beam polishing and Scanning Electron Microscopy (BIB-SEM) to characterize the microstructure of selected core samples of immature Upper Cretaceous carbonate-rich oil shales from Jordan and to link the observations to porosity and compositional and geochemical data. The aim of this study is to understand the distribution of pore space, primary organic matter, and organic sulfur on a sub-micron scale, particularly in carbonate- and silicate-dominated layers. The thermal maturity of these marine carbonate mudstone samples of pelagic origin was found to be influenced by the elevated sulfur contents in these Type II-S kerogen source rocks. This was confirmed through both organic geochemistry and BIB-SEM observations, which revealed high sulfur content. Porosity in the carbonate mudstone exists within foraminifera, and aggregates of microfossil fragments. Initially, these voids provided significant inter- and intra-particle porosity which were later filled by organic matter during diagenesis. This ‘mobile’ organic matter is interpreted as microscopic bitumen, which exists as a solid or highly viscous fluid at surface conditions. It is likely a residue of low-temperature (“early”) bitumen generation. By examining the samples before and after dichloromethane (DCM) extraction and subsequent BIB-SEM analyses, we observed that the specimens contained a significant amount of soluble organic matter (SOM), mostly present in the micropores associated with calcite. The microscopic solid bitumen is observed to remain stable even under various conditions, such as in vacuum oven conditions of 105 °C (24 h), or exposure to ultra-high vacuum, broad ion beam (heat > 70 °C) and an electron beam of 15 keV. This suggests that the solid bitumen acts as a solid at elevated temperatures and confining pressures (85 °C and 250 MPa), and its presence can lead to the buildup of significant fluid overpressures. Our observations indicate that the pores associated with calcite provide high storage capacity in the shales during the early stages of hydrocarbon generation. In contrast, it suggests that siliciclastic-rich samples are more prone to hydrofracturing as the (early) generated hydrocarbons cannot be expelled easily. These findings highlight the complex distribution and behavior of pore space, organic matter, and sulfur in shales, shedding light on their potential for hydrocarbon generation and storage. Graphical abstract
Klaver et al. (Mon,) studied this question.