Porosity evolution of two Upper Carboniferous tight-gas-fluvial sandstone reservoirs: Impact of fractures and total cement volumes on reservoir quality

Abstract

Abstract Cyclic fluvial, coal-bearing sandstones from the Upper Carboniferous are important tight-gas reservoirs in the Lower Saxony Basin, NW Germany. Two wells from two fields located 10 km apart, both comprising of Westphalian C/D fluvial sandstones were studied. Well A was affected by approximately 1.2 km and well B of approximately 2.8 km of basin inversion after maximum burial depths larger than 5 km. Both fields display significant differences in recovered resources. An integrated core study combining sedimentological, petrographic and petrophysical data illustrates the impact of different diagenetic pathways. While permeability values appear in the same range of 0.01–1 mD for both fields, lithologies from well A of field A have average matrix porosities of 6% in a generally unfractured reservoir, whereas lithologies from well B of field B have matrix porosities of 10% in an overall fractured reservoir. Intense siderite/ankerite cementation in matrix and fractures is present in sandstones from both fields and can be related to fluid migration during basin inversion. In contrast, the strong alpine tectonic inversion affecting field B results in a lower thermal exposure since the late Cretaceous, resulting in smaller quartz cement volumes than in field A and larger matrix porosities in field B. Thus, matrix porosity is overall better due to smaller total cement volumes in field B. The study indicates a strong impact of fractures on tight sandstone reservoir quality and quartz cementation on hydrocarbon production performance from the sandstone matrix. Observations may be applicable to similar, strongly inverted tight gas sandstone fields and may directly affect exploration strategies.