Reservoir heterogeneity of tight gas sandstones from observations of outcrop and subsurface data in the Lower Saxony Basin, Germany
Becker, I., Wüstefeld, P., Hilse, U., Manss, Y., Koehrer, B., and Hilgers, C.
Reducing uncertainties in reservoir characterization can immensely benefit from using quantitative outcrop analog data. The comparison of outcrop analogs with subsurface data from well cores enables the delineation of reservoir heterogeneities over basin-scale distances. This study focuses on the structural and diagenetic pattern of Upper Carboniferous tight gas sandstone reservoirs in the Lower Saxony Basin, Germany. The investigated open-pit quarries in the Ibbenbüren-Osnabrück area reflect the sedimentology, stratigraphy, structure and diagenesis of tight gas reservoirs some 50 km further north. They expose fining upwards fluvial cycles of coarse-grained sandstones into siltstones and coal seams. We show how the variation of porosity and permeability of surface and subsurface data links to the diagenetic and structural evolution of tight sandstone reservoirs.
Using He-pycnometry and single-phase gas flow in an isostatic flow cell depicts potential vertical and lateral porosity and permeability trends. Matrix permeabilities show a wide variation from 0.001 to 1 mD in the outcrop samples and in the tight sandstone reservoirs (see also Wimmers & Koehrer 2014). Such wide ranges are related to variations in the intensity of mesogenetic illite and quartz cement formation and subsequent leaching processes depending on lithofacies, subsidence and structural setting.
Surface data expose particular low porosities and permeabilities in tight sandstones when affected by higher temperatures at intersecting faults as demonstrated by the Piesberg quarry (Wuestefeld et al. 2014). In contrast, diagenetically analogous outcrops show higher matrix porosities up to 22 % due to the dissolution of unstable carbonate cements, but similar matrix permeabilities. The lateral variation of porosities and permeabilites is consistent over tens of meters in the same lithofacies.
Exposed faults, however, represent migration pathways for fluids indicated by mesogenetic quartz veins and later leached lithoclasts close to the fault, the latter leading to an increased matrix porosity up to 25 % and permeability up to 100 mD (Wuestefeld et al. 2014). Similar effects of reservoir improving leaching events can also be shown in naturally-fractured tight sand reservoirs by the dissolution of feldspars and increased secondary porosities. Thus, fault zones in the Upper Carboniferous tight sandstones represent corridors of prominent but localized sealing and leaching events.
Overall, linking the diagenetic and structural history of tight sandstone reservoirs is key to predict reservoir quality with regard to open pore space at the point of hydrocarbon charging.