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This paper investigates reservoir quality development in tight Upper Carboniferous fluvial sandstones (Westphalian C/D) in the Lower Saxony Basin, NW Germany. The study integrates data from three outcrops (Piesberg, Woitzel and Hüggel) in the south of the basin with that from two wells (Wells A and B) located at gas fields approximately 50 km to the north. Petrographic and petrophysical data are related to the diagenetic evolution of the sandstones and the burial and structural history of the Lower Saxony Basin. The outcrop and subsurface data sets are compared in order to investigate the factors controlling reservoir quality evolution. Upper Carboniferous fluvial sandstones from the Woitzel and Hüggel outcrops and from Wells A and B have similar matrix permeabilities (0.01 to 10 mD), but matrix porosities vary between Well A (average 6%), Well B (average 10%), Woitzel (average 15%), and Hüggel (average 19%). Permeability reduction during burial is related to the formation of clay mineral cement, which was mainly controlled by variations in both the palaeo‐climate and in the sandstones’ depositional composition. Matrix porosity was controlled by local differences in burial history related to basin inversion tectonics. The greater amount of inversion‐related uplift at Well B (about 2.8 km) resulted in lower thermal exposure of the Westphalian sandstones at this location, which thus show higher matrix porosities than the sandstones at Well A which were uplifted by only about 1.2 km. Further increases in porosity in the outcrop sandstones may be related to the dissolution of carbonate cement during late‐stage uplift in near‐surface conditions. Upper Carboniferous fluvial sandstones from the Piesberg quarry show the poorest reservoir characteristics compared to the samples from the subsurface and the other outcrops, with matrix porosities averaging 6% and permeabilities <0.01 mD. Reservoir quality reduction was controlled by thermal anomalies associated with a large fault at the Piesberg quarry. By contrast, a few outliers in the sample data sets from Well B and the Piesberg quarry, which have permeabilities of more than 100 mD, show that faulting or natural fracturing may enhance reservoir quality within a particular area. Faults/fractures may act as potential migration pathways for leaching fluids, or may provide fracture‐permeability systems with production potential. Depositional setting, burial‐related diagenetic processes and structural characteristics in the Lower Saxony Basin need to be carefully evaluated in order to provide an improved understanding of the reservoir quality of the Upper Carboniferous sandstones.
This paper investigates reservoir quality development in tight Upper Carboniferous fluvial sandstones (Westphalian C/D) in the Lower Saxony Basin, NW Germany. The study integrates data from three outcrops (Piesberg, Woitzel and Hüggel) in the south of the basin with that from two wells (Wells A and B) located at gas fields approximately 50 km to the north. Petrographic and petrophysical data are related to the diagenetic evolution of the sandstones and the burial and structural history of the Lower Saxony Basin. The outcrop and subsurface data sets are compared in order to investigate the factors controlling reservoir quality evolution. Upper Carboniferous fluvial sandstones from the Woitzel and Hüggel outcrops and from Wells A and B have similar matrix permeabilities (0.01 to 10 mD), but matrix porosities vary between Well A (average 6%), Well B (average 10%), Woitzel (average 15%), and Hüggel (average 19%). Permeability reduction during burial is related to the formation of clay mineral cement, which was mainly controlled by variations in both the palaeo‐climate and in the sandstones’ depositional composition. Matrix porosity was controlled by local differences in burial history related to basin inversion tectonics. The greater amount of inversion‐related uplift at Well B (about 2.8 km) resulted in lower thermal exposure of the Westphalian sandstones at this location, which thus show higher matrix porosities than the sandstones at Well A which were uplifted by only about 1.2 km. Further increases in porosity in the outcrop sandstones may be related to the dissolution of carbonate cement during late‐stage uplift in near‐surface conditions. Upper Carboniferous fluvial sandstones from the Piesberg quarry show the poorest reservoir characteristics compared to the samples from the subsurface and the other outcrops, with matrix porosities averaging 6% and permeabilities <0.01 mD. Reservoir quality reduction was controlled by thermal anomalies associated with a large fault at the Piesberg quarry. By contrast, a few outliers in the sample data sets from Well B and the Piesberg quarry, which have permeabilities of more than 100 mD, show that faulting or natural fracturing may enhance reservoir quality within a particular area. Faults/fractures may act as potential migration pathways for leaching fluids, or may provide fracture‐permeability systems with production potential. Depositional setting, burial‐related diagenetic processes and structural characteristics in the Lower Saxony Basin need to be carefully evaluated in order to provide an improved understanding of the reservoir quality of the Upper Carboniferous sandstones.
An investigation of the Triassic Yanchang Formation, Ordos Basin, N. China, revealed that the diagenesis and quality of tight oil sandstone reservoirs (with an average porosity of 9.83% and an average permeability of 0.96 mD) were controlled by a closed diagenetic system. The carbonate cements observed in the sandstone were derived from decarboxylation of organic matter that occurred in the adjacent mudstones. These reactions supplied CO32−, which reacted with cations derived from grain dissolution in the sandstones. The average size of the diagenetic geochemical system with respect to carbonate cements was small (<6 × 10−2 m3), comprising sandstone and its adjacent mudstone(s). The carbonate cements tend to concentrate in the marginal sandstone, which is taken to indicate that the flux of CO32− into the sandstones limited the quantity of carbonate precipitated. In addition, the mass is near balance between the amount of feldspar dissolution and its by‐products in the central sandstone (distance to the sandstone/mudstone interface is mainly more than 1 m), where the permeability of sandstone will present a decreasing trend with the increase of feldspar dissolution pores. The pore space of central sandstone will be just redistributed, with primary intergranular pores converting to feldspar dissolution pores and clay mineral micropores. Thus, the best part of the sandstone reservoirs tends to be the central part of sandstone. In particular, sandstones that are more than 2 m thick could be the potential hydrocarbon reservoirs because they retain the best porosity (average of 13.6%) and permeability (average of 1.8 mD). The results of our study provide an important guide for the exploration of tight oil sandstones in other petroliferous basins over the world.
The environmental consequences of mine flooding in the Saar hard coal district, post-mining re-use concepts in the course of the energy transition, and the potential of coalbed methane production require an understanding of subsurface rock properties on the microscale. In this study, mineralogy, microtexture, microstructure, porosity, permeability, and geochemistry of an Upper Carboniferous (Stephanian A–B) drill core recovered in the Saar–Nahe basin are quantified. Based on these data, the diagenetic history and reservoir quality are analyzed regarding mine flooding and coalbed methane potential. The feldspar-poor and igneous rock fragment-free siliciclastic rock succession shows multiple fining upward sequences deposited in a fluvial environment during the pre-volcanic syn-rift phase of the Variscan intramontane Saar–Nahe basin. Intercalated small-scale coarsening upward sequences are related to the floodplain where near-surface soft-sediment deformation and paleosol formation took place. Porosity (< 7%) of the tight siliciclastic rocks is mainly controlled by an interplay of authigenic microporous kaolinite, dissolution porosity, and quartz cement, whereas permeability (< 0.05 mD) shows no systematic variation with petrography. During burial, quartz cements preserved porosity by stabilizing the granular framework against mechanical compaction, while phyllosilicates were ductilely deformed reducing reservoir quality. Relative phyllosilicates and quartz contents and mean grain size are reliably inferred from SiO2/Al2O3 ratios (1.8–28.8), Ba (0.0108–0.0653 wt%), Rb (0.0024–0.0181 wt%), and Sr (0.0013–0.0086 wt%) concentrations measured with a portable x-ray fluorescence analyzer. Regarding coalbed methane production and mine flooding, sealing of cleats and heterogeneous subsurface rock properties due to dynamically changing depositional settings during the Late Carboniferous need to be considered. Graphical abstract
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