The Vienna Basin is a major hydrocarbon province with a long exploration history. Within the basin, secondary migration from Upper Jurassic source rocks into stacked Middle Miocene (Badenian) sandstone reservoirs was formerly considered to have occurred almost entirely along major fault zones. However recent exploration data has suggested that in areas where no major faults are present, oil may have migrated vertically through the sandy mudstone intervals separating individual reservoir units, which are therefore imperfectly sealed. In order to investigate possible secondary migration through the semi‐permeable mudstones, this study links variations in gross depositional environment (GDE) to variations in mudstone properties (e.g. mineralogy and pore size distribution). The study focussed on the mudstones which seal reservoir sandstones referred to locally as the “8.TH” and “16.TH” units. The bulk mineralogical composition of 56 mudstone and sandy mudstone (and minor intercalated muddy sandstone) samples from seal layers in 22 wells was studied by X‐ray diffraction analysis, broad ion beam – scanning electron microscopy (BIB‐SEM), mercury intrusion porosimetry (MICP) and N 2 adsorption. These data are interpreted in the context of GDE maps of the Vienna Basin which were previously established using seismic and well log data. Results indicate that the gross depositional environment strongly controlled the pore space characteristics of the mudstones. The sandy mudstones in the NW part of the study area were influenced by a complex eastward‐prograding deltaic system which deposited coarse detritus into a major palaeo depression (“Zistersdorf Depression”) located in the centre of the basin. Higher overall porosity and a dominance of larger pore size classes, probably resulting in reduced seal quality, were observed for sandy mudstones from well locations within feeder channels and also from within the Zistersdorf Depression. Similarly, sandy mudstones from locations associated with the long‐term input of coarser sediments in shoreline, coastal and proximal offshore settings in the NW and central parts of the study area are considered to be of lower sealing quality compared to fine‐grained mudstones deposited in distal, open‐marine settings which prevailed in the SE part of the study area throughout the Middle Miocene. In general, pore geometries were influenced by mineralogical composition; quartz‐ and detrital carbonate‐rich samples show equidimensional pores, while more elongated pores (with a higher average aspect ratio) characterize clay‐rich samples. Furthermore, matrix mesopores (2‐50 nm) determined by N 2 sorption are more abundant in clay‐rich versus quartz‐rich samples, and show a pronounced positive trend with increasing percentage of illite‐smectite mixed‐layer clay minerals. This study shows that regional‐scale mudstone seals in the Vienna Basin have been influenced by variations in sedimentation associated with lateral variations in gross depositional environment during the Middle Miocene. The observed pore characteristics will serve as input data for future models of secondary migration.
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With the rising potential of underground hydrogen storage (UHS) in depleted oil and gas reservoirs or deep saline aquifers, questions remain regarding changes to geological units due to interaction with injected hydrogen. Of particular importance is the integrity of potential caprocks/seals with respect to UHS. The results of this study show significant dissolution of calcite fossil fragments in claystone caprock proxies that were treated with a combination of hydrogen and 10 wt% NaCl brine. This is the first time it has been experimentally observed in claystones. The purpose of this short communication is to document the initial results that indicate the potential alteration of caprocks with injected hydrogen, and to further highlight the need for hydrogen-specific studies of caprocks in areas proposed for UHS.
Shallow oil and gas shows are common in the Alpine thrust front (including the Flysch Zone) and the North Alpine Foreland Basin in Switzerland, southern Germany and Austria, but have not hitherto been evaluated systematically. In the vertically‐drained Vienna Basin and the easternmost part of the Flysch Zone, shallow oil and gas shows and seeps often coincide with deeper‐lying hydrocarbon accumulations, and gas shows occur along major faults – for example within the urbanised area of the city of Vienna. The number of gas shows decreases in the Vienna Basin away from (to the south of) the subcrop of the main thermogenic source rock (the Upper Jurassic Mikulov Formation); however shallow accumulations of microbial gas occur in that area. To the west, along the northern margin of the laterally‐drained North Alpine Foreland Basin, oil shows have been recorded in both Austria and Switzerland; microbial gas shows are common in addition to thermogenic hydrocarbons. Typically the shows form regional clusters along river valleys and occur above shallow gas accumulations. A Lower Oligocene organic‐rich interval represents the main source of oil / condensate and thermogenic gas in the Upper Austrian part of the North Alpine Foreland Basin, whereas the composition of oil shows within the Calcareous Alps to the south indicates the presence of mature Mesozoic source rocks within the Alpine nappes. This implies the presence of an additional, as‐yet untested petroleum system. Thermogenic gas, occurring in Permo‐Triassic evaporitic rocks in the Calcareous Alps, as well as microbial gas in younger sediments, has frequently been encountered during salt mining and tunnelling activities. A surprising discrepancy has been found in different parts of the study area between the number of hydrocarbon shows and the number of economic fields. Whereas the number of fields and shows are approximately in proportion in the Vienna Basin and the Austrian sector of the North Alpine Foreland Basin, shows appear to be “under‐represented” in Germany. By contrast in Switzerland, despite a high number of shows especially in the North Alpine Foreland Basin and the Jura fold‐and‐thrust belt, no economic production has been established to date. Future exploration will show whether this is due to poor reservoir/trap quality, or if undiscovered resources are in fact present. The presence of oil shows generated from Mesozoic and Oligocene source rocks in the SW German and Swiss parts of the North Alpine Foreland Basin suggests the occurrence of multiple petroleum systems; these systems should be delineated in future studies. Few surface seeps have been recorded in less populated parts of the study area such as the high Alps, possibly due to sampling bias. However, this bias does not explain the low frequency of recorded hydrocarbon shows in the German part of the North Alpine Foreland Basin. This may be because the geological setting there is in general less favourable for the migration of thermogenic gas into shallow reservoirs and its preservation in shallow traps.
Abstract Mudstones and shales serve as natural barrier rocks in various geoenergy applications. Although many studies have investigated their mechanical properties, characterizing these parameters at the microscale remains challenging due to their fine-grained nature and susceptibility to microstructural damage introduced during sample preparation. This study aims to investigate the micromechanical properties of clay matrix composite in mudstones by combining high-speed nanoindentation mapping and machine learning data analysis. The nanoindentation approach effectively captured the heterogeneity in high-resolution mechanical property maps. Utilizing machine learning-based k -means clustering, the mechanical characteristics of matrix clay, brittle minerals, as well as measurements on grain boundaries and structural discontinuities (e.g., cracks) were successfully distinguished. The classification results were validated through correlation with broad ion beam-scanning electron microscopy images. The resulting average reduced elastic modulus ( E r ) and hardness ( H ) values for the clay matrix were determined to be 16.2 ± 6.2 and 0.5 ± 0.5 GPa, respectively, showing consistency across different test settings and indenter tips. Furthermore, the sensitivity of indentation measurements to various factors was investigated, revealing limited sensitivity to indentation depth and tip geometry (when comparing Cube corner and Berkovich tip in a small range of indentation depth variations), but decreased stability at lower loading rates. Box counting and bootstrapping methods were applied to assess the representativeness of parameters determined for the clay matrix. A relatively small dataset (indentation number = 60) is needed to achieve representativeness, while the main challenges is to cover a representative mapping area for clay matrix characterization. Overall, this study demonstrates the feasibility of high-speed nanoindentation mapping combined with data analysis for micromechanical characterization of the clay matrix in mudstones, paving the way for efficient analysis of similar fine-grained sedimentary rocks.
Tight sandstone oil reservoirs in the Yanchang Formation of the Ordos Basin have great resource potential. Reservoir quality plays a crucial role in the aggregation and development of tight sandstone oil. The quality of tight sandstone reservoirs is indirectly controlled by diagenesis, which is directly manifested in the differences in pore structure characteristics. At present, there are many studies on the relationship between reservoir quality and diagenesis in the tight sandstone reservoirs of the Yanchang Formation, but there is still no unified method for classifying the diagenetic facies types and characterizing the full-scale pore structure. In this study, based on the large field of view cast thin section analysis and X-ray diffraction (XRD) technology, the clustering analysis method was utilized to classify the diagenetic facie types. Combining low-temperature nitrogen adsorption (LTNA), high-pressure mercury intrusion (HPMI), and constant-velocity mercury intrusion (CMI), a new method based on a weighted approach to characterize the full pore size of tight sandstone reservoirs was proposed. Four types of diagenetic facies are mainly developed in the study area: felsic weakly compacted diagenetic facies (A), dissolution diagenetic facies (B), carbonate cemented diagenetic facies (C), and tightly compacted diagenetic facies (D). The full pore size distribution curve of diagenetic facies B shows a multipeak distribution, in which the peak with the largest value is located from 0.4 to 0.8 μm. The full pore size distribution curves of diagenetic facies A, C, and D all show a single-peak pattern, with peak positions corresponding to decreasing pore diameters from 0.1 to 0.2 μm, 0.07 to 0.1 μm, and 0.007 to 0.13 μm, respectively. The presence of brittle minerals, such as quartz, and the occurrence of dissolution favor reservoir quality. Cementation destroys reservoir storage space, but this occurs when the cement content exceeds a certain threshold. Micropores and mesopores are more clearly related to diagenesis than nanopores. Diagenesis affects reservoir quality by controlling the development of micropores and mesopores. Finally, the correlation between diagenetic facies and the wireline logs was established, and it is clear that the development of diagenetic facies A and diagenetic facies B is associated with better reservoir quality. The study provides insights into how the diagenetic facies of tight sandstone reservoirs are correlated with reservoir quality and pore structures. It has reference significance for sweet spot evaluation in tight sandstone reservoirs.
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