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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 N2 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 N2 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. [ABSTRACT FROM AUTHOR]

Two separate petroleum systems have been identified in the Austrian sector of the North Alpine Foreland Basin: a lower Oligocene – Cenomanian/Eocene oil and thermogenic gas system; and an Oligocene‐Miocene microbial gas system. Recent studies by both academic and industry‐based research groups have resulted in an improved understanding of these petroleum systems, which are reviewed in this paper. Lower Oligocene organic‐rich intervals (up to 12 %TOC; HI: 400–600 mgHC/gTOC), capable of generating slightly more than 1 t of hydrocarbons/m2, are the source rocks for the thermogenic petroleum system in the Austrian sector of the North Alpine Foreland Basin. The present‐day distribution of this source rock is controlled by submarine mass movements which removed a large part of the organic‐rich interval from its depositional location during the late early Oligocene. The transported material was redeposited in locations to the south which are at the present day buried beneath Alpine thrust sheets. In addition, source rock units were incorporated into Molasse imbricates during Alpine deformation. Hydrocarbon generation began during the Miocene, and the oil kitchen was located to the south of the Alpine thrust front. Hence, lateral migration over distances of up to 50 km was required to charge the mainly Eocene and Cenomanian non‐ and shallow‐marine sandstone reservoir units. Hydrocarbons are in general trapped in structures related to east‐west trending normal faults, and differences in source rock facies resulted in the development of separate western and eastern oil families. Surprisingly, with the exception of some fields in the eastern part of the study area, associated gas contains varying (and sometimes very high) percentages of primary and secondary microbial methane. The composition of oil in some fields is influenced by both biodegradation and water washing. Post‐Miocene uplift in the Austrian sector of the basin had further effects on biodegradation and the consequent formation of secondary microbial gas, and also resulted in re‐migration. The upper Oligocene to lower Miocene succession (Puchkirchen Group, Hall Formation) provides both source and reservoir rocks for the microbial petroleum system in the Austrian sector of the North Alpine Foreland Basin. TOC contents (<1.0 %) and HI values (<140 mgHC/gTOC) of pelitic source rocks are typically low. Microbial gas was generated shortly after deposition during early diagenesis and was subsequently fixed in gas hydrates. Basin subsidence and high sedimentation rates resulted in decomposition of the hydrates below their stability zone, and reservoirs were filled during the early Miocene. Subsequent mixing of microbial gas with thermogenic gas and condensates is widespread. However, biodegradation has prevented precise determination of the fraction of thermogenic hydrocarbons present in gas samples. Reservoir sandstones were deposited within a deep‐marine channel belt along the axis of the North Alpine Foreland Basin, and reservoir quality depends on the precise position within this belt. In the study area, gas is trapped in compaction anticlines or at channel margin pinch‐outs and additional traps are formed by imbrication structures. [ABSTRACT FROM AUTHOR]

The Paratethys area extends from Central Europe to the borders of the Caspian Sea in Central Asia and hosts a significant number of petroleum provinces, many of which have been charged by Eocene to Miocene source rocks of supra‐regional significance. These include highly oil‐prone Middle Eocene marls and limestones in the Eastern Paratethys (Kuma Formation and equivalents) which are several tens of metres thick. Estimates of the source potential index (SPI) indicate that the Kuma Formation in the northern Caucasus and the Rioni Basin (Georgia) may generate 1 to 2 tons of hydrocarbons per square metre (tHC/m2). This implies that the Kuma Formation may also be an important and additional source rock in the eastern Black Sea. Oligocene and Lower Miocene pelitic rocks (Maikop Group and equivalents) are considered to be the most important source rocks in the Paratethys. Vertical variations in source potential record different stages of basin isolation that reached a maximum during the Early Oligocene (NP23) Solenovian Event. However major variations exist between different sub‐basins in the Central and the Eastern Paratethys. In the Central Paratethys, the highest quality source rocks occur in the Carpathian Basin where the Menilite Formation, several hundreds of metres thick, can generate up to 10 tHC/m2. Locally the Menilite Formation is about 1500 m thick and continues into the Lower Miocene. In these settings, the Menilite Formation can generate approximately 70 tHC/m2. In the Alpine Foreland Basin (Schöneck and Eggerding Formations) and the Pannonian Basin (Tard Clay Formation), oil‐prone source rocks are restricted to the Lower Oligocene. In the Eastern Paratethys, the best source rock intervals of the Maikop Group are typically associated with the Early Oligocene Solenovian Event. By contrast, with the exception of the Kura Basin in Azerbaijan, the potential of Upper Oligocene and Lower Miocene rocks is often limited. In total, the Maikop Group may generate up to 2 tHC/m2 in the North Caucasus area and 4 tHC/m2 in the Rioni Basin. A particular source rock facies is found in the Western Black Sea where diatomaceous rocks with good oil potential accumulated in the Kaliakra Canyon during Early Miocene time. This facies may generate up to 8 tHC/m2, but is probably limited to shelf‐break canyons. Middle and Upper Miocene rocks are the main source for oil and thermogenic gas in the Pannonian Basin System, and also contributed to thermogenic hydrocarbons in the Moesian Platform and the South Caspian Basin. In addition, Upper Oligocene and Miocene rocks are the source for microbial gas in several basins including the Alpine and Carpathian foredeeps. [ABSTRACT FROM AUTHOR]

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 FROM AUTHOR]