Gas accumulations in Oligocene–Miocene reservoirs in the Alpine Foreland Basin (Austria): evidence for gas mixing and gas degradation

Pytlak, Ł.; Groß, Doris; Sachsenhofer, Reinhard F.; Bechtel, Achim; Linzer, Hans‐Gert

doi:10.1007/s00531-016-1421-1

Cited by 9 publications

(7 citation statements)

References 53 publications

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“…Isotopically light gas is produced from uppermost Oligocene and Lower Miocene sediments in the eastern part of the Alpine Foreland Basin (Schulz and van Berk, 2009;Pytlak et al, 2017) and from Middle Miocene sediments in the Carpathian Foredeep, the Vienna Basin (Ladwein, 1988;Rupprecht et al, 2018) and the Transylvanian Basin (e.g. Kotarba and Koltun, 2006;Ciulavu et al, 2000).…”

Section: Miocene Source Rocksmentioning

confidence: 99%

Paratethyan Petroleum Source Rocks: An Overview

Sachsenhofer

Popov

Ćorić

et al. 2018

Journal of Petroleum Geology

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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.

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Section: Miocene Source Rocksmentioning

confidence: 99%

Paratethyan Petroleum Source Rocks: An Overview

Sachsenhofer

Popov

Ćorić

et al. 2018

Journal of Petroleum Geology

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“…4a) and by the presence of varying fractions of coarse-grained clastic rocks in the Puchkirchen Group. This is supported by the fact that microbial gas in Oligocene and Miocene reservoir rocks contains elevated percentages of thermogenic gas (and condensates) in fields located above zones where erosion removed parts of the Oligocene fine-grained succession (Pytlak et al, 2017a) (see below: Microbial Petroleum System).…”

Section: Sealsmentioning

confidence: 98%

“…Fault activity was especially intense during early Oligocene time, but seismic data show that some faults were active until the earliest Miocene (e.g. Pytlak et al, 2017a) .…”

Section: Tectonic Evolutionmentioning

confidence: 99%

“…Moreover, microbial gas is very dry (C 1 /C 2 +C 3 ) > 500), as only small amounts of ethane and propane are formed by microbial activity (Hinrichs et al, 2006). Pytlak et al (2017a) investigated the molecular and isotopic composition of 87 gas samples produced from the Puchkirchen and Hall reservoirs. Purely microbial gas was found in a single field at the northern flank of the basin (Zupf field; Fig.…”

Section: Hydrocarbon Mixing and Biodegradationmentioning

confidence: 99%

“…Biodegradation and the formation of secondary microbial gas resulted in gas drying, causing the investigated gas samples to be relatively dry despite the significant contribution of thermogenic hydrocarbons. The presence of ethene and propene, which are considered to be unstable over geological time periuods (Whiticar, 1994), suggests that biodegradation probably continues at the present day (Pytlak et al, 2017a). The degree of biodegradation, however, decreases with depth ( Fig.…”

Section: Hydrocarbon Mixing and Biodegradationmentioning

confidence: 99%

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Petroleum Systems in the Austrian Sector of the North Alpine Foreland Basin: An Overview

Groß

Sachsenhofer

Bechtel

et al. 2018

Journal of Petroleum Geology

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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 posit...

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Factors controlling the petroleum generation characteristics of Palaeogene source rocks in the Austrian Molasse Basin as revealed by principal component analysis biplots

Yang

Schulz

2019

Marine and Petroleum Geology

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After Rock-Eval & TOC screening and heterogeneity evaluation on 91 Palaeogene source rock samples from a well drilled in the Austrian Molasse Basin, ten shale samples were selected for detailed investigations by means of pyrolysis-gas chromatography, bulk kinetics and biomarker identification and quantification. Afterwards, 2-D biplots based on principal component analysis were applied to unravel the palaeo-environmental control on the development of petroleum source rocks. All samples are immature source rocks with good petroleum generation potentials. The redox environment during deposition was generally reducing, and palaeosalinity is suggested to be the main factor causing the differences in organic carbon contents among the samples. The hydrogen index values, the gas generation preferences and the aromaticity of the products are controlled by both depositional environment and precursors, and the product of a salinity indicator (MTTC) and the oleanane index is introduced as predictive proxy to evaluate these features. The maturity indicator (Tmax) is revealed as dominated by the stability of the kerogen structure which is controlled by the proportion of organic sulphur compounds in the kerogen. The global Eocene-Oligocene climate change from a greenhouse to an icehouse world is suggested to play an important role in changing the palaeoenvironment and further in influencing the development of petroleum source rocks by triggering upwelling, increasing the palaeo-sea water salinity and decreasing the deposition of carbonate-minerals. The chemometric method suggested here acts as a powerful tool in identifying the controlling factors for the petroleum generation potential among many variables, and can be applied more widely in petroleum geology when multi-parameters are involved to get quick and meaningful correlations.

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Gas accumulations in Oligocene–Miocene reservoirs in the Alpine Foreland Basin (Austria): evidence for gas mixing and gas degradation

Cited by 9 publications

References 53 publications

Paratethyan Petroleum Source Rocks: An Overview

Paratethyan Petroleum Source Rocks: An Overview

Petroleum Systems in the Austrian Sector of the North Alpine Foreland Basin: An Overview

Factors controlling the petroleum generation characteristics of Palaeogene source rocks in the Austrian Molasse Basin as revealed by principal component analysis biplots

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