Source rocks and petroleum systems in the Hungarian part of the Pannonian Basin: The potential for shale gas and shale oil plays

Badics, Balázs; Vetö, István

doi:10.1016/j.marpetgeo.2011.08.015

Cited by 65 publications

(40 citation statements)

References 27 publications

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“…2). Bechtel et al (2012) and Badics and Vetö (2012) studied the source rock potential of the Tard Clay and investigated its shale gas/shale oil potential.…”

Section: Pannonian Basinmentioning

confidence: 99%

“…TOC contents of the Buda Marl Formation (NP20-22; Danisik et al, 2015) are typically below 1.0 wt.% (max. 2.3 wt.%) and HI values (<150 mgHC/gTOC) indicate the presence of Type III or inert Type IV kerogen (Bechtel et al, 2012) m; Badics and Vetö, 2012), and in well Ad-3 reaches a thickness of 86 m. Its non-to weakly laminated lower part (698-679 m; uppermost NP22) was deposited in a semi-marine environment and displays TOC contents of up to 5.0 wt.% but with low HI values (<185 mgHC/gTOC) (Bechtel et al, 2012). Higher HI values (210-440 mgHC/gTOC) occur between 679 and 640 m depth (lower NP23) in the strongly laminated, low-salinity middle part of the formation, which corresponds to deposition during the Solenovian Event (Vetö and Hetény, 1991;Vetö and Hertelendi, 1996).…”

Section: Pannonian Basinmentioning

confidence: 99%

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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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“…2). Bechtel et al (2012) and Badics and Vetö (2012) studied the source rock potential of the Tard Clay and investigated its shale gas/shale oil potential.…”

Section: Pannonian Basinmentioning

confidence: 99%

Section: Pannonian Basinmentioning

confidence: 99%

Paratethyan Petroleum Source Rocks: An Overview

Sachsenhofer

Popov

Ćorić

et al. 2018

Journal of Petroleum Geology

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“…The great success of both exploration and development in North America has proved the shale gas to be the most promising unconventional energy recently2. Shale gas consists of both free gas within inter granular pores or natural fractures and adsorbed gas on or underneath the surface of insoluble organic matter (kerogen) or inorganic minerals3.…”

mentioning

confidence: 99%

Research of CO2 and N2 Adsorption Behavior in K-Illite Slit Pores by GCMC Method

Chen

Zhang

Han

et al. 2016

Sci Rep

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Understanding the adsorption mechanisms of CO2 and N2 in illite, one of the main components of clay in shale, is important to improve the precision of the shale gas exploration and development. We investigated the adsorption mechanisms of CO2 and N2 in K-illite with varying pore sizes at the temperature of 333, 363 and 393 K over a broad range of pressures up to 30 MPa using the grand canonical Monte Carlo (GCMC) simulation method. The simulation system is proved to be reasonable and suitable through the discussion of the impact of cation dynamics and pore wall thickness. The simulation results of the excess adsorption amount, expressed per unit surface area of illite, is in general consistency with published experimental results. It is found that the sorption potential overlaps in micropores, leading to a decreasing excess adsorption amount with the increase of pore size at low pressure, and a reverse trend at high pressure. The excess adsorption amount increases with increasing pressure to a maximum and then decreases with further increase in the pressure, and the decreasing amount is found to increase with the increasing pore size. For pores with size greater larger than 2 nm, the overlap effect disappears.

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“…S2 hydrocarbons correlate positively (R 2 ϭ 0.95) with total organic carbon (TOC) throughout the sampled interval at all three locations (Fig. 3) (Badics and Veto, 2012). Both TOC and S2 exhibit well-developed, peaks then decreases at both a small (~2.5 m, ⌬TOC~1.5%) and large (~15.0 m, ⌬TOC~3.5%) resolution at Locations A and B (Fig.…”

Section: Resultsmentioning

confidence: 89%

“…However, without any other petrographic or geochemical indicators it is difficult to determine whether this change is depositional or controlled by post-depositional processes. The mineral carbon rich intervals noted in Location B maybe linked to its proximity to the paleoreef, preserving periods of increased carbonate production associated with eustatic sea level change (Badics and Veto, 2012). The presence of minor inertinite in samples at Location B (observed at sample depths 3360.4, 3362.0 and 3363.4 m, respectively), may indicated proximity to a terrestrial source, however inertinite volume is so low (Ͻ1%) this would likely not affect T max significantly.…”

Section: Discussionmentioning

confidence: 92%

Chemostratigraphic Associations Between Trace Elements and Organic Parameters Within the Duvernay Formation, Western Canadian Sedimentary Basin

Wetering¹,

Mayer²,

Sanei³

2015

Unconventional Resources Technology Conference

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The Devonian Duvernay Formation of the Western Canadian Sedimentary Basin is a hot topic in the energy sector due to the host of massive reserves in both liquid and gas hydrocarbons. There has been a considerable amount of exploration and active recovery within the formation, however very little research into the distribution and character of the organic matter within the Duvernay Formation. The Duvernay Formation is composed of organic-rich limestones and shales, with minor clastics and silica rich, deep-sea sediments. It has been hypothesised that there is a complex relationship between the distribution of organic matter within the Duvernay, and the surrounding Leduc Reef complexes, which act as reservoirs for oil generated in the Duvernay. The data presented as part of this abstract illustrates the use of trace element data (determined by ICP-MS) and organic and thermal parameters (determined by RockEval), to evaluate changes in depositional environment and resulting hydrocarbon production potential in the Duvernay Formation. A high-resolution data set (n ϭ 216) was analysed from two wells intersecting the Duvernay Formation for a interval of 48.0 m. The results were statistically evaluated using modified polytopic vector analysis (PVA) software. PVA analysis indicated strong associations between total organic carbon (TOC) and elemental enrichment of Mo, U, V and Re (R2 Ͼ 0.86), whilst kerogen type (Hydrogen Index (HI) / Oxygen Index (OI)) was strongly associated (R2 Ͼ 0.78) with enriched carbonate elements including Ca, Mg, Mn and Sr. Variations over depth of these elemental and organic parameters exhibit a change from reducing to oxidising conditions associated with increased clastic input and progression from Type I to Type II kerogen from the lower to upper Duvernay Formation. The isolation of specific trace elements from ICP-MS data provides a quantitative indicator of depositional environment and it's relationship with organic and thermal parameters within unconventional source rocks. The relationships between these variables provide valuable information that maybe integrated into geophysical data sets to interpret stratigraphic boundaries and changes in basin architecture over geological time.

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Source rocks and petroleum systems in the Hungarian part of the Pannonian Basin: The potential for shale gas and shale oil plays

Cited by 65 publications

References 27 publications

Paratethyan Petroleum Source Rocks: An Overview

Paratethyan Petroleum Source Rocks: An Overview

Research of CO2 and N2 Adsorption Behavior in K-Illite Slit Pores by GCMC Method

Chemostratigraphic Associations Between Trace Elements and Organic Parameters Within the Duvernay Formation, Western Canadian Sedimentary Basin

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