Depositional environment and hydrocarbon source potential of the Lower Miocene oil shale deposit in the Aleksinac Basin (Serbia)

Bechtel, Achim; Oberauer, Klaus; Kostić, Aleksandar; Gratzer, Reinhard; Milisavljevic, Vladimir; Aleksić, Nikoleta; Stojanović, Ksenija; Groß, Doris; Sachsenhofer, Reinhard F.

doi:10.1016/j.orggeochem.2017.10.009

Cited by 30 publications

(7 citation statements)

References 66 publications

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“…The depositional environment has significant effects on the composition of shale with different types of kerogen [45,46,[55][56][57]. In addition, for shales with different kerogen types, they have their own relationships between different compositions [34,[58][59][60].…”

Section: Composition Of the Shale Samples With Type III Kerogen Formementioning

confidence: 99%

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

et al. 2020

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This study focuses on the nanostructure of shale samples with type III kerogen and its effect on methane adsorption capacity. The composition, pore size distribution, and methane adsorption capacities of 12 shale samples were analyzed by using the high-pressure mercury injection experiment, low-temperature N2/CO2 adsorption experiments, and the isothermal methane adsorption experiment. The results show that the total organic carbon (TOC) content of the 12 shale samples ranges from 0.70% to ~35.84%. In shales with type III kerogen, clay minerals and organic matter tend to be deposited simultaneously. When the TOC content is higher than 10%, the clay minerals in these shale samples contribute more than 70% of the total inorganic matter. The CO2 adsorption experimental results show that micropores in shales with type III kerogen are mainly formed in organic matter. However, mesopores and macropores are significantly affected by the contents of clay minerals and quartz. The methane isothermal capacity experimental results show that the Langmuir volume, indicating the maximum methane adsorption capacity, of all the shale samples is between 0.78 cm3/g and 9.26 cm3/g. Moreover, methane is mainly adsorbed in micropores and developed in organic matter, whereas the influence of mesopores and macropores on the methane adsorption capacity of shale with type III kerogen is small. At different stages, the influencing factors of methane adsorption capacity are different. When the TOC content is <1.4% or >4.5%, the methane adsorption capacity is positively correlated with the TOC content. When the TOC content is in the range of 1.4–4.5%, clay minerals have obviously positive effects on the methane adsorption capacity.

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Section: Composition Of the Shale Samples With Type III Kerogen Formementioning

confidence: 99%

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

et al. 2020

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“…Beside their origin from carotenoids specific for photosynthetic green sulphur bacteria (Chlorobiaceae; Summons and Powell, 1987), aryl isoprenoids have been reported as diagentic products from β-carotane by Koopmans et al, (1996). However, the occurrence of β-isorenieratane in the oil shale sample at 77.3 m depth, suggests that the aryl isoprenoids are most probably derived from green sulphur bacteria (Brocks and Schaeffer, 2008;Bechtel et al, 2018).The occurrence Formation. Std., standard (1,1'-binaphthyl).…”

Section: Hopanoidsmentioning

confidence: 99%

Hydrocarbon Potential and Palaeo‐depositional Environment of Lacustrine Source Rocks: Middle Jurassic Shimengou Formation, Northern Qaidam Basin, Nw China

Meng

Bechtel

Sachsenhofer

et al. 2018

Journal of Petroleum Geology

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The Middle Jurassic Shimengou Formation in the Qaidam Basin, NW China, includes coals and lacustrine source rocks which locally reach oil shale quality (i.e. yielding >3.5 % oil on low‐temperature distillation). In the present study, the palaeo‐depositional environment and hydrocarbon potential of the 84.5 m thick Shale Member of the Shimengou Formation are investigated based on bulk geochemical parameters, organic petrographic data, biomarker analysis, and stable isotope geochemistry of 88 core samples. The Shale Member was deposited in an anoxic freshwater lake which formed following the drowning of a precursor low‐lying mire. Variations in bulk geochemical parameters allow four informal units to be identified, referred to (from the base up) as Units 1 to 4. These contain intervals of oil shale of varying thicknesses. In Unit 1, mudstones in the interval referred to as oil shale Layer 1 (true thickness [TD]: 2.06 m) are OM‐rich as a result of algal blooms and photic zone anoxia, and correspond to an initial flooding event. Subsequently, productivity of aquatic organisms decreased, resulting in the deposition of organic‐lean mudstones in Unit 2. Oil shale Layers 2 (TD: 2.03 m) and 3 (TD: 8.03 m) near the base of Unit 3 were deposited during maximum water depths. As with Layer 1, high productivity by algal blooms resulted in photic zone anoxia in a stratified water column. The shales in the upper part of Unit 3 are characterized by high TOC contents and a gradual increased input of terrigenous OM, and were deposited in a stable semi‐deep lake. Finally, organic‐lean mudstones in Unit 4 were deposited in shallow lacustrine conditions. The reconstruction of depositional environments in thick, non‐marine shale‐rich successions by mineralogical, petrographic and inorganic geochemical methods may be challenging as a result of the homogenous composition of component mudstones. The results of this study indicate, however, that sub‐division and basin‐wide correlation of such intervals can be achieved by organic geochemical analyses. Oil shales and organic‐rich mudstones in Units 1 and 3 of the Shimengou Formation Shale Member are excellent oil‐prone source‐rocks with a Source Potential Index of 3.2 t HC/m2. Considering the large area covered by the Shimengou Formation in the northern Qaidam Basin (∼34,000 km2), the results of this study highlight the regional significance for future petroleum exploration. They indicate that variations in organic productivity and dilution by minerals are key factors controlling the abundance and type of organic matter in the formation. An understanding of these factors will assist with the identification of exploration targets.

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“…Many studies of OM accumulation in lacustrine shale suggest that OM-supplemented and depositional environment dominated source rock development. 62,69,70 In the study, the Taiyuan to the Shanxi demonstrated similar OM input with slight variation between the two formations. This was accompanied by a fluctuation of the paleoclimate toward greater humidity (Figure 4).…”

Section: Resultsmentioning

confidence: 70%

Carboniferous–Permian Coaly Source Rock Formation in North China: Implications from Geochemical Characteristics and Depositional Environments

Lou¹,

Cao²,

Peng³

et al. 2022

ACS Earth Space Chem.

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Coal and accompanying shales have gained attention as potential source rocks and reservoirs providing abundant cleaner energy hydrocarbons. Carboniferous−Permian coaly source rocks deposited in North China were investigated using organic−inorganic chemistry, organic petrology, and biomarkers to analyze their hydrocarbon generation potential, maceral components, and depositional environments. Coal of Taiyuan Formation (Taiyuan) and Shanxi Formation (Shanxi) was characterized by type II 1 to III kerogen with good-to-excellent quality. However, carbonaceous mudstone and coaly shale contained type II 2 to III kerogen with poor-to-good quality. More liptinite of sporinite, cutinite, resinite, and hydrogen-rich collodetrinite was present in the Taiyuan coal than that of the Shanxi. Carbonaceous mudstone and coaly shale contained less sporinite, cutinite, and vitrinite. Taiyuan coaly source rocks were deposited in a brackish and anoxic−dysoxic bottom water environment which provided better preservation conditions compared to the fresh−brackish and weak reduction−oxidation environment of Shanxi coaly source rocks. The depositional environment was a critical factor determining the accumulation of organic matter (OM) for the Taiyuan and Shanxi coaly source rocks. Additionally, a flux of hydrogen-rich components of liptinite and vitrinite was also a key factor in the formation of coal, carbonaceous mudstone, and coaly shale. A model of OM accumulation in coaly source rocks was established to predict good-to-excellent source rocks in similar depositional environments.

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Depositional environment and hydrocarbon source potential of the Lower Miocene oil shale deposit in the Aleksinac Basin (Serbia)

Cited by 30 publications

References 66 publications

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

Hydrocarbon Potential and Palaeo‐depositional Environment of Lacustrine Source Rocks: Middle Jurassic Shimengou Formation, Northern Qaidam Basin, Nw China

Carboniferous–Permian Coaly Source Rock Formation in North China: Implications from Geochemical Characteristics and Depositional Environments

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