Phenanthrene biomarkers in the organic matter of Precambrian and Phanerozoic deposits and in the oils of the Siberian Platform

Каширцев, В. А.; Parfenova, Т.М.; Головко, А. К.; Nikitenko, B.L.; Зуева, И. Н.; Chalaya, O. N.

doi:10.1016/j.rgg.2018.09.013

Cited by 17 publications

(10 citation statements)

References 19 publications

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“…or steeply-dipping faults, into the overlying Upper Vendian and Lower Cambrian. Biomarker evidence published by Kashirtsev et al (1999) is consistent with all of the Riphean to Early Cambrian oils of the Nepa-Botuoba Anteclise having been sourced from organicrich Riphean and Vendian carbonates and calcareous mudstones deposited on the passive margin of the Siberian Platform. Drobot et al (2004) proposed that the same kitchen has been the source of gas in fields located in the Angara-Lena Step including the giant Kovykta field NW of Lake Baikal (Fig.…”

Section: Baikal-patom Kitchensupporting

confidence: 59%

“…Starosel 'tsev et al (2013) stated that Llandoverian (Lower Silurian) graptolite shales in Eastern Siberia display elevated contents of organic matter and form potential source rocks, although there is little information on their nature or distribution. Devonian source rocks do not appear to be widespread, but biomarker evidence published by Kashirtsev et al (1999) indicates that oils within the Permian reservoir at the South Tigyansk field on the northern flank of the Anabar Arch were generated by source rocks deposited in a hypersaline environment, consistent with the Devonian of the Lena-Anabar Basin to the north. Coals and carbonaceous mudrocks of Late Carboniferous to Permian age form widespread gas-prone source rocks across the Siberian Platform, including the Vilyui and Tunguska Basins.…”

Section: Post-riphean Source Rocksmentioning

confidence: 99%

“…These deposits are not regarded as oil-prone. Kashirtsev et al (1999) interpreted biomarker evidence from oils within Upper Permian and Mesozoic reservoirs in the Vilyui Basin to indicate derivation from terrigenous, possibly coal-bearing, fluvial, lacustrine and swamp deposits of Permian age. Fine-grained Jurassic sedimentary rocks only contain significant contents of organic matter, both oil-and gas-prone, around the eastern margins of the Siberian Platform.…”

Section: Post-riphean Source Rocksmentioning

confidence: 99%

“…Safronov et al (2014) stated bitumens permeated by lighter oils in dolomitised limestones of the Middle Cambrian Tankhai Suite were recorded in several shallow (83 m and 282 m) hydrogeological wells on the right-bank of the River Amga during the 1970s and 1980s, and the area was provisionally referred to as Bologur after the name of a local settlement. A core of oil-saturated vuggy limestone from one of these wells was illustrated by Kashirtsev (2004). Archegov et al (2006) reported that bitumens are concentrated around faults.…”

Section: Amgamentioning

confidence: 99%

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Bitumen Resources of the East Siberian Basin

Liu

Blackbourn²,

Zhixing

et al. 2023

Journal of Petroleum Geology

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The so‐called East Siberian “Basin” extends over an ancient continental block, the Siberian Platform, and is made up of a number of smaller‐scale basement arches and basins with a variable sedimentary cover of mostly Proterozoic and Palaeozoic ages. The basin hosts the oldest large‐scale petroleum systems known. Proterozoic (“Riphean”: 1650‐650 Ma) marine source rocks, which were deposited on the passive margins which surrounded much of the Platform, generated hydrocarbons as they were buried, folded and thermally matured during a series of mostly Late Proterozoic to Cambrian continental collisions, with the final collision taking place in the Early Cretaceous along the northeastern (Verkhoyan) margin. The hydrocarbons were transported by long‐distance migration to reservoirs in the sedimentary successions which drape basement uplifts, there forming giant oil and gas accumulations which were sealed by extensive Cambrian evaporites. Subsequent uplift and unroofing, especially in the north and east of the Platform where the seal is not present, led to degradation of the oil to leave giant accumulations of bitumen, defined here as petroleum with an API gravity of less than 10° which is immobile under reservoir conditions. A significantly younger petroleum system, which may still be active, is present in the Vilyui Basin in the NE of the Siberian Platform. This basin was initiated as a mid‐Devonian rift and has a later Palaeozoic and Mesozoic fill.Bitumen accumulations in the East Siberian Basin occur mainly in Precambrian, Cambrian and Permian reservoir rocks, and began to form from precursor oils during the Permian. Around twenty‐five named fields have been described, many of which comprise portions of more extensive belts of bitumen occurrence. Although geological mapping of natural resources in the East Siberian Basin has been carried out since the 19th century, the region remains under‐explored and none of the bitumen accumulations has yet been developed.An attempt is made in this paper to catalogue and map all recorded occurrences of bitumen throughout the East Siberian Basin. Regional geological studies have been conducted in order to understand the origin and habitat of each occurrence. So far as possible, data on the areal extent and stratigraphic thickness of each bitumen occurrence has been collated, together with data on bitumen saturations and quality. These data were used to calculate resource volumes for each accumulation from first principles. Thus the total bitumen resources within the East Siberian Basin have been calculated as 24,640 MM (million) tonnes. Disregarding accumulations regarded as either of insufficient resource‐density or too small to merit consideration, this figure has been reduced to 14,760 MM tonnes. Recoverable reserves, by analogy with comparable resources worldwide, are calculated as 6100 MM tonnes (approximately 33,900 MM brl)

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Section: Baikal-patom Kitchensupporting

confidence: 59%

Section: Post-riphean Source Rocksmentioning

confidence: 99%

Section: Post-riphean Source Rocksmentioning

confidence: 99%

Section: Amgamentioning

confidence: 99%

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Bitumen Resources of the East Siberian Basin

Liu

Blackbourn²,

Zhixing

et al. 2023

Journal of Petroleum Geology

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“…The content of naphthalene is higher in shale oil from the Domanic rocks of the Berezovskaya area, in contrast to the oil from carbonate rocks of the Zelenogorskaya area (25.14 vs. 18.01%). In [61], the possible ways of phenanthrene formation-biomarkers in OM of rocks and crude oils-are discussed. It is shown that such molecules can play a role of "secondary" biomarkers in shale oils generated by dispersed organic matter of different facies and ages.…”

Section: Zelenogorskaya Area Berezovskaya Areamentioning

confidence: 99%

Composition of Oil after Hydrothermal Treatment of Cabonate-Siliceous and Carbonate Domanic Shale Rocks

et al. 2021

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The hydrocarbon compositions of shale oils, generated from two different lithological–facial Domanic deposits of the Tatarstan Republic (Russia), were studied under hydrothermal impact with 30% of water addition in a 350 °С and CO2 environment. The samples were extracted from carbonate–siliceous rocks of the Semiluky–Mendym deposits of the Berezovskaya area, and carbonate deposits of the Dankovo–Lebedyan horizon of the Zelenogorskaya area of the Romashkino oil field. The distinctive features of rocks are in the composition and content of organic matter (OM), its thermal stability, as well as the structural-group composition of the shale oil products. The hydrothermal treatment of the rock samples increased the content of saturates and decreased the content of aromatics, resins and asphaltenes in the composition of crude oil. The decomposition of the polymer-like kerogen structure and destruction processes of high-molecular compounds, such as resins and asphaltenes, are accompanied with the formation of substances highly rich in carbons—carbenes and carboids. The contents of n-alkanes and acyclic isoprenoids increase in the composition of saturated hydrocarbons. According to the chemical classification of Al. A. Petrov, the character of the molecular mass distribution of such substances corresponds to oil type A1, which is considered paraffinic. The contents of dibenzothiophene, naphthalene and phenanthrene are increased in the composition of aromatic hydrocarbons, while the contents of tri-methyl-alkyl-benzene and benzothiophene are decreased. The increase in the aryl isoprenoid ratio (AIR = С13–С17/С18–С22) and maturity parameter (4-MDBT/1-MDBT) under the influences of hydrothermal factors indicates the increasing thermal maturity degree of the hydrocarbon system. The differences in the distribution behavior of saturated and aromatic hydrocarbons—biomarkers in rocks of various lithological-facies types, which are reasoned by different conditions of initial organic matter transformation as well as under the impact of hydrothermal factors—were revealed.

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