Hydrocarbons from non-marine source rocks

Bjorøy, Malvin; Hall, P. B.; Löberg, Rita; McDermott, Josephine Ann; Mills, N. J.

doi:10.1016/0146-6380(88)90042-3

Cited by 21 publications

(5 citation statements)

References 21 publications

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“…Terrigenous Miocene delta-plain coals and shales have generated oil and gas in the Mahakam Delta, Indonesia (e.g. Bjorøy et al, 1988, Peters et al, 2000. Obaje and Hamza (2000) and Obaje et al (2004) discussed the generation of petroleum from Cretaceous coals in the Middle Benue Trough and the Gongola Basin (Upper Benue Trough), onshore Nigeria.…”

Section: Oil From Coalsmentioning

confidence: 99%

Oil‐prone Lower Carboniferous Coals in the Norwegian Barents Sea: Implications for a Palaeozoic Petroleum System

Koeverden

Karlsen

Schwark

et al. 2010

Journal of Petroleum Geology

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In this study, we assess the oil generation potential of Lower Carboniferous, liptinite-rich coals in the Tettegras Formation on the Finnmark Platform, southern Norwegian Barents Sea. Oil from these coals has been expelled into intercalated sandstones. The coals may have contributed to petroleum recorded in well 7128/4-1 on the Finnmark Platform and may constitute a new Palaeozoic source rock in the Barents Sea.The Tettegras Formation coals contain up to 80 vol. % liptinite (mineral matter free base) and have low oxygen indices. Hydrogen indices up to 367 mg HC/g TOC indicate liquid hydrocarbon potential. In wells 7128/4-1 and 7128/6-1, the coals have vitrinite reflectance R o = 0.75-0.85 %. Compared to shale and carbonate source rocks, expulsion from coal in general begins at higher maturities (R o = 0.8-0.9% and T max = 444-453°C). Thus, the coals in the wells are mostly immature with regard to oil expulsion. The oil in well 7128/4-1 most likely originates from a more mature part of the Tettegras Formation in the deeper northern part of the Finnmark Platform. Wide variations in biomarker facies parameters and δ 13 C isotope values indicate a heterogeneous paralic depositional setting. The preferential retention by coal strata of naphthenes (e.g. terpanes and steranes) and aromatic compounds, compared to n-alkanes and acyclic isoprenoids, results in a terrigenous and waxy oil. This oil however contains marine biomarkers derived from the intercalated shales and siltstones. It is therefore important to consider the entire coal-bearing sequence, including the intercalated shales, in terms of source rock potential.Coals of similar age occur on Svalbard and Bjørnøya. The results of this study therefore suggest that a Lower Carboniferous coaly source rock may extend over large areas of the Norwegian Barents Sea. This source rock is mature in areas where the otherwise prolific Upper Jurassic marine shales are either immature or missing and may constitute a new Palaeozoic coal-sourced petroleum system in the Barents Sea.

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Section: Oil From Coalsmentioning

confidence: 99%

Oil‐prone Lower Carboniferous Coals in the Norwegian Barents Sea: Implications for a Palaeozoic Petroleum System

Koeverden

Karlsen

Schwark

et al. 2010

Journal of Petroleum Geology

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“…These controls influence the isoprenoid to n-alkane ratios in a similar manner. No preferential expulsion for pr or ph is discerned, but rather their presence in the expelled bitumen supports early generation and expulsion (Bjorøy et al, 1988;Krooss and Hanebeck, 1993). Although n-alkanes up to n-C 20 are strongly affected by evaporative fractionation under the experimental temperature conditions of 350°C, this does not increase the isoprenoid to n-alkane ratio because, for example, n-C 17 has a higher thermal stability than pristane.…”

Section: Composition Of the Expelled Hydrocarbonsmentioning

confidence: 95%

Experimental investigation of the compositional variation of acyclic paraffins during expulsion from source rocks

Eseme

Littke

Krooß

et al. 2006

Journal of Geochemical Exploration

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“…Pyrolysis-gas chromatography and hydrous pyrolysis of Mae Sot and Mae Moh oil shales yield n-alkanes up to about C 27-30 indicating their ability to generate waxy oil (Bjorøy et al, 1988). Oil shales containing Botryococcus-type alginite and terrestrial liptinite seem to generate a larger amount of C 20+ n-alkanes (Bjorøy et al, 1988;Petersen et al, 2004). Lacustrine conditions are further indicated from the low C 31 22R/ C 30 hopane ratios, the presence of 28-Nor-spergulane, T26/T25 (tricyclic triterpanes) ratios of 1.07-1.57, and TTP ratios close to 1.…”

Section: Origin Of the Oilsmentioning

confidence: 99%

Oils From Cenozoic Rift‐basins in Central and Northern Thailand: Source and Thermal Maturity

Petersen

Nytoft

Ratanasthien

et al. 2007

Journal of Petroleum Geology

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Oil is produced from the Suphan Buri, Phitsanulok and Fang Basins onshore central and northern Thailand. Most of the Cenozoic rift‐basins onshore Thailand are 2–4 km deep, but the Phitsanulok Basin is the deepest with a basin‐fill up to 8 km thick. In this basin, the Sirikit field produces ∼18,000–24,000 bbl/day of crude oil. In the Suphan Buri Basin, about 400 bbl/day of crude oil is produced from the U Thong and Sang Kajai fields. Approximately 800 bbl/day of crude oil is produced from the Fang field (Fang Basin), which in reality consists of a number of minor structures including Ban Thi, Pong Nok, San Sai, Nong Yao and Mae Soon. A total of eight oil samples were collected from these structures and from the Sirikit, U Thong and Sang Kajai fields. The oils were subjected to MPLC and HPLC separation and were analysed by gas chromatography (GC) and gas chromatography‐mass spectrometry (GC‐MS and GC‐MS‐MS). The U Thong oil was investigated in more detail by separating the oil into a number of fractions suited for the analysis of various specific compounds. The Sirikit oil appears to be the most mature, whereas the Suphan Buri oils and the oil from the San Sai structure (Fang Basin) are the least mature. Apart from the San Sai oil, the other oils in the Fang Basin are of similar maturity. The oils contain small amounts of asphaltenes and the asphaltene‐free fractions are completely dominated by saturated hydrocarbons (generally >60%). Long‐chain n‐alkanes extend to at least C40 and the oils are thus highly waxy. In general the oils were generated from freshwater lacustrine source rocks containing a large proportion of algal material, as indicated by the presence of long‐chain n‐alkanes, low C3122R/C30 hopane ratios, the presence of 28‐Nor‐spergulane, T26/T25 (tricyclic triterpanes) ratios of 1.07–1.57 and tetracyclic polyprenoid (TTP) ratios close to 1. Occasional saline conditions may have occurred during deposition of the Sirikit, Ban Thi and Pong Nok source rocks. The Fang Basin oils were sourced from two different kitchens, one feeding the Ban Thi and Pong Nok structures and one feeding the Mae Soon, Nong Yao and San Sai structures. The presence ofcadalene, tetracyclic C24 compounds, oleanane, lupane, bicadinane and trace amounts ofnorpimarane or norisopimarane indicate a contribution from higher land plant organic matter to the oils. The terrestrial organic matter may occur disseminated in the lacustrine facies or concentrated in coal seams associated with the lacustrine mudstones. Thermally immature oil shales (lacustrine mudstones) and coals exposed in numerous basins in central and northern Thailand could upon maturation generate oils with a composition comparable to the investigated oils.

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Hydrocarbons from non-marine source rocks

Cited by 21 publications

References 21 publications

Oil‐prone Lower Carboniferous Coals in the Norwegian Barents Sea: Implications for a Palaeozoic Petroleum System

Oil‐prone Lower Carboniferous Coals in the Norwegian Barents Sea: Implications for a Palaeozoic Petroleum System

Experimental investigation of the compositional variation of acyclic paraffins during expulsion from source rocks

Oils From Cenozoic Rift‐basins in Central and Northern Thailand: Source and Thermal Maturity

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