Application of integrated vitrinite reflectance and FAMM analyses for thermal maturity assessment of the northeastern Malay Basin, offshore Vietnam: Implications for petroleum prospectivity evaluation

Petersen, Henrik I.; Sherwood, Neil; Mathiesen, Anders; Fyhn, Michael B.W.; Dau, Nguyen T.; Russell, Nigel J.; Bojesen‐Koefoed, Jørgen A.; Nielsen, Lars Henrik

doi:10.1016/j.marpetgeo.2008.04.004

Cited by 28 publications

(7 citation statements)

References 29 publications

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“…Therefore, it is suggested that R o suppression is a misnomer in these upper Paleozoic marine-shale petroleum systems. Vitrinitereflectance suppression also is widely reported from shale of other geologic ages (Mesozoic-Cenozoic) and from other depositional environments including fluvial-deltaic to lacustrine settings (Fatimah and Ward, 2009;Petersen et al, 2009;Wilkins et al, 2015;Schito et al, 2016). The wide range in age (Cambrian-Ordovician to Miocene) of the shales used in this study in which BR o consistently shows lower response to thermal stress than does R o suggests that our work has application to a broader array of settings and ages, such as those mentioned above.…”

Section: Discussionsupporting

confidence: 62%

Understanding and distinguishing reflectance measurements of solid bitumen and vitrinite using hydrous pyrolysis: Implications to petroleum assessment

Hackley

Lewan

2018

Bulletin

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Solid bitumen is a common organic component of thermally mature shales and typically is identified by embayment against euhedral mineral terminations and by groundmass textures. However, because these textures are not always present, solid bitumen can be easily misidentified as vitrinite. Hydrous-pyrolysis experiments (72 hr, 300°C-360°C) on shale and coal samples show that solid-bitumen reflectance (BR o) in shales is less responsive to thermal stress than vitrinite reflectance (R o) in coal. This effect is most pronounced at lower experimental temperatures (300°C-320°C), whereas reflectance changes are more similar at higher temperatures (340°C-360°C). Neither a "vitrinitelike" maceral nor "suppressed vitrinite" was identified or measured in our sample set; instead, the experiments show that solid bitumen matures slower than vitrinite. The data may explain some reports of "R o suppression," particularly at lower thermal maturity (R o £ 1.0%), as a simple case of solid bitumen being mistaken for vitrinite. Further, the experimental results confirm previous empirical observations that R o and BR o are more similar at higher maturities (R o > 1.0%). It is suggested that R o suppression, commonly reported from upper Paleozoic marine shales of early to midoil window maturity, is a misnomer. This observation has important implications to petroleum exploration models and resource assessment, because it may change interpretations for the timing and spatial locations of kerogen maturation and petroleum generation.

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Section: Discussionsupporting

confidence: 62%

Understanding and distinguishing reflectance measurements of solid bitumen and vitrinite using hydrous pyrolysis: Implications to petroleum assessment

Hackley

Lewan

2018

Bulletin

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“…1D modelling of hydrocarbon generation using custom kinetics was performed on eleven immature oil shales using PetroMod software (Integrated Exploration Systems GmbH, Aachen, Germany). The Vietnamese Malay-Cho Thu Basin in the Gulf of Thailand/South China Sea was used as a case study of a lacustrine-sourced petroleum system (Petersen et al, 2009). A well-constrained temperature history has been derived for the basin by establishing a reliable thermal maturity gradient using a combination of conventional vitrinite reflectance measurements and "equivalent VR" (EqVR) values derived from the fluorescence alteration of multiple macerals (FAMM) technique (Petersen et al, 2009).…”

Section: Methodsmentioning

confidence: 99%

“…7 shows modelled transformation ratios (TR) of 11 of the studied oil shales with largely similar thermal maturity using custom kinetics (E a -distributions and A-factors; Fig. 2; Table 4) and the temperature and subsidence histories of the Malay-Cho Thu Basin in the Gulf of Thailand/South China Sea (Petersen et al, 2009). The Type I kerogen of Pepper and Corvi (1995) (corresponding to their non-marine Organofacies C) is included for comparison.…”

Section: Effect Of Different Kinetics On Hydrocarbon Generationmentioning

confidence: 99%

Variations in Composition, Petroleum Potential and Kinetics of Ordovician – Miocene Type I and Type I‐ii Source Rocks (Oil Shales): Implications for Hydrocarbon Generation Characteristics

Petersen

Bojesen‐Koefoed

Mathiesen

2009

Journal of Petroleum Geology

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Lacustrine and marine oil shales with Type I and Type I-II kerogen constitute significant petroleum source rocks around the world. Contrary to common belief, such rocks show considerable compositional variability which influences their hydrocarbon generation characteristics. A global set of 23 Ordovician -Miocene freshwater and brackish water lacustrine and marine oil shales has been studied with regard to their organic composition, petroleum potential and generation kinetics. In addition their petroleum generation characteristics have been modelled. The oil shales can be classified as lacosite, torbanite, tasmanite and kukersite. They are thermally immature. Most of the shales contain >10 wt% TOC and the highest sulphur contents are recorded in the brackish water and marine oil shales. The kerogen is sapropelic and is principally . The kerogen type and source rock quality appear not to be related to age, depositional environment or oil shale type. Therefore, a unique, global activation energy (E a ) distribution and frequency factor (A) for these source rocks cannot be expected. The differences in kerogen composition result in considerable variations in E a -distributions and A-factors. Generation modelling using custom kinetics and the known subsidence history of the Malay-Cho Thu Basin (Gulf of Thailand/South China Sea), combined with established and hypothetical temperature histories, show that the oil shales decompose at different rates during maturation. At a maximum temperature of ~120ºC reached during burial, only limited kerogen conversion has taken place. However, oil shales characterised by broader E a -distributions with low E a -values (and a single approximated A-factor) show increased decomposition rates. Where more deeply buried (maximum temperature ~150ºC), some of the brackish water and marine oil shales have realised the major part of their generation potential, whereas the freshwater oil shales and other brackish water oil shales are only ~30-40% converted. At still higher temperatures between ~165ºC and 180ºC all oil shales reach 90% conversion. Most hydrocarbons from these source rocks will be generated within narrow oil windows (~20-80% kerogen conversion). Although the brackish water and marine oil shales appear to decompose faster than the freshwater oil shales, this

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“…These authors proposed the kinetic EASY%R algorithm that permits the comparison of measured and calculated vitrinite reflectance values and thus the effective calibration of the thermal and burial histories. This model has been used (e.g.,) by Hertle and Littke (2000); Petersen et al (2009). Carr (2003 noticed that in overpressure systems a pressure-dependent kinetic model should be used for modeling.…”

Section: Basin Analysismentioning

confidence: 99%

Organic Petrology: An Overview

Suárez-Ruiz¹

2012

Petrology - New Perspectives and Applications

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Application of integrated vitrinite reflectance and FAMM analyses for thermal maturity assessment of the northeastern Malay Basin, offshore Vietnam: Implications for petroleum prospectivity evaluation

Cited by 28 publications

References 29 publications

Understanding and distinguishing reflectance measurements of solid bitumen and vitrinite using hydrous pyrolysis: Implications to petroleum assessment

Understanding and distinguishing reflectance measurements of solid bitumen and vitrinite using hydrous pyrolysis: Implications to petroleum assessment

Variations in Composition, Petroleum Potential and Kinetics of Ordovician – Miocene Type I and Type I‐ii Source Rocks (Oil Shales): Implications for Hydrocarbon Generation Characteristics

Organic Petrology: An Overview

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