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PETROLEUM POTENTIAL (petroleum + potential)

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Earth and Environmental Science100%

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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

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2010
H. I. Petersen
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 composed of a complex of algal-derived organic matter in the form of: (i) telalginite (Botryococcus-, Prasinophyte- (Tasmanites?) or Gloeocapsomorpha-type); (ii) lamalginite (laminated, filamentous or network structure derived from Pediastrum- or Tetraedron-type algae, from dinoflagellate/acritarch cysts or from thin-walled Prasinophyte-type algae); (iii) fluorescing amorphous organic matter (AOM) and (iv) liptodetrinite. High atomic H/C ratios reflect the hydrogen-rich Type I and Type I-II kerogen, and Hydrogen Index values generally >300 mg HC/g TOC and reaching nearly 800 mg HC/g TOC emphasise the oil-prone nature of the oil shales. 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 (Ea) distribution and frequency factor (A) for these source rocks cannot be expected. The differences in kerogen composition result in considerable variations in Ea -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 ,120°C reached during burial, only limited kerogen conversion has taken place. However, oil shales characterised by broader Ea -distributions with low Ea -values (and a single approximated A-factor) show increased decomposition rates. Where more deeply buried (maximum temperature ,150°C), 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 ,165°C and 180°C 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 suggests that with increasing heatflow the influence of kerogen heterogeneity on modelling of hydrocarbon generation declines. It may thus be critical to understand the organic facies of Type I and Type I-II source rocks, particularly in basins with moderate heatflows and restricted burial depths. Measurement of custom kinetics is recommended, if possible, to increase the accuracy of any computed hydrocarbon generation models. [source]

PETROLEUM POTENTIAL, THERMAL MATURITY AND THE OIL WINDOW OF OIL SHALES AND COALS IN CENOZOIC RIFT BASINS, CENTRAL AND NORTHERN THAILAND

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2006
H. I. Petersen
Oil shales and coals occur in Cenozoic rift basins in central and northern Thailand. Thermally immature outcrops of these rocks may constitute analogues for source rocks which have generated oil in several of these rift basins. A total of 56 oil shale and coal samples were collected from eight different basins and analysed in detail in this study. The samples were analysed for their content of total organic carbon (TOC) and elemental composition. Source rock quality was determined by Rock-Eval pyrolysis. Reflected light microscopy was used to analyse the organic matter (maceral) composition of the rocks, and the thermal maturity was determined by vitrinite reflectance (VR) measurements. In addition to the 56 samples, VR measurements were carried out in three wells from two oil-producing basins and VR gradients were constructed. Rock-Eval screening data from one of the wells is also presented. The oil shales were deposited in freshwater (to brackish) lakes with a high preservation potential (TOC contents up to 44.18 wt%). They contain abundant lamalginite and principally algal-derived fluorescing amorphous organic matter followed by liptodetrinite and telalginite (Botryococcus-type). Huminite may be present in subordinate amounts. The coals are completely dominated by huminite and were formed in freshwater mires. VR values from 0.38 to 0.47%Ro show that the exposed coals are thermally immature. VR values from the associated oil shales are suppressed by 0.11 to 0.28%Ro. The oil shales have H/C ratios >1.43, and Hydrogen Index (HI) values are generally >400 mg HC/g TOC and may reach 704 mg HC/ gTOC. In general, the coals have H/C ratios between about 0.80 and 0.90, and the HI values vary considerably from approximately 50 to 300 mg HC/gTOC. The HImax of the coals, which represent the true source rock potential, range from ,160 to 310 mg HC/g TOC indicating a potential for oil/gas and oil generation. The steep VR curves from the oil-producing basins reflect high geothermal gradients of ,62°C/km and ,92°C/km. The depth to the top oil window for the oil shales at a VR of ,0.70%Ro is determined to be between ,1100 m and 1800 m depending on the geothermal gradient. The kerogen composition of the oil shales and the high geothermal gradients result in narrow oil windows, possibly spanning only ,300 to 400 m in the warmest basins. The effective oil window of the coals is estimated to start from ,0.82 to 0.98%Ro and burial depths of ,1300 to 1400 m (,92°C/km) and ,2100 to 2300 m (,62°C/km) are necessary for efficient oil expulsion to occur. [source]

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

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2010
H. I. Petersen
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 composed of a complex of algal-derived organic matter in the form of: (i) telalginite (Botryococcus-, Prasinophyte- (Tasmanites?) or Gloeocapsomorpha-type); (ii) lamalginite (laminated, filamentous or network structure derived from Pediastrum- or Tetraedron-type algae, from dinoflagellate/acritarch cysts or from thin-walled Prasinophyte-type algae); (iii) fluorescing amorphous organic matter (AOM) and (iv) liptodetrinite. High atomic H/C ratios reflect the hydrogen-rich Type I and Type I-II kerogen, and Hydrogen Index values generally >300 mg HC/g TOC and reaching nearly 800 mg HC/g TOC emphasise the oil-prone nature of the oil shales. 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 (Ea) distribution and frequency factor (A) for these source rocks cannot be expected. The differences in kerogen composition result in considerable variations in Ea -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 ,120°C reached during burial, only limited kerogen conversion has taken place. However, oil shales characterised by broader Ea -distributions with low Ea -values (and a single approximated A-factor) show increased decomposition rates. Where more deeply buried (maximum temperature ,150°C), 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 ,165°C and 180°C 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 suggests that with increasing heatflow the influence of kerogen heterogeneity on modelling of hydrocarbon generation declines. It may thus be critical to understand the organic facies of Type I and Type I-II source rocks, particularly in basins with moderate heatflows and restricted burial depths. Measurement of custom kinetics is recommended, if possible, to increase the accuracy of any computed hydrocarbon generation models. [source]

Origin of Crude Oil in the Lunnan Region, Tarim Basin

ACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 5 2010
LI Sumei
Abstract: The oil source of the Tarim Basin has been controversial over a long time. This study characterizes the crude oil and investigates the oil sources in the Lunnan region, Tarim Basin by adopting compound specific isotopes of n -alkanes and biomarkers approaches. Although the crude oil has a good correlation with the Middle-Upper Ordovician (O2+3) source rocks and a poor correlation with the Cambrian-Lower Ordovician (,-O1) based on biomarkers, the ,13C data of n -alkanes of the Lunnan oils show an intermediate value between ,-O1 and O2+3 genetic affinity oils, which suggests that the Lunnan oils are actually of an extensively mixed source. A quantification of oil mixing was performed and the results show that the contribution of the Cambrian-Lower Ordovician source rocks ranges from 11% to 70% (averaging 36%), slightly less than that of the Tazhong uplift. It is suggested that the inconsistency between the biomarkers and ,13C in determining the oil sources in the Lunnan Region results from multiple petroleum charge episodes with different chemical components in one or more episode(s) and different sources. The widespread marine mixed-source oil in the basin indicates that significant petroleum potential in deep horizons is possible. To unravel hydrocarbons accumulation mechanisms for the Lunnan oils is crucial to further petroleum exploration and exploitation in the region. [source]