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Oil Shales (oil + shale)

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Earth and Environmental Science	84%

Selected Abstracts

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]

Investigation of mineral composition of oil shale

ASIA-PACIFIC JOURNAL OF CHEMICAL ENGINEERING, Issue 5 2009
Dong-Mei Wang
Abstract The aim of this paper is to identify the mineral composition of oil shale from different locations and relate it to their interval of occurrence. Thermogravimetric analysis (TGA), diffuse reflectance infrared Fourier transforms spectroscopy (DRIFTS) and X-ray diffraction (XRD) methods were used for this invetigation. Hydrogen peroxide was used as the oxidant to eliminate the influence of organic matter in TGA. DRIFTS results indicated that most of the kerogen is in aliphatic hydrocarbon form and the peak of hydrocarbon nearly disappeared after oxidation. XRD results indicated that quartz, muscovite, kaolinite and calcite are the dominant minerals. Longkou and Changchun oil shale samples contain high percentage of calcite (12.9 and 11.7% CO2 respectively) while Fushun and Huadian oil shale samples contain less than 6% CO2. Especially, in Fushun oil shale sample, the content is below 3%. Kaolinite is found in Fushun oil shale sample, while muscovite is only found in Huadian oil shale sample. Integration of the XRD, DRIFTS and TGA results of the oil shale samples from different locations has provided a better way of mineral composition identification. Copyright © 2009 Curtin University of Technology and John Wiley & Sons, Ltd. [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

OILS FROM CENOZOIC RIFT-BASINS IN CENTRAL AND NORTHERN THAILAND: SOURCE AND THERMAL MATURITY

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2007
H.I. Petersen
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. [source]

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

THE NATURE AND ORIGIN OF PETROLEUM IN THE CHAIWOPU SUB-BASIN (JUNGGAR BASIN), NW CHINA

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2000
H. P. Huang
The Chaiwopu Sub-basin is a minor extension of the Junggar Basin, hW China, and covers an area of about 2,500 sq. km. It is bounded to the east and north by the Bogda Shan and to the south by the Tian Shan ("Shan" meaning "mountains" in Chinese). Four wells have been drilled in the sub-basin; condensate and gas have been produced in noncommercial quantities at one of the wells (Well C), but the other three wells were dry. In this paper, I investigate the nature and origin of the petroleum at Well C. Three of the four wells in the Chaiwopu Sub-basin penetrated the Upper Permian Lucaogou Formation. Previous studies in the Junggar Basin have established that laminated lacustrine mudstones assigned to this formation comprise a very thick high quality source rock. However, the analysis of cores from wells in the sub-basin shows that the Lucaogou Formation is composed here of shallow lacustrine, fluvial and alluvial deposits which have very low petroleum generation potential. Overlying sediments (Upper Permian, Triassic and younger strata) likewise have little source potential. Around 1,000 m of Upper Permian laminated oil shales crop out at Dalongkou and Tianchi on the northern side of the Bogda Shan. On the southern side of the Bogda Shan, however, only 30 m of Upper Permian oil shales occur at Guodikong. Shales and oil seeps from these locations were analysed using standard organic-geochemical techniques. The physical properties of the petroleum present at Well C, and its carbon isotope and biomarker characteristics, suggest that it has migrated over long distances from its source rock, although an alternative explanation for its origin is not precluded. Burial history modelling indicates that hydrocarbon generation and migration may have occurred before the uplift of the Bogda Shan in the Late Jurassic,Early Cretaceous, the orogenic episode which resulted in the diflerentiation of the Chaiwopu Sub-basinfrom the Junggar Basin. [source]

Sedimentation History of Neogene Lacustrine Sediments of Su,eo,ka Bela Stena Based on Geochemical Parameters (Valjevo-Mionica Basin, Serbia)

ACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 6 2008
AJNOVI, Aleksandra
Abstract: Sediments of the western part of the Valjevo-Mionica basin (Serbia) were examined both geochemically and mineralogically to explain, on the basis of their sedimentological characteristics, the causes of changes in their qualitative and quantitative composition. A total of 62 samples obtained from the drillhole at depths up to 400 m was investigated. Using correlation of the obtained data, six geochemical zones were defined, two of which being specially distinguished by their mineralogical, geochemical and sedimentological characteristics. The first one, upper zone A, consists of banded marlstones interbedded with clay and oil shales and is characterized by presence of analcite and searlesite. These minerals and very high contents of Na2O indicate sedimentation in alkaline conditions with increased salinity in arid climate. That provided pronounced water stratification, as well as higher bioproductivity in the basin and sedimentary organic matter preservation. Therefore, the zone A sediments are characterized by high organic matter contents of the type which provides good potential for production of liquid hydrocarbons. Another specific zone, zone F, contains sediments with very high MgO, K2O and Li concentrations. Their geochemical correlation, as well as almost complete absence of illite in this zone, indicates the presence of interstratified clay mineral type illite-saponite (lithium-bearing Mg-smectite). [source]