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Oil Window (oil + window)
Selected AbstractsPETROLEUM POTENTIAL, THERMAL MATURITY AND THE OIL WINDOW OF OIL SHALES AND COALS IN CENOZOIC RIFT BASINS, CENTRAL AND NORTHERN THAILANDJOURNAL OF PETROLEUM GEOLOGY, Issue 4 2006H. 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] Generation and accumulation of oil and condensates in the Wenchang A Sag, western Pearl River Mouth Basin, South China SeaGEOFLUIDS (ELECTRONIC), Issue 4 2009H. J. GAN Abstract The Pearl River Mouth (PRM) Basin is one of four Cenozoic basins in the South China Sea, and the Wenchang A Sag is a secondary depression in the western part of the basin. Both the Wenchang and Enping formations contain good source rocks in the western PRM Basin; however, only the latter has been considered a likely source of the discovered oil and gas. New data from fluid inclusions and the analysis of oil,source rock correlations for the WC10-3 oil and gas pools indicate two stages of petroleum charging, the earlier originating from the Wenchang Formation and the later from the Enping Formation. Kinetics of petroleum generation and structural evolution modeling were employed to further investigate the mechanism of formation of the WC10-3 oil and gas pools. It was shown that the crucial condition for the formation of pools is the time of development of the structural trap. The Wenchang Formation source rocks generated oil from 25 to 14 Ma in the possible source area of the WC10-3 oil and gas pools in the Wenchang A Sag, so that only traps formed earlier than this period could capture oil sourced by the Wenchang Formation. The Enping Formation source rock experienced its oil window from 18 Ma to the present with the main stage of oil generation from 15 to 5 Ma. During this period structural traps in the sag continued to form until movements became weak, so that most pools in the Wenchang A Sag originated from the Enping Formation source rock. The likely dissipation of oil and gas from the earlier stage of charging should be taken into account in assessing the oil potential of the Wenchang A Sag. [source] HIGHER PLANT BIOMARKERS IN PALEOGENE CRUDE OILS FROM THE YUFUTSU OIL-AND GASFIELD AND OFFSHORE WILDCATS, JAPANJOURNAL OF PETROLEUM GEOLOGY, Issue 4 2006S. Yessalina Geochemical investigation of Paleogene oils from the onshore Yufutsu oil- and gasfield, southern Hokkaido, and from two nearby offshore wells, revealed the presence of numerous biomarkers of higher plant origin. Biomarkers in the oils belong to different groups of both angiosperm and gymnosperm origin; they include bicyclic sesquiterpanes, diterpanes, and triterpanes and their aromatized counterparts, which suggests a terrestrial origin for the oils. The oils were characterized as having a high wax content, a low content of organosulphur compounds, a high pristane/phytane ratio, and a low C27/(C27+C29) sterane ratio. Although the oils from on- and offshore Southern Hokkaido are similar in their geochemical composition, notable differences were observed in the biomarker signature of both saturate and aromatic fractions. The oils from the offshore wells appeared to have a greater abundance of higher plant biomarkers compared to those from the Yufutsu field, suggesting an enrichment in higher plant components. Differences in biomarker fingerprint could not be linked to the maturity effect, since the oils appeared to be of similar maturity levels, corresponding to the late stage of the oil window (0.9,1.2%, Rc). The differences in the biomarker signatures between the oils from the Yufutsu field and the offshore wells are likely to be due to facies variations in source organic matter, resulting from differences in the quantity and quality of land plant input. [source] PETROLEUM POTENTIAL, THERMAL MATURITY AND THE OIL WINDOW OF OIL SHALES AND COALS IN CENOZOIC RIFT BASINS, CENTRAL AND NORTHERN THAILANDJOURNAL OF PETROLEUM GEOLOGY, Issue 4 2006H. 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] THE PALEOCENE SANDY SIRI FAIRWAY: AN EFFICIENT "PIPELINE" DRAINING THE PROLIFIC CENTRAL GRABEN?JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2006S.E. Ohm A new petroleum charge model is presented for the sand-dominated Paleocene channel system known as the Siri Fairway in the Central Graben of the North Sea. The Siri Fairway is located in the platform area along the Danish - Norwegian border and extends from the Norwegian palaeo shelf into the Tail-End Graben and Søgne Basin. The nearest known expelling source rocks are located in the Central Graben. The discovery of the Siri oilfield and later the Cecilie and the Nini fields proves that petroleum has migrated through these Paleocene sandstones for up to 70 km, which is a considerable distance in the North Sea. If the Siri Fairway has acted as a "pipeline" for petroleum migrating from the Graben to the platform area, the chemical composition of the hydrocarbons discovered in the Graben and within the Fairway itself should be similar in terms of maturity and organic facies signature. This study shows this not to be the case. The Graben oils have a mature signature, whereas the oils from the Siri field have an early mature signature and are mixed with biogenic gas generated in situ. The biogenic gas "signature", which was inherited from gas which accumulated in the trap before the arrival of the oil charge, should have disappeared if petroleum had continuously been introduced to the Fairway. It therefore appears that hydrocarbon charging to the Fairway ceased for some reason before the source rocks in the Graben entered the main oil window; the Siri Fairway therefore represents an aborted migration route, and limited charging of the Paleocene sandstone deposits in the platform has occurred. The chemical composition of the oils from the Siri field indicates that the Fairway was charged from two different basins with different subsidence histories. The Siri-2 trap is thus interpreted to have been filled with the same oil as that found in Siri-1 and Siri-3, but this oil was later partly displaced by oil generated in a shallower sub-basin. The sandstones in the Siri Fairway were deposited as turbidites and/or gravity slides in the Late Paleocene, and consist of stacked interfingering sandstone lobes which are encased to varying degrees in fine-grained sediments. Although long distance migration through the sandstones has been proved to occur, connectivity between individual sandlobes may be problematic. The number of dry wells drilled in the Fairway and the early-mature character of the analysed oils, together with the general absence of more mature later petroleum, indicate that migration routes in this region are limited and difficult to predict. [source] BURIAL HISTORY RECONSTRUCTION AND THERMAL MODELLING AT KUH-E MOND, SW IRANJOURNAL OF PETROLEUM GEOLOGY, Issue 4 2003M. R. Kamali At the Kuh-e Mond anticline (Fars Province, SW Iran) and in nearby offshore structures, large volumes of natural gas are reservoired in the Permian , Early Triassic Dehram Group while heavy oil has been discovered in the Cretaceous Sarvak and Eocene Jahrum Formations. In this paper, we use data from six exploration wells and from nearby surface exposures to reconstruct the burial history at Kuh-e Mond. Regional observations show that the thick sedimentary fill in this part of the Zagros Basin was subjected to intense tectonism during the Zagros Orogeny, with a paroxysmal phase during the late Miocene and Pliocene. Thermal modelling and geochemical data from Kuh-e Mond and adjacent fields allows possible hydrocarbon generation and migration mechanisms to be identified. Maturities predicted using Lopatin's TTI model are in accordance with maturities obtained from vitrinite reflectance measurements. We show that formations which have source potential in the nearby Dezful Embayment (including the Pabdeh, Gurpi, Gadvan and Kazhdumi Formations) have not reached the oil window in the Mond wells. Moreover, their organic carbon content is very low as they were deposited in oxic, shallow-water settings. Underlying units (including the Ordovician and Cambrian) could have reached the gas window but contain little organic matter. Silurian shales (Sarchahan Formation), which generate gas at Kuh-e Gahkum and Kuh-e Faraghan (north of Bandar Abbas) and in Saudi Arabia and elsewhere in the Middle East, are absent from the Mond structure. The absence of source rocks suggests that the gas and heavy oil accumulations at Kuh-e Mond and at nearby fields have most probably undergone long-distance lateral migration from distant source kitchens. [source] SOURCE ROCK EVALUATION AND GEOCHEMISTRY OF CONDENSATES AND NATURAL GASES, OFFSHORE NILE DELTA, EGYPTJOURNAL OF PETROLEUM GEOLOGY, Issue 2 2003L. M. Sharaf Geochemical analyses of mudstones from wells in the NE offshore Nile Delta suggest that the Early Miocene Qantara Formation has "good" potential to generate hydrocarbons at the studied locations. Its generating capability and oil-proneness increase northwards, towards areas where better organic-matter preservation and a greater contribution from marine source material can be expected. By contrast, the Middle Miocene Sidi Salem Formation has "poor to fair" potential to generate mixed gas and oil, while the overlying Wakar and Kafr El Sheikh Formations have "poor" capability to generate gas with minor oil. Based on pyrolysis Tmax and thermal alteration index assessments, the Wakar and Kafr El Sheikh Formations are immature in the study area. The Sidi Salem and Qantara Formations are immature in the southern part of the study area, but are within the oil window in the north, around well Temsah-4. Biomarker distributions based on GC-MS analyses of two condensate samples from the Wakar and Sidi Salem Formations indicate that hydrocarbons are derived from siliciclastic source rocks containing significant terrestrial material and limited marine organic matter. The condensates were generated during early maturation of Type III kerogen from deeper and more mature source rocks than those encountered in the drilled wells. Geochemical and isotopic data from natural gas produced from the Kafr El Sheikh Formation suggest mixed biogenic and thermogenic sources. [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 CHARACTERISTICSJOURNAL OF PETROLEUM GEOLOGY, Issue 1 2010H. 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 THAILANDJOURNAL OF PETROLEUM GEOLOGY, Issue 4 2006H. 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] | ||||||||||