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Source Rocks (source + rock)
Kinds of Source Rocks Selected AbstractsVARIATIONS 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] DISTRIBUTION OF SOURCE ROCKS AND MATURITY MODELLING IN THE NORTHERN CENOZOIC SONG HONG BASIN (GULF OF TONKIN), VIETNAMJOURNAL OF PETROLEUM GEOLOGY, Issue 2 2005C. Andersen The northern offshore part of the Cenozoic Song Hong Basin in the Gulf of Tonkin (East Vietnam Sea) is at an early stage of exploration with only a few wells drilled. Oil to source rock correlation indicates that coals are responsible for the sub-commercial oil and gas accumulations in sandstones in two of the four wells which have been drilled on faulted anticlines and flower structures. The wells are located in a narrow, structurally inverted zone with a thick predominantly deltaic Miocene succession between the Song Chay and Vinh Ninh/Song Lo fault zones. These faults are splays belonging to the offshore extension of the Red River Fault Zone. Access to a database of 3,500 km of 2D seismic data has allowed a detailed and consistent break-down of the geological record of the northern part of the basin into chronostratigraphic events which were used as inputs to model the hydrocarbon generation history. In addition, seismic facies mapping, using the internal reflection characteristics of selected seismic sequences, has been applied to predict the lateral distribution of source rock intervals. The results based on Yükler ID basin modelling are presented as profiles and maturity maps. The robustness of the results are analysed by testing different heat flow scenarios and by transfer of the model concept to IES Petromod software to obtain a more acceptable temperature history reconstruction using the Easy%R0 algorithm. Miocene coals in the wells located in the inverted zone between the fault splays are present in separate intervals. Seismic facies analysis suggests that the upper interval is of limited areal extent. The lower interval, of more widespread occurrence, is presently in the oil and condensate generating zones in deep synclines between inversion ridges. The Yükler modelling indicates, however, that the coaly source rock interval entered the main window prior to formation of traps as a result of Late Miocene inversion. Lacustrine mudstones, similar to the highly oil-prone Oligocene mudstones and coals which are exposed in the Dong Ho area at the northern margin of the Song Hong Basin and on Bach Long Vi Island in Gulf of Tonkin, are interpreted to be preserved in a system of undrilled NW,SE Paleogene half-grabens NE of the Song Lo Fault Zone. This is based on the presence of intervals with distinct, continuous, high reflection seismic amplitudes. Considerable overlap exists between the shale-prone seismic facies and the modelled extent of the present-day oil and condensate generating zones, suggesting that active source kitchens also exist in this part of the basin. Recently reported oil in a well located onshore (BIO-STB-IX) at the margin of the basin, which is sourced mainly from "Dong Ho type" lacustrine mudstones supports the presence of an additional Paleogene sourced petroleum system. [source] HYDROCARBON POTENTIAL OF JURASSIC SOURCE ROCKS IN THE JUNGGAR BASIN, NW CHINAJOURNAL OF PETROLEUM GEOLOGY, Issue 3 2003A. N. Ding Jurassic source rocks in the Junggar Basin (NW China) include coal swamp and freshwater lacustrine deposits. Hydrocarbon-generating macerals in the coal swamp deposits are dominated by desmocollinite and exinite of higher-plant origin. In lacustrine facies, macerals consists of bacterially-altered amorphinite, algal- amorphinite, alginite, exinite and vitrinite. Coals and coaly mudstones in the Lower Jurassic Badaowan Formation generate oil at the Qigu oilfield on the southern margin of the basin. Lacustrine source rocks generate oil at the Cainan oilfield in the centre of the basin. The vitrinite reflectance (Ro) of coal swamp deposits ranges from 0.5% to 0.9%, and that of lacustrine source rocks from 0.4% to 1.2%. Biomarker compositions likewise indicate that thermal maturities are variable. These variations cause those with lighter compositions to have matured earlier. Our data indicate that oil and gas generation has occurred at different stages of source-rock maturation, an "early" stage and a "mature" stage. Ro values are 0.4%,0.7% in the former and 0.8%,1.2% in the latter. [source] Geochemical Signatures of Early Paleogene Source Rocks in the Sanshui Basin, South ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 1 2010Chunlian LIU Abstract: The Honggang member of the early Paleogene Buxin Formation is the main source rock in the Sanshui Basin, characterized by organic-rich black shales with the cyclic recurrence of organic-poor sediments. The geochemical characteristics of the Honggang member have been documented to determine the organic matter types and depositional environments in this paper. The organic matter of the black shales mainly consists of a mixture of land plant-derived and phytoplankton-derived organic matter. Total organic carbon content (TOC)-sulfur-iron (Fe) relationships suggest that the organic-rich black shales were deposited under dysoxic-to-euxinic water conditions. The time that iron minerals remained in contact with H2S in anoxic waters possibly influenced the formation of syngenetic pyrite, and organic carbon controlled the formation of diagenetic pyrite. Organic-poor intervals usually show pyrite sulfur enrichment and higher degree of pyritization values relative to low organic carbon contents. This resulted from HS, diffusing downward from overlying organic-rich sediments and formed Fe sulfides through reactions with sufficient Fe. Trace elements generally exhibit low concentrations and little TOC dependence, suggesting some degree of depletion in these elements in the early Paleogene sediments of the Sanshui Basin. This probably resulted from cyclic recurrences of oxic benthic conditions, which promoted the remobilization of trace elements and caused the low concentration of trace elements. [source] Source Rocks for the Giant Puguang Gas Field Sichuan Basin: Implication for Petroleum Exploration in Marine Sequences in South ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 3 2008ZOU Huayao Abstract: Detailed geochemistry studies were conducted to investigate the origin of solid bitumens and hydrocarbon gases in the giant Puguang gas field. Two types of solid bitumens were recognized: low sulfur content, low reflectance (LSLR) solid bitumens in sandstone reservoirs in the Xujiahe Formation and high sulfur content, high reflectance (HSHR) solid bitumens in the carbonate reservoirs in the Lower Triassic Feixianguan and Upper Permian Changxing formations. Solid bitumens in the Upper Triassic Xujiahe Formation correlate well with extracts from the Upper Triassic to Jurassic nonmarine source rocks in isotopic composition of the saturated and aromatic fractions and biomarker distribution. Solid bitumens in the Feixianguan and Changxing formations are distinctly different from extracts from the Cambrian and Silurian rocks but display reasonable correlation with extracts from the Upper Permian source rocks both in isotopic composition of the saturated and aromatic fractions and in biomarker distribution, suggesting that the Permian especially the Upper Permian Longtan Formation was the main source of solid bitumens in the carbonate reservoirs in the Feixianguan and Changxing formations in the Puguang gas field. Chemical and isotopic composition of natural gases indicates that the majority of hydrocarbon gases originated from sapropelic organic matter and was the products of thermal cracking of accumulated oils. This study indicates that source rock dominated by sapropelic organic matter existed in the Upper Permian and had made major contribution to the giant Puguang gas field, which has important implication for petroleum exploration in marine sequences in South China. [source] Textural and compositional controls on modern beach and dune sands, New ZealandEARTH SURFACE PROCESSES AND LANDFORMS, Issue 3 2007J. J. Kasper-Zubillaga Abstract Textural, compositional, physical and geophysical determinations were carried out on 111 beach and dune sand samples from two areas in New Zealand: the Kapiti,Foxton coast sourced by terranes of andesite and greywackes and the Farewell Spit,Wharariki coast sourced by a wide variety of Paleozoic terranes. Our aim is to understand how long-shore drift, beach width and source rock control the sedimentological and petrographic characteristics of beach and dune sands. Furthermore, this study shows the usefulness of specific minerals (quartz, plagioclase with magnetite inclusions, monomineralic opaque grains) to interpret the physical processes (fluvial discharges, long-shore currents, winds) that distribute beach and dune sands in narrow and wide coastal plains. This was done by means of direct (grain size and modal analyses) and indirect (specific gravity, magnetic/non-magnetic separations M/NM, magnetic susceptibility measurements, hysteresis loops) methods. Results are compared with beach sands from Hawaii, Oregon, the Spanish Mediterranean, Elba Island and Southern California. Compositionally, the Kapiti,Foxton sands are similar to first-order immature sands, which retain their fluvial signature. This results from the high discharge of rivers and the narrow beaches that control the composition of the Kapiti,Foxton sands. The abundance of feldspar with magnetite inclusions controls the specific gravity of the Kapiti,Foxton sands due to their low content of opaque minerals and coarse grain size. Magnetic susceptibility of the sands is related mainly to the abundance of feldspars with Fe oxides, volcanic lithics and free-opaque minerals. The Farewell Spit,Wharariki sands are slightly more mature than the Kapiti,Foxton sands. The composition of the Farewell Spit,Wharariki sands does not reflect accurately their provenance due to the prevalence of long-shore drift, waves, little river input and a wide beach. Low abundance of feldspar with magnetite inclusions and free opaque grains produces poor correlations between specific gravity (Sg) and Fe oxide bearing minerals. The small correlation between opaque grains and M/NM may be related to grain size. The magnetic susceptibility of Farewell Spit,Wharariki sands is low due to the low content of grains with magnetite inclusions. Hysteresis and isothermal remnant magnetization (IRM) agree with the magnetic susceptibility values. Copyright © 2006 John Wiley & Sons, Ltd. [source] Organic geochemistry indicates Gebel El Zeit, Gulf of Suez, is a source of bitumen used in some Egyptian mummiesGEOARCHAEOLOGY: AN INTERNATIONAL JOURNAL, Issue 3 2005A.O. Barakat Molecular geochemical properties of crude oils and surface petroleum seeps from the southern part of the Gulf of Suez were evaluated. The characterizations of individual aliphatic, aromatic, and biomarker compounds were based on gas chromatography (GC) and gas chromatography/mass spectrometry (GC/MS) analyses. The results provided strong evidence for a close genetic association of these samples. The geochemical characteristics suggest an origin from Tertiary source rocks deposited in a normal marine environment that received continental runoff. The molecular signatures of the investigated samples were very similar to those of the Lower Miocene Rudeis Formation source rock in the southern Gulf of Suez. Further, biomarker fingerprints of the investigated oil seeps were compared with those of the Dead Sea asphalt, as well as the bitumen from some Egyptian mummies reported in the literature. The results demonstrate that oil seeps from the southern end of Gebel El Zeit were used by ancient Egyptians for embalming. © 2005 Wiley Periodicals, Inc. [source] Diagenesis of the Amposta offshore oil reservoir (Amposta Marino C2 well, Lower Cretaceous, Valencia Trough, Spain)GEOFLUIDS (ELECTRONIC), Issue 3 2010E. PLAYÀ Abstract Samples from the Amposta Marino C2 well (Amposta oil field) have been investigated in order to understand the origin of fractures and porosity and to reconstruct the fluid flow history of the basin prior, during and after oil migration. Three main types of fracture systems and four types of calcite cements have been identified. Fracture types A and B are totally filled by calcite cement 1 (CC1) and 2 (CC2), respectively; fracture type A corresponds to pre-Alpine structures, while type B is attributed to fractures developed during the Alpine compression (late Eocene-early Oligocene). The oxygen, carbon and strontium isotope compositions of CC2 are close to those of the host-rock, suggesting a high degree of fluid-rock interaction, and therefore a relatively closed palaeohydrogeological system. Fracture type C, developed during the Neogene extension and enlarged by subaerial exposure, tend to be filled with reddish (CS3r) and greenish (CS3g) microspar calcite sediment and blocky calcite cement type 4 (CC4), and postdated by kaolinite, pyrite, barite and oil. The CS3 generation records lower oxygen and carbon isotopic compositions and higher 87Sr/86Sr ratios than the host-limestones. These CS3 karstic infillings recrystallized early within evolved-meteoric waters having very little interaction with the host-rock. Blocky calcite cement type 4 (CC4 generation) has the lowest oxygen isotope ratio and the most radiogenic 87Sr/86Sr values, indicating low fluid-rock interaction. The increasingly open palaeohydrogeological system was dominated by migration of hot brines with elevated oxygen isotope ratios into the buried karstic system. The main oil emplacement in the Amposta reservoir occurred after the CC4 event, closely related to the Neogene extensional fractures. Corrosion of CC4 (blocky calcite cement type 4) occurred prior to (or during) petroleum charge, possibly related to kaolinite precipitation from relatively acidic fluids. Barite and pyrite precipitation occurred after this corrosion. The sulphur source associated with the late precipitation of pyrite was likely related to isotopically light sulphur expelled, e.g. as sulphide, from the petroleum source rock (Ascla Fm). Geofluids (2010) 10, 314,333 [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] OIL-PRONE LOWER CARBONIFEROUS COALS IN THE NORWEGIAN BARENTS SEA: IMPLICATIONS FOR A PALAEOZOIC PETROLEUM SYSTEMJOURNAL OF PETROLEUM GEOLOGY, Issue 2 2010J.H. Van Koeverden 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 Ro= 0.75,0.85 %. Compared to shale and carbonate source rocks, expulsion from coal in general begins at higher maturities (Ro= 0.8,0.9% and Tmax= 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 ,13C 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. [source] THERMAL HISTORY RECONSTRUCTION IN THE SOROOSH AND NOWROOZ FIELDS, PERSIAN GULF, BASED ON APATITE FISSION TRACK ANALYSIS AND VITRINITE REFLECTANCE DATAJOURNAL OF PETROLEUM GEOLOGY, Issue 2 2008A. Bashari The thermal history of the sedimentary successions at the Soroosh-17, Soroosh-02 and Nowrooz-16 wells in the northern Persian Gulf have been studied using apatite fission track analysis and vitrinite reflectance data. These data were used to identify and quantify episodes of heating and cooling which have affected the sections penetrated by these wells. This information was synthesised to provide a thermal history framework for the wells, within which the history of hydrocarbon generation, as well as regional structural development, can be understood. Preliminary hydrocarbon generation histories are presented for the Soroosh and Nowrooz oilfields and nearby areas. Modelling of hydrocarbon generation histories based on the AFTA- and VR-derived thermal histories, assuming a dominant Type III kerogen for possible Albian Kazhdumi Formation source rocks and a dominant Type II kerogen for possible Neocomian Fahliyan (Lower Ratawi) Formation source rock, suggest that local sourcing of oil from the Kazhdumi Formation is unlikely. The most likely source rock for oil in the Burgan Formation reservoir at Soroosh-17 and Nowrooz-16 is interpreted to be the Fahliyan Formation based on the available data. On the other hand, speculative modelling of the Hendijan-I well down-dip from the Nowrooz field does allow some oil to be generated from the Kazhdumi sequence at that location, and this might be available for migration to the Nowrooz field. [source] A REVIEW OF GEOLOGICAL DATA THAT CONFLICT WITH THE PARADIGM OF CATAGENIC GENERATION AND MIGRATION OF OILJOURNAL OF PETROLEUM GEOLOGY, Issue 3 2005H. Hugh Wilson The majority of petroleum geologists today agree that the complex problems that surround the origin, generation, migration and accumulation of hydrocarbons can be resolved by accepting the geochemical conclusion that the process originates by catagenic generation in deeply-buried organically-rich source rocks. These limited source rock intervals are believed to expel hydrocarbons when they reach organic maturity in oil kitchens. The expelled oil and gas then follow migration pathways to traps at shallower levels. However, there are major geological obstacles that cast doubt upon this interpretation. The restriction of the source rock to a few organically rich levels in a basin forces the conclusion that the basin plumbing system is leaky and allows secondary horizontal and vertical migration through great thicknesses of consolidated sedimentary rocks in which there are numerous permeability barriers that are known to effectively prevent hydrocarbon escape from traps. The sourcing of lenticular traps points to the enclosing impermeable envelope as the logical origin of the trapped hydrocarbons. The lynch-pin of the catagenic theory of hydrocarbon origin is the expulsion mechanism from deeply-buried consolidated source rock under high confining pressures. This mechanism is not understood and is termed an "enigma". Assuming that expulsion does occur, the pathways taken by the hydrocarbons to waiting traps can be ascertained by computer modelling of the basin. However, subsurface and field geological support for purported migration pathways has yet to be provided. Many oilfield studies have shown that oil and gas are preferentially trapped in synchronous highs that were formed during, or very shortly after, the deposition of the charged reservoir. An unresolved problem is how catagenically generated hydrocarbons, expelled during a long-drawn-out maturation period, can have filled synchronous highs but have avoided later traps along the assumed migration pathways. From many oilfield studies, it has also been shown that the presence of hydrocarbons inhibits diagenesis and compaction of the reservoir rock. This "Füchtbauer effect" points to not only the early charging of clastic and carbonate reservoirs, but also to the development of permeability barriers below the early-formed accumulations. These barriers would prevent later hydrocarbon additions during the supposed extended period of expulsion from an oil kitchen. Early-formed traps that have been sealed diagenetically will retain their charge even if the trap is opened by later structural tilting. Diagenetic traps have been discovered in clastic and carbonate provinces but their recognition as viable exploration targets is discouraged by present-day assumptions of late hydrocarbon generation and a leaky basin plumbing system. Because there are so many geological realities that cast doubt upon the assumptions that devolve from the paradigm of catagenic generation, the alternative concept of early biogenic generation and accumulation of immature oil, with in-reservoir cracking during burial, is again worthy of serious consideration. This concept envisages hydrocarbon generation by bacterial activity in many anoxic environments and the charging of synchronous highs from adjacent sources. The resolution of the fundamental problem of hydrocarbon generation and accumulation, which is critical to exploration strategies, should be sought in the light of a thorough knowledge of the geologic factors involved, rather than by computer modelling which may be guided by questionable geochemical assumptions. [source] SOURCE ROCK PROPERTIES OF LACUSTRINE MUDSTONES AND COALS (OLIGOCENE DONG HO FORMATION), ONSHORE SONG HONG BASIN, NORTHERN VIETNAMJOURNAL OF PETROLEUM GEOLOGY, Issue 1 2005H. I. Petersen Oligocene lacustrine mudstones and coals of the Dong Ho Formation outcropping around Dong Ho, at the northern margin of the mainly offshore Cenozoic Song Hong Basin (northern Vietnam), include highly oil-prone potential source rocks. Mudstone and coal samples were collected and analysed for their content of total organic carbon and total sulphur, and source rock screening data were obtained by Rock-Eval pyrolysis. The organic matter composition in a number of samples was analysed by reflected light microscopy. In addition, two coal samples were subjected to progressive hydrous pyrolysis in order to study their oil generation characteristics, including the compositional evolution in the extracts from the pyrolysed samples. The organic material in the mudstones is mainly composed of fluorescing amorphous organic matter, liptodetrinite and alginite with Botryococcus-morphology (corresponding to Type I kerogen). The mudstones contain up to 19.6 wt.% TOC and Hydrogen Index values range from 436,572 mg HC/g TOC. From a pyrolysis S2 versus TOC plot it is estimated that about 55% of the mudstones'TOC can be pyrolised into hydrocarbons; the plot also suggests that a minimum content of only 0.5 wt.% TOC is required to saturate the source rock to the expulsion threshold. Humic coals and coaly mudstones have Hydrogen Index values of 318,409 mg HC/g TOC. They are dominated by huminite (Type III kerogen) and generally contain a significant proportion of terrestrial-derived liptodetrinite. Upon artificial maturation by hydrous pyrolysis, the coals generate significant quantities of saturated hydrocarbons, which are probably expelled at or before a maturity corresponding to a vitrinite reflectance of 0.97%R0. This is earlier than previously indicated from Dong Ho Formation coals with a lower source potential. The composition of a newly discovered oil (well B10-STB-1x) at the NE margin of the Song Hong Basin is consistent with contributions from both source rocks, and is encouraging for the prospectivity of offshore half-grabens in the Song Hong Basin. [source] THE NATURE AND ORIGIN OF PETROLEUM IN THE CHAIWOPU SUB-BASIN (JUNGGAR BASIN), NW CHINAJOURNAL OF PETROLEUM GEOLOGY, Issue 2 2000H. 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] Disequilibrium partial melting experiments on the Leedey L6 chondrite: Textural controls on melting processesMETEORITICS & PLANETARY SCIENCE, Issue 11 2001S. N. Feldstein Chips of the L6 chondrite, Leedey, were heated at 1200 °C and log ,O2 = IW-1 for durations of 1 h to 21 days. We observed a progression of kinetically-controlled textural changes in melt and restite minerals and changes in the liquidus mineralogy in response to factors such as volatile loss. During the course of the experiments, both olivine and orthopyroxene recrystallized at different times. Rare relic chondrules could still be identified after 21 days. The silicate melts that form are very heterogeneous, in terms of both major and trace element chemistry, reflecting heterogeneity of the localized mineral assemblage, particularly with respect to phosphates and clinopyroxene. Metal-sulfide melts formed in short-duration runs are also heterogeneous. The experimental data are relevant to aspects of the genesis of primitive achondrites such as the acapulcoites. The observed textures are consistent with a model for acapulcoite petrogenesis in which silicate melting was limited to only a few volume percent of the chondritic source rock. The experiments are also relevant to the behavior of chondritic material that has been partially melted in an impact environment. [source] THE TRAVERSETTE (ITALIA) ROCKFALL: GEOMORPHOLOGICAL INDICATOR OF THE HANNIBALIC INVASION ROUTE*ARCHAEOMETRY, Issue 1 2010W. C. MAHANEY Numerous small, low volume rockfalls around the crest of the Italian and French Alps, principally formed from calcareous mica schist and metabasalt, have impeded travel across the major cols for millennia. As documented by Polybius and Livy in the ancient literature, Hannibal's Army was blocked by a two-tier rockfall on the lee side of the Alps, a rubble sheet of considerable volume that delayed his exit into the upper Po River Country. An in-depth study of the possible cols reveals that the only such two-tier landform lies below the Col de la Traversette, at ,2600 m above sea level. In addition, it represents a problem in applied geomorphology, namely, to accurately determine the nature of the surface rubble sheet in Hannibal's time (218 bc). A reconstruction of the initial deposit, likely Late Glacial, following the retreat of the Po Glacier, is based upon an analysis of the source rock and geological setting. Further specifications on the geometry of the Neoglacial cover sediment are based on weathering characteristics, lichen cover and soil development. The ,myth' that Hannibal fired the rockfall to comminute boulders is plausible given the vegetation records which support tree growth nearby, but is unsubstantiated by the lack of any carbonized rock. [source] Mudstone compaction curves in basin modelling: a study of Mesozoic and Cenozoic Sediments in the northern North SeaBASIN RESEARCH, Issue 3 2010Ø. Marcussen ABSTRACT Basin modelling studies are carried out in order to understand the basin evolution and palaeotemperature history of sedimentary basins. The results of basin modelling are sensitive to changes in the physical properties of the rocks in the sedimentary sequences. The rate of basin subsidence depends, to a large extent, on the density of the sedimentary column, which is largely dependent on the porosity and therefore on the rate of compaction. This study has tested the sensitivity of varying porosity/depth curves and related thermal conductivities for the Cenozoic succession along a cross-section in the northern North Sea basin, offshore Norway. End-member porosity/depth curves, assuming clay with smectite and kaolinite properties, are compared with a standard compaction curve for shale normally applied to the North Sea. Using these alternate relationships, basin geometries of the Cenozoic succession may vary up to 15% from those predicted using the standard compaction curve. Isostatic subsidence along the cross-section varies 2.3,4.6% between the two end-member cases. This leads to a 3,8% difference in tectonic subsidence, with maximum values in the basin centre. Owing to this, the estimated stretching factors vary up to 7.8%, which further gives rise to a maximum difference in heat flow of more than 8.5% in the basin centre. The modelled temperatures for an Upper Jurassic source rock show a deviation of more than 20 °C at present dependent on the thermal conductivity properties in the post-rift succession. This will influence the modelled hydrocarbon generation history of the basin, which is an essential output from basin modelling analysis. Results from the northern North Sea have shown that varying compaction trends in sediments with varying thermal properties are important parameters to constrain when analysing sedimentary basins. [source] Multiple-Element Matching Reservoir Formation and Quantitative Prediction of Favorable Areas in Superimposed BasinsACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 5 2010WANG Huaijie Abstract: Superimposed basins in West China have experienced multi-stage tectonic events and multicycle hydrocarbon reservoir formation, and complex hydrocarbon reservoirs have been discovered widely in basins of this kind. Most of the complex hydrocarbon reservoirs are characterized by relocation, scale re-construction, component variation and phase state transformation, and their distributions are very difficult to predict. Research shows that regional caprock (C), high-quality sedimentary facies (Deposits, D), paleohighs (Mountain, M) and source rock (S) are four geologic elements contributing to complex hydrocarbon reservoir formation and distribution of western superimposed basins. Longitudinal sequential combinations of the four elements control the strata of hydrocarbon reservoir formation, and planar superimpositions and combinations control the range of hydrocarbon reservoir and their simultaneous joint effects in geohistory determine the time of hydrocarbon reservoir formation. Multiple-element matching reservoir formation presents a basic mode of reservoir formation in superimposed basins, and we recommend it is expressed as T-CDMS. Based on the multiple-element matching reservoir formation mode, a comprehensive reservoir formation index (Tcdms) is developed in this paper to characterize reservoir formation conditions, and a method is presented to predict reservoir formation range and probability of occurrence in superimposed basins. Through application of new theory, methods and technology, the favorable reservoir formation range and probability of occurrence in the Ordovician target zone in Tarim Basin in four different reservoir formation periods are predicted. Results show that central Tarim, Yinmaili and Lunnan are the three most favorable regions where Ordovician oil and gas fields may have formed. The coincidence of prediction results with currently discovered hydrocarbon reservoirs reaches 97%. This reflects the effectiveness and reliability of the new theory, methods and technology. [source] Characteristics of Oil Sources from the Chepaizi Swell, Junggar Basin, ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 5 2010LIU Luofu Abstract: So far there has been no common opinion on oil source of the Chepaizi swell in the Junggar Basin. Therefore, it is difficult to determine the pathway system and trend of hydrocarbon migration, and this resulted in difficulties in study of oil-gas accumulation patterns. In this paper, study of nitrogen compounds distribution in oils from Chepaizi was carried out in order to classify source rocks of oils stored in different reservoirs in the study area. Then, migration characteristics of oils from the same source were investigated by using nitrogen compounds parameters. The results of nitrogen compounds in a group of oil/oil sand samples from the same source indicate that the oils trapped in the Chepaizi swell experienced an obvious vertical migration. With increasing migration distance, amounts and indices of carbazoles have a regular changing pattern (in a fine linear relationship). By using nitrogen compounds techniques, the analyzed oil/oil sand samples of Chepaizi can be classified into two groups. One is the samples stored in reservoir beds of the Cretaceous and Tertiary, and these oils came from mainly Jurassic source rock with a small amount of Cretaceous rock; the other is those stored in the Jurassic, Permian and Carboniferous beds, and they originated from the Permian source. In addition, a sample of oil from an upper Jurassic reservoir (Well Ka 6), which was generated from Jurassic coal source rock, has a totally different nitrogen compound distribution from those of the above-mentioned two groups of samples, which were generated from mudstone sources. Because of influence from fractionation of oil migration, amounts and ratios of nitrogen compounds with different structures and polarities change regularly with increasing migrating distance, and as a result the samples with the same source follow a good linear relationship in content and ratio, while the oil samples of different sources have obviously different nitrogen compound distribution owing to different organic matter types of their source rocks. These conclusions of oil source study are identical with those obtained by other geochemical bio-markers. Therefore, nitrogen compounds are of great significance in oil type classification and oil/source correlation. [source] Hydrocarbon Generation Evolution of Permo-Carboniferous Rocks of the Bohai Bay Basin in ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 2 2010Yanming ZHU Abstract: The Bohai Bay Basin is a Mesozoic subsidence and Cenozoic rift basin in the North China Craton. Since the deposition of the Permo-Carboniferous hydrocarbon source rock, the basin has undergone many tectonic events. The source rocks have undergone non-uniform uplift, twisting, deep burying, and magmatism and that led to an interrupted or stepwise during the evolution of hydrocarbon source rocks. We have investigated the Permo-Carboniferous hydrocarbon source rocks history of burying, heating, and hydrocarbon generation, not only on the basis of tectonic disturbance and deeply buried but also with new studies on apatite fission track analysis, fluid inclusion measurements, and the application of the numerical simulation of EASY %Ro. The heating temperature of the source rocks continued to rise from the Indosinian to Himalayan stage and reached a maximum at the Late Himalayan. This led to the stepwise increases during organic maturation and multiple stages of hydrocarbon generation. The study delineated the tectonic stages, the intensity of hydrocarbon generation and spatial and temporal distribution of hydrocarbon generations. The hydrocarbon generation occurred during the Indosinian, Yanshanian, and particularly Late Himalayan. The hydrocarbon generation during the late Himalayan stage is the most important one for the Permo-Carboniferous source rocks of the Bohai Bay Basin in China. [source] Oil and Gas Accumulation in the Foreland Basins, Central and Western ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 2 2010Yan SONG Abstract: Foreland basin represents one of the most important hydrocarbon habitats in central and western China. To distinguish these foreland basins regionally, and according to the need of petroleum exploration and favorable exploration areas, the foreland basins in central and western China can be divided into three structural types: superimposed, retrogressive and reformative foreland basin (or thrust belt), each with distinctive petroleum system characteristics in their petroleum system components (such as the source rock, reservoir rock, caprock, time of oil and gas accumulation, the remolding of oil/gas reservoir after accumulation, and the favorable exploration area, etc.). The superimposed type foreland basins, as exemplified by the Kuqa Depression of the Tarim Basin, characterized by two stages of early and late foreland basin development, typically contain at least two hydrocarbon source beds, one deposited in the early foreland development and another in the later fault-trough lake stage. Hydrocarbon accumulations in this type of foreland basin often occur in multiple stages of the basin development, though most of the highly productive pools were formed during the late stage of hydrocarbon migration and entrapment (Himalayan period). This is in sharp contrast to the retrogressive foreland basins (only developing foreland basin during the Permian to Triassic) such as the western Sichuan Basin, where prolific hydrocarbon source rocks are associated with sediments deposited during the early stages of the foreland basin development. As a result, hydrocarbon accumulations in retrogressive foreland basins occur mainly in the early stage of basin evolution. The reformative foreland basins (only developing foreland basin during the Himalayan period) such as the northern Qaidam Basin, in contrast, contain organic-rich, lacustrine source rocks deposited only in fault-trough lake basins occurring prior to the reformative foreland development during the late Cenozoic, with hydrocarbon accumulations taking place relatively late (Himalayan period). Therefore, the ultimate hydrocarbon potentials in the three types of foreland basins are largely determined by the extent of spatial and temporal matching among the thrust belts, hydrocarbon source kitchens, and regional and local caprocks. [source] Geochemical Signatures of Early Paleogene Source Rocks in the Sanshui Basin, South ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 1 2010Chunlian LIU Abstract: The Honggang member of the early Paleogene Buxin Formation is the main source rock in the Sanshui Basin, characterized by organic-rich black shales with the cyclic recurrence of organic-poor sediments. The geochemical characteristics of the Honggang member have been documented to determine the organic matter types and depositional environments in this paper. The organic matter of the black shales mainly consists of a mixture of land plant-derived and phytoplankton-derived organic matter. Total organic carbon content (TOC)-sulfur-iron (Fe) relationships suggest that the organic-rich black shales were deposited under dysoxic-to-euxinic water conditions. The time that iron minerals remained in contact with H2S in anoxic waters possibly influenced the formation of syngenetic pyrite, and organic carbon controlled the formation of diagenetic pyrite. Organic-poor intervals usually show pyrite sulfur enrichment and higher degree of pyritization values relative to low organic carbon contents. This resulted from HS, diffusing downward from overlying organic-rich sediments and formed Fe sulfides through reactions with sufficient Fe. Trace elements generally exhibit low concentrations and little TOC dependence, suggesting some degree of depletion in these elements in the early Paleogene sediments of the Sanshui Basin. This probably resulted from cyclic recurrences of oxic benthic conditions, which promoted the remobilization of trace elements and caused the low concentration of trace elements. [source] Petroleum System of the Sufyan Depression at the Eastern Margin of a Huge Strike-slip Fault Zone in Central AfricaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 6 2009ZHANG Yamin Abstract: The present paper mainly studies the petroleum system of the Sufyan Depression in the Muglad Basin of central Africa and analyzes its control of hydrocarbon accumulation. On the basis of comprehensive analysis of effective source rock, reservoir bed types and source,reservoir,seal assemblages, petroleum system theory has been used to classify the petroleum system of the Sufyan Depression. Vertically, the Sufyan Depression consists of two subsystems. One is an Abu Gabra subsystem as a self generating, accumulating and sealing assemblage. The other subsystem is composed of an Abu Gabra source rock, Bentiu channel sandstone reservoir and Darfur group shale seal, which is a prolific assemblage in this area. Laterally, the Sufyan Depression is divided into eastern and western parts with separate hydrocarbon generation centers more than 10 000 m deep. The potential of the petroleum system is tremendous. Recently, there has been a great breakthrough in exploration. The Sufyan C-1 well drilled in the central structural belt obtained high-yielding oil flow exceeding 100 tons per day and controlled geologic reserves of tens of millions of tons. The total resource potential of the Sufyan Depression is considerable. The central structural belt is most favorable as an exploration and development prospect. [source] Lithostratigraphy, Sedimentology, and Provenance of the Balfour Formation (Beaufort Group) in the Fort Beaufort,Alice Area, Eastern Cape Province, South AfricaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 5 2009David KATEMAUNZANGA Abstract: The Balfour Formation has a pronounced lithological variation that is characterized by alternating sandstone- and mudstone-dominated members. The sandstone-dominated Oudeberg and Barberskrans Members are composed of lithofacies that range from intraformational conglomerates to fine-grained sediments, whereas the mudstone-dominated members (Daggaboersnek, Elandsberg, and Palingkloof) are dominated by the facies Fm and FI. Petrography, geochemistry, and a paleocurrent analysis indicated that the source rock of the Balfour Formation was to south east and the rocks had a transitional/dissected magmatic arc signature. The sandstones-rich members were deposited by seasonal and ephemeral high-energy, low-sinuous streams, and the fine-grained-rich members were formed by ephemeral meandering streams. The paleoclimates have been equated to present temperate climates; they were semiarid becoming arid towards the top of the Balfour Formation. This has been determined by reconstructing the paleolatitude of the Karoo Basin, geochemistry, paleontology, sedimentary structures, and other rock properties, like color. [source] Tectonic,Hydrocarbon Accumulation of Laoyemiao Region in the Nanpu Sag, Bohai Bay BasinACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 5 2009Cuimei ZHANG Abstract: This paper aims to gain insight into Laoyemiao (LYM) tectonic features and utilizes the tectonic,hydrocarbon accumulation model by integrated analysis tectonic controls on suitable reservoirs, trap styles, and hydrocarbon migration. On the basis of 3-D seismic data interpretation and the Xi'nanzhuang (XNZ) Fault geometry analysis, it has been assessed that the LYM tectonics is essentially a transverse anticline produced by flexure of the XNZ Fault surface and superimposed by Neocene north-east-trending strike-slip faults. Transverse anticline is found to exert controls both on major sediment transportation pathways and sedimentary facies distribution. Fan-delta plains that accumulated on the anticline crest near the XNZ Fault scrap and fan-delta front on the anticline front and the upper part of both limbs slumps on synclines and the Linque subsag. In combination with the reservoir properties, suitable reservoirs are predicted in the subfacies of subaqueous distributary channel and mouth bar deposited on the anticline crest. The LYM-faulted anticline accounts for the following trap groups: faulted-block and anticline-dominated trap, fault-dominated traps, and combined and stratigraphic traps. Evidence from biomarkers of crude oil and hydrocarbon-filling period simultaneous, or a little later to the strike-slip fault activity, reveal that the strike-slip faults penetrating into the deep source rock, by connecting with shallow reservoirs, provide the major hydrocarbon migration pathways. [source] Source Rocks for the Giant Puguang Gas Field Sichuan Basin: Implication for Petroleum Exploration in Marine Sequences in South ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 3 2008ZOU Huayao Abstract: Detailed geochemistry studies were conducted to investigate the origin of solid bitumens and hydrocarbon gases in the giant Puguang gas field. Two types of solid bitumens were recognized: low sulfur content, low reflectance (LSLR) solid bitumens in sandstone reservoirs in the Xujiahe Formation and high sulfur content, high reflectance (HSHR) solid bitumens in the carbonate reservoirs in the Lower Triassic Feixianguan and Upper Permian Changxing formations. Solid bitumens in the Upper Triassic Xujiahe Formation correlate well with extracts from the Upper Triassic to Jurassic nonmarine source rocks in isotopic composition of the saturated and aromatic fractions and biomarker distribution. Solid bitumens in the Feixianguan and Changxing formations are distinctly different from extracts from the Cambrian and Silurian rocks but display reasonable correlation with extracts from the Upper Permian source rocks both in isotopic composition of the saturated and aromatic fractions and in biomarker distribution, suggesting that the Permian especially the Upper Permian Longtan Formation was the main source of solid bitumens in the carbonate reservoirs in the Feixianguan and Changxing formations in the Puguang gas field. Chemical and isotopic composition of natural gases indicates that the majority of hydrocarbon gases originated from sapropelic organic matter and was the products of thermal cracking of accumulated oils. This study indicates that source rock dominated by sapropelic organic matter existed in the Upper Permian and had made major contribution to the giant Puguang gas field, which has important implication for petroleum exploration in marine sequences in South China. [source] Sourcing carbonate pointed stones from the barrier beach of Mantoloking, New Jersey, USAGEOARCHAEOLOGY: AN INTERNATIONAL JOURNAL, Issue 8 2006John P. Vermylen Over 500 previously unidentified, symmetric pointed stones of similar size, shape, color, and texture have been found on the barrier beach of Mantoloking, New Jersey, since 1940. Petrographic, stereo, and scanning electron microscopy analysis reveals that the stones are made of either a biomicritic packstone composed of 50% siliceous microfossil remains ( including sponge spicules and radiolaria) embedded in a micrite matrix or a limestone with abundant angular quartz grains (50,150 ,m wide) surrounded by a calcite matrix. The distinctive shape of the Mantoloking stones is most similar to whetstones used for sharpening scythes. We conducted a worldwide search and discovered one producer of carbonate whetstones: a company in the town of Pradalunga in Northern Italy. Microscope analysis reveals that the Pradalunga source rocks are exact matches for the spicule-rich limestone and angular quartz-rich limestone found in the Mantoloking collection. The whetstones are most likely lost cargo from a wreck offshore of Mantoloking, but the exact source may never be known. © 2006 Wiley Periodicals, Inc. [source] Organic geochemistry indicates Gebel El Zeit, Gulf of Suez, is a source of bitumen used in some Egyptian mummiesGEOARCHAEOLOGY: AN INTERNATIONAL JOURNAL, Issue 3 2005A.O. Barakat Molecular geochemical properties of crude oils and surface petroleum seeps from the southern part of the Gulf of Suez were evaluated. The characterizations of individual aliphatic, aromatic, and biomarker compounds were based on gas chromatography (GC) and gas chromatography/mass spectrometry (GC/MS) analyses. The results provided strong evidence for a close genetic association of these samples. The geochemical characteristics suggest an origin from Tertiary source rocks deposited in a normal marine environment that received continental runoff. The molecular signatures of the investigated samples were very similar to those of the Lower Miocene Rudeis Formation source rock in the southern Gulf of Suez. Further, biomarker fingerprints of the investigated oil seeps were compared with those of the Dead Sea asphalt, as well as the bitumen from some Egyptian mummies reported in the literature. The results demonstrate that oil seeps from the southern end of Gebel El Zeit were used by ancient Egyptians for embalming. © 2005 Wiley Periodicals, Inc. [source] A comparative electron microprobe study of "Aeginetan" wares with potential raw material sources from Aegina, Methana, and Poros, GreeceGEOARCHAEOLOGY: AN INTERNATIONAL JOURNAL, Issue 6 2002Michael J. Dorais Qualitative stylistic evidence from ceramic vessels and limited petrographic analysis suggested that a distinctive group of ceramics with visible inclusions of biotite (Gold Mica Fabric) was produced on the island of Aegina, Greece, during the Middle Helladic and Late Helladic I periods. To quantitatively evaluate this provenance, we sampled all potential source rocks on Aegina, Methana, and Poros. Electron microprobe analysis of amphibole in these samples revealed that each of these volcanic centers has its own unique mineralogical signature. Comparative analyses of amphibole in Zerner's original stylistic "Gold Mica Fabric" type sample with the reference samples reveal that two sherds are Aeginetan. Three additional sherds from this sample may have a non-Aeginetan provenance, probably from a back-arc setting outside the Saronic Gulf. These results suggest that the hypothesis of a single source production site for Aeginetan Ware should be reexamined. © 2002 Wiley Periodicals, Inc. [source] Analysis of hopanes and steranes in single oil-bearing fluid inclusions using time-of-flight secondary ion mass spectrometry (ToF-SIMS)GEOBIOLOGY, Issue 1 2010S. SILJESTRÖM Steranes and hopanes are organic biomarkers used as indicators for the first appearance of eukaryotes and cyanobacteria on Earth. Oil-bearing fluid inclusions may provide a contamination-free source of Precambrian biomarkers, as the oil has been secluded from the environment since the formation of the inclusion. However, analysis of biomarkers in single oil-bearing fluid inclusions, which is often necessary due to the presence of different generations of inclusions, has not been possible due to the small size of most inclusions. Here, we have used time-of-flight secondary ion mass spectrometry (ToF-SIMS) to monitor in real time the opening of individual inclusions trapped in hydrothermal veins of fluorite and calcite and containing oil from Ordovician source rocks. Opening of the inclusions was performed by using a focused C60+ ion beam and the in situ content was precisely analysed for C27,C29 steranes and C29,C32 hopanes using Bi3+ as primary ions. The capacity to unambiguously detect these biomarkers in the picoliter amount of crude oil from a single, normal-sized (15,30 ,m in diameter) inclusion makes the approach promising in the search of organic biomarkers for life's early evolution on Earth. [source] | |||||||||||||||||||||||||