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1.
To study the sedimentary environment of the Lower Cambrian organic-rich shales and isotopic geochemical characteristics of the residual shale gas, 20 black shale samples from the Niutitang Formation were collected from the Youyang section, located in southeastern Chongqing, China. A combination of geochemical, mineralogical, and trace element studies has been performed on the shale samples from the Lower Cambrian Niutitang Formation, and the results were used to determine the paleoceanic sedimentary environment of this organic-rich shale. The relationships between total organic carbon (TOC) and total sulfur (TS) content, carbon isotope value (δ13Corg), trace element enrichment, and mineral composition suggest that the high-TOC Niutitang shale was deposited in an anoxic environment and that the organic matter was well preserved after burial. Stable carbon isotopes and biomarkers both indicate that the organic matter in the Niutitang black shales was mainly derived from both lower aquatic organisms and algaes and belong to type I kerogen. The oil-prone Niutitang black shales have limited residual hydrocarbons, with low values of S2, IH, and bitumen A. The carbon isotopic distribution of the residual gas indicate that the shale gas stored in the Niutitang black shale was mostly generated from the cracking of residual bitumen and wet gas during a stage of significantly high maturity. One of the more significant observations in this work involves the carbon isotope compositions of the residual gas (C1, C2, and C3) released by rock crushing. A conventional δ13C1–δ13C2 trend was observed, and most δ13C2 values of the residual gases are heavier than those of the organic matter (OM) in the corresponding samples, indicating the splitting of ethane bonds and the release of smaller molecules, leading to 13C enrichment in the residual ethane.  相似文献   

2.
The stable carbon isotopic ratios (δ13C) of methane (CH4) and carbon dioxide (CO2) of gas-rich fluid inclusions hosted in fracture-fill mineralization from the southern part of the Lower Saxony Basin, Germany have been measured online using a crushing device interfaced to an isotopic ratio mass spectrometer (IRMS). The data reveal that CH4 trapped in inclusions seems to be derived from different source rocks with different organic matter types. The δ13C values of CH4 in inclusions in quartz hosted by Carboniferous rocks range between −25 and −19‰, suggesting high-maturity coals as the source of methane. Methane in fluid inclusions in minerals hosted by Mesozoic strata has more negative carbon isotope ratios (−45 to −31‰) and appears to represent primary cracking products from type II kerogens, i.e., marine shales. There is a positive correlation between increasing homogenization temperatures of aqueous fluid inclusions and less negative δ13C(CH4) values of in co-genetic gas inclusions probably indicating different mtaturity of the potential source rocks at the time the fluids were released. The CO2 isotopic composition of CH4-CO2-bearing inclusions shows slight negative or even positive δ13C values indicating an inorganic source (e.g., water-rock interaction and dissolution of detrital, marine calcite) for CO2 in inclusions. We conclude that the δ13C isotopic ratios of CH4-CO2-bearing fluid inclusions can be used to trace migration pathways, sources of gases, and alteration processes. Furthermore, the δ13C values of methane can be used to estimate the maturity of the rocks from which it was sourced. Results presented here are further supported by organic geochemical analysis of surface bitumens which coexist with the gas inclusion-rich fracture-fill mineralization and confirm the isotopic interpretations with respect to fluid source, type and maturity.  相似文献   

3.
Hydrate-bearing sediment cores were retrieved from recently discovered seepage sites located offshore Sakhalin Island in the Sea of Okhotsk. We obtained samples of natural gas hydrates and dissolved gas in pore water using a headspace gas method for determining their molecular and isotopic compositions. Molecular composition ratios C1/C2+ from all the seepage sites were in the range of 1,500–50,000, while δ13C and δD values of methane ranged from ?66.0 to ?63.2‰ VPDB and ?204.6 to ?196.7‰ VSMOW, respectively. These results indicate that the methane was produced by microbial reduction of CO2. δ13C values of ethane and propane (i.e., ?40.8 to ?27.4‰ VPDB and ?41.3 to ?30.6‰ VPDB, respectively) showed that small amounts of thermogenic gas were mixed with microbial methane. We also analyzed the isotopic difference between hydrate-bound and dissolved gases, and discovered that the magnitude by which the δD hydrate gas was smaller than that of dissolved gas was in the range 4.3–16.6‰, while there were no differences in δ13C values. Based on isotopic fractionation of guest gas during the formation of gas hydrate, we conclude that the current gas in the pore water is the source of the gas hydrate at the VNIIOkeangeologia and Giselle Flare sites, but not the source of the gas hydrate at the Hieroglyph and KOPRI sites.  相似文献   

4.
We investigated the molecular composition (methane, ethane, and propane) and stable isotope composition (methane and ethane) of hydrate-bound gas in sediments of Lake Baikal. Hydrate-bearing sediment cores were retrieved from eight gas seep sites, located in the southern and central Baikal basins. Empirical classification of the methane stable isotopes (δ13C and δD) for all the seep sites indicated the dominant microbial origin of methane via methyl-type fermentation; however, a mixture of thermogenic and microbial gases resulted in relatively high methane δ13C signatures at two sites where ethane δ13C indicated a typical thermogenic origin. At one of the sites in the southern Baikal basin, we found gas hydrates of enclathrated microbial ethane in which 13C and deuterium were both highly depleted (mean δ13C and δD of –61.6‰ V-PDB and –285.4‰ V-SMOW, respectively). To the best of our knowledge, this is the first report of C2 δ13C–δD classification for hydrate-bound gas in either freshwater or marine environments.  相似文献   

5.
Fluid inclusion gases in minerals from shale hosted fracture-fill mineralization have been analyzed for stable carbon isotopic ratios of CH4 using a crushing device interfaced to an isotope ratio mass spectrometer (IRMS). The samples of Paleozoic strata under study originate from outcrops and wells in the Rhenish Massif and Campine Basin, Harz Mountains, and the upper slope of the Southern Permian Basin. Fracture-fill mineralization hosted by Mesozoic strata was sampled from drill cores in the Lower Saxony Basin. Some studied sites are candidates for shale gas exploration in Germany. Samples of Mesozoic strata are characterized by abundant calcite-filled horizontal fractures which preferentially occur in TOC-rich sections of the drilled sediments. Only rarely are vertical fractures filled with carbonates and/or quartz in drill cores from Mesozoic strata but in Paleozoic shale they occur frequently. The δ13C(CH4) values of fluid inclusions in calcite from horizontal fractures hosted by Mesozoic strata suggest that gaseous hydrocarbons were generated during the oil/early gas window and that the formation of horizontal fractures seems to be related to hydraulic expulsion fracturing. The calculated maturity of the source rocks at the time of gas generation lies below the maturity derived from measured vitrinite reflectance. Thus, the formation of horizontal fractures and trapping of gas that was generated in the oil and/or early gas window obviously occurred prior to maximal burial. Rapidly increasing vitrinite reflectance data seen locally can be explained by hydrothermal alteration, as indicated by increasing δ13C (CH4–CO2) values in fluid inclusions. The formation of vertical fractures in studied Mesozoic sediments is related to stages of post-burial inversion; gas-rich inclusions in fracture filling minerals recorded the migration of gas that had probably been generated instantaneously, rather than cumulatively, from high to overmature source rocks. Since no evidence is given for the presence of early generated gas in studied Paleozoic shale, it appears likely that major gas loss from shales occurred due to deformation and uplift of these sediments in response to the Variscan Orogeny.  相似文献   

6.
Kimmeridgian organic-rich shales of the Madbi Formation from the Marib-Shabowah Basin in western Yemen were analysed to evaluate the type of organic matter, origin and depositional environments as well as their oil-generation potential. Results of the current study establishes the organic geochemical characteristics of the Kimmeridgian organic-rich shales and identifies the kerogen type based on their organic petrographic characteristics as observed under reflected white light and blue light excitation. Kerogen microscopy shows that the Kimmeridgian organic-rich shales contain a large amount of organic matter, consisting predominantly of yellow fluorescing alginite and amorphous organic matter with marine-microfossils (e.g., dinoflagellate cysts and micro-foraminiferal linings). Terrigenous organic matters (e.g., vitrinite, spores and pollen) are also present in low quantities. The high contributions of marine organic matter with minor terrigenous organic matter are also confirmed by carbon isotopic values. The organic richness of the Kimmeridgian shales is mainly due to good preservation under suboxic to relatively anoxic conditions, as indicated by the percent of numerous pyritized fragments associated with the organic matter. The biomarker parameters obtained from mass spectrometer data on m/z 191 and m/z 217 also indicate that these organic-rich shales contain mixed organic matter that were deposited in a marine environment and preserved under suboxic to relatively anoxic conditions.The Kimmeridgian organic-rich shales thus have high oil and low gas-generation potential due to oil window maturities and the nature of the organic matter, with high content of hydrogen-rich Type II and mixed Type II-III kerogens with minor contributions of Type III kerogen.  相似文献   

7.
This study investigates the source rock characteristics of Permian shales from the Jharia sub-basin of Damodar Valley in Eastern India. Borehole shales from the Raniganj, Barren Measure and Barakar Formations were subjected to bulk and quantitative pyrolysis, carbon isotope measurements, mineral identification and organic petrography. The results obtained were used to predict the abundance, source and maturity of kerogen, along with kinetic parameters for its thermal breakdown into simpler hydrocarbons.The shales are characterized by a high TOC (>3.4%), mature to post-mature, heterogeneous Type II–III kerogen. Raniganj and Barren Measure shales are in mature, late oil generation stage (Rr%Raniganj = 0.99–1.22; Rr%Barren Measure = 1.1–1.41). Vitrinite is the dominant maceral in these shales. Barakar shows a post-mature kerogen in gas generation stage (Rr%Barakar = 1.11–2.0) and consist mainly of inertinite and vitrinite. The δ13Corg value of kerogen concentrate from Barren Measure shale indicates a lacustrine/marine origin (−24.6–−30.84‰ vs. VPDB) and that of Raniganj and Barakar (−22.72–−25.03‰ vs. VPDB) show the organic provenance to be continental. The δ13C ratio of thermo-labile hydrocarbons (C1–C3) in Barren Measure suggests a thermogenic source.Discrete bulk kinetic parameters indicate that Raniganj has lower activation energies (ΔE = 42–62 kcal/mol) compared to Barren Measure and Barakar (ΔE = 44–68 kcal/mol). Temperature for onset (10%), middle (50%) and end (90%) of kerogen transformation is least for Raniganj, followed by Barren Measure and Barakar. Mineral content is dominated by quartz (42–63%), siderite (9–15%) and clay (14–29%). Permian shales, in particular the Barren Measure, as inferred from the results of our study, demonstrate excellent properties of a potential shale gas system.  相似文献   

8.
Hydrocarbon gases with unconventional carbon isotopic signatures were observed in the Solimões sedimentary basin in north-west Brazil. Siderite contents measured with a new Rock-Eval methodology in the drill-cuttings samples of the Famenian source rock were found to decrease with the increase of gas maturity and with the occurrence of the gas isotopic anomalies. Triassic diabase intrusions induced heating of the source rock, which likely resulted in the gradual oxidative dissolution of siderite as suggested by the observation of etch pits on the siderite surfaces. It is proposed that ferrous iron from the carbonate was involved in a redox reaction with water producing ferric iron and H2, then reducing CO2 and yielding an inverse correlation between siderite content and gas maturity. Alternatively, hydrogenation of highly mature kerogen by H2 derived from siderite could explain the production of 13C-rich CH4. Mass balance considerations suggest that these mechanisms may account for a significant fraction of the hydrocarbon gases generated from the Famenian source rock in the Solimões basin.  相似文献   

9.
The assessment of gas origin in mud volcanoes and related petroleum systems must consider post-genetic processes which may alter the original molecular and isotopic composition of reservoir gas. Beyond eventual molecular and isotopic fractionation due to gas migration and microbial oxidation, investigated in previous studies, we now demonstrate that mud volcanoes can show signals of anaerobic biodegradation of natural gas and oil in the subsurface. A large set of gas geochemical data from more than 150 terrestrial mud volcanoes worldwide has been examined. Due to the very low amount of C2+ in mud volcanoes, isotopic ratios of ethane, propane and butane (generally the best tracers of anaerobic biodegradation) are only available in a few cases. However, it is observed that 13C-enriched propane is always associated with positive δ13CCO2 values, which are known indicators of secondary methanogenesis following anaerobic biodegradation of petroleum. Data from carbon isotopic ratio of CO2 are available for 134 onshore mud volcanoes from 9 countries (Azerbaijan, Georgia, Ukraine, Russia, Turkmenistan, Trinidad, Italy, Japan and Taiwan). Exactly 50% of mud volcanoes, all releasing thermogenic or mixed methane, show at least one sample with δ13CCO2 > +5‰ (PDB). Thermogenic CH4 associated with positive carbon isotopic ratio of CO2 generally maintains its δ13C-enriched signature, which is therefore not perturbed by the lighter secondary microbial gas. There is, however, high variability in the δ13CCO2 values within the same mud volcanoes, so that positive δ13CCO2 values can be found in some vents and not in others, or not continuously in the same vent. This can be due to high sensitivity of δ13CCO2 to gas–water–rock interactions or to the presence of differently biodegraded seepage systems in the same mud volcano. However, finding a positive δ13CCO2 value should be considered highly indicative of anaerobic biodegradation and further analyses should be made, especially if mud volcanoes are to be used as pathfinders of the conditions indicative of subsurface hydrocarbon accumulations in unexplored areas.  相似文献   

10.
This study performed a detailed geochemical analyses of the components, stable carbon isotopes of alkane gas and CO2, stable hydrogen isotopes of alkane gas and helium isotopes of reproducing gas from the largest tight gas field (Sulige) and shale gas (Fuling) field in China. The comparative study shows that tight gas from the Sulige gas field in the Ordos Basin is of coal-derived origin, which is characterized by a positive carbon and hydrogen isotopic distribution pattern (δ13C1 > δ13C2 > δ13C3 > δ13C4; δ2H1 > δ2H2 > δ2H3), i.e., the carbon and hydrogen isotopes increase with increasing carbon numbers. Carbon dioxide from this field are of biogenic origin and the helium is crust-derived. Shale gas from the Fuling shale gas field belongs to oil-derived gas which has complete carbon and hydrogen isotopic reversal of secondary alteration origin (δ13C1 < δ13C2 < δ13C3; δ2H1 < δ2H2 < δ2H3), i.e., the carbon and hydrogen isotopes decrease with increasing carbon numbers. Such complete isotopic reversal distribution pattern is due to the secondary alteration like oil or gas cracking, diffusion and so on under high temperature. In that case, positive carbon or hydrogen isotopic distribution pattern will change into complete isotopic reversal as the temperature increases. Carbon dioxide is of abiogenic origin resulting from the thermal metamorphism of carbonates and helium is crust-derived.  相似文献   

11.
Two sets of Lower Paleozoic organic-rich shales develop well in the Weiyuan area of the Sichuan Basin: the Lower Cambrian Jiulaodong shale and the Lower Silurian Longmaxi shale. The Weiyuan area underwent a strong subsidence during the Triassic to Early Cretaceous and followed by an extensive uplifting and erosion after the Late Cretaceous. This has brought about great changes to the temperature and pressure conditions of the shales, which is vitally important for the accumulation and preservation of shale gas. Based on the burial and thermal history, averaged TOC and porosity data, geological and geochemical models for the two sets of shales were established. Within each of the shale units, gas generation was modeled and the evolution of the free gas content was calculated using the PVTSim software. Results show that the free gas content in the Lower Cambrian and Lower Silurian shales in the studied area reached the maxima of 1.98–2.93 m3/t and 3.29–4.91 m3/t, respectively (under a pressure coefficient of 1.0–2.0) at their maximum burial. Subsequently, the free gas content continuously decreased as the shale was uplifted. At present, the free gas content in the two sets of shales is 1.52–2.43 m3/t and 1.94–3.42 m3/t, respectively (under a current pressure coefficient of 1.0–2.0). The results are roughly coincident with the gas content data obtained from in situ measurements in the Weiyuan area. We proposed that the Lower Cambrian and Lower Silurian shales have a shale gas potential, even though they have experienced a strong uplifting.  相似文献   

12.
Barremian–Aptian organic-rich shales from Abu Gabra Formation in the Muglad Basin were analysed using geochemical and petrographic analyses. These analyses were used to define the origin, type of organic matters and the influencing factors of diagenesis, including organic matter input and preservation, and their relation to paleoenvironmental and paleoclimate conditions. The bulk geochemical characteristics indicated that the organic-rich shales were deposited in a lacustrine environment with seawater influence under suboxic conditions. Their pyrolysis hydrogen index (HI) data provide evidence for a major contribution by Type I/II kerogen with HI values of >400 mg HC/g TOC and a minor Type II/III contribution with HI values <400 mg HC/g TOC. This is confirmed by kerogen microscopy, whereby the kerogen is characterized by large amounts of structured algae (Botryococcus) and structureless (amorphous) with a minor terrigenous organic matter input. An enhanced biological productivity within the photic zone of the water columns is also detected. The increased biological productivity in the organic-rich shales may be related to enhanced semi-arid/humid to humid-warm climate conditions. Therefore, a high bio-productivity in combination with good organic matter preservation favoured by enhanced algae sizes are suggested as the OM enrichment mechanisms within the studied basin.  相似文献   

13.
Natural gas samples from two gas fields located in Eastern Kopeh-Dagh area were analyzed for molecular and stable isotope compositions. The gaseous hydrocarbons in both Lower Cretaceous clastic reservoir and Upper Jurassic carbonate reservoir are coal-type gases mainly derived from type III kerogen, however enriched δD values of methane implies presence of type II kerogen related material in the source rock. In comparison Upper Jurassic carbonate reservoir gases show higher dryness coefficient resulted through TSR, while presence of C1C5 gases in Lower Cretaceous clastic reservoir exhibit no TSR phenomenon. Carbon isotopic values indicate gas to gas cracking and TSR occurrence in the Upper Jurassic carbonate reservoir, as the result of elevated temperature experienced, prior to the following uplifts in last 33–37 million years. The δ13C of carbon dioxide and δ34S of hydrogen sulfide in Upper Jurassic carbonate reservoir do not primarily reflect TSR, as uplift related carbonate rock dissolution by acidic gases and reaction/precipitation of light H2S have changed these values severely. Gaseous hydrocarbons in both reservoirs exhibit enrichment in C2 gas member, with the carbonate reservoir having higher values resulted through mixing with highly-mature-completely-reversed shale gases. It is likely that the uplifts have lifted off the pressure on shale gases, therefore facilitated the migration of the gases into overlying horizons. However it appears that the released gases during the first major uplift (33–37 million years ago) have migrated to both reservoirs, while the second migrated gases have only mixed with Upper Jurassic carbonate reservoir gases. The studied data suggesting that economic accumulations of natural gas/shale gases deeper than Upper Jurassic carbonate reservoir would be unlikely.  相似文献   

14.
Deposition of organic rich black shales and dark gray limestones in the Berriasian-Turonian interval has been documented in many parts of the world. The Early Cretaceous Garau Formation is well exposed in Lurestan zone in Iran and is composed of organic-rich shales and argillaceous limestones. The present study focuses on organic matter characterization and source rock potential of the Garau Formations in central part of Lurestan zone. A total of 81 core samples from 12 exploratory wells were subjected to detailed geochemical analyses. These samples have been investigated to determine the type and origin of the organic matter as well as their petroleum-generation potential by using Rock-Eval/TOC pyrolysis, GC and GCMS techniques. The results showed that TOC content ranges from 0.5 to 4.95 percent, PI and Tmax values are in the range of 0.2 and 0.6, and 437 and 502 °C. Most organic matter is marine in origin with sub ordinary amounts of terrestrial input suggesting kerogen types II-III and III. Measured vitrinite reflectance (Rrandom%) values varying between 0.78 and 1.21% indicating that the Garau sediments are thermally mature and represent peak to late stage of hydrocarbon generation window. Hydrocarbon potentiality of this formation is assessed fair to very good capable of generating chiefly gas and some oil. Biomarker characteristics are used to provide information about source and maturity of organic matter input and depositional environment. The relevant data include normal alkane and acyclic isoprenoids, distribution of the terpane and sterane aliphatic biomarkers. The Garau Formation is characterized by low Pr/Ph ratio (<1.0), high concentrations of C27 regular steranes and the presence of tricyclic terpanes. These data indicated a carbonate/shale source rock containing a mixture of aquatic (algal and bacterial) organic matter with a minor terrigenous organic matter contribution that was deposited in a marine environment under reducing conditions. The results obtained from biomarker characteristics also suggest that the Garau Formation is thermally mature which is in agreement with the results of Rock-Eval pyrolysis.  相似文献   

15.
The molecular composition, stable carbon and hydrogen isotopes and light hydrocarbons of the Upper Paleozoic tight gas in the Daniudi gas field in the Ordos Basin were investigated to study the geochemical characteristics. Tight gas in the Daniudi gas field displays a dryness coefficient (C1/C1–5) of 0.845–0.977 with generally positive carbon and hydrogen isotopic series, and the C7 and C5–7 light hydrocarbons of tight gas are dominated by methylcyclohexane and iso-alkanes, respectively. The identification of gas origin and gas-source correlation indicate that tight gas is coal-type gas, and the gases reservoired in the Lower Permian Shanxi Fm. (P1s) and Lower Shihezi Fm. (P1x) had a good affinity and were derived from the P1s coal-measure source rocks, whereas the gas reservoired in the Upper Carboniferous Taiyuan Fm. (C3t) was derived from the C3t coal-measure source rocks. The molecular and methane carbon isotopic fractionations of natural gas support that the P1x gas was derived from the P1s source rocks. The differences of geochemical characteristics of the C3t gas from different areas in the field suggest the effect of maturity difference of the source rocks rather than the diffusive migration, and the large-scale lateral migration of the C3t gas seems unlikely. Comparative study indicates that the differences of the geochemical characteristics of the P1s gases from the Yulin and Daniudi gas fields originated likely from the maturity difference of the in-situ source rocks, rather than the effect of large-scale lateral migration of the P1s gases.  相似文献   

16.
The Qiongdongnan Basin, South China Sea has received huge thickness (>12 km) of Tertiary-Quaternary sediments in the deepwater area to which great attention has been paid due to the recent discoveries of the SS22-1 and the SS17-2 commercial gas fields in the Pliocene-Upper Miocene submarine canyon system with water depth over 1300 m. In this study, the geochemistry, origin and accumulation models of these gases were investigated. The results reveal that the gases are predominated by hydrocarbon gases (98%–99% by volume), with the ratio of C1/C1-5 ranging from 0.92 to 0.94, and they are characterized by relatively heavy δ13C1 (−36.8‰ to −39.4‰) and δDCH4 values (−144‰ to −147‰), similar to the thermogenic gases discovered in the shallow water area of the basin. The C5-7 light hydrocarbons associated with these gases are dominated by isoparaffins (35%–65%), implying an origin from higher plants. For the associated condensates, carbon isotopic compositions and high abundance of oleanane and presence of bicadinanes show close affinity with those from the YC13-1 gas field in the shallow water area. All these geochemical characteristics correlate well with those found in the shales of the Oligocene Yacheng Formation in the Qiongdongnan Basin. The Yacheng Formation in the deepwater area has TOC values in the range of 0.4–21% and contains type IIb–III gas-prone kerogens, indicating an excellent gas source rock. The kinetic modeling results show that the δ13C1 values of the gas generated from the Yacheng source rock since 3 or 4 Ma are well matched with those of the reservoir gases, indicating that the gas pool is young and likely formed after 4 Ma. The geologic and geochemical data show that the mud diapirs and faults provide the main pathways for the upward migration of gases from the deep gas kitchen into the shallow, normally pressured reservoirs, and that the deep overpressure is the key driving force for the vertical and lateral migration of gas. This gas migration pattern implies that the South Low Uplift and the No.2 Fault zone near the deepwater area are also favorable for gas accumulation because they are located in the pathway of gas migration, and therefore more attention should be paid to them in the future.  相似文献   

17.
The quantitative characterization of carbon isotopes of n-alkanes is commonly carried out in organic geochemical studies. Possible controls on carbon isotopes include source organic matter, maturity, fractionation during oil expulsion and migration, and the mixing of different oils. In this study of the origin of crude oils in the western Pearl River Mouth Basin, the influences of all of these factors have been considered in reaching a conclusion. Carbon isotopes of n-alkanes in the crude oils, and the extracts of the two effective source rocks (the Wenchang and Enping formations) in the basin, exhibit clear differences. The Wenchang source rocks have heavy δ13C values that remain almost constant or become slightly heavier with increasing carbon number. The Enping source rocks have light δ13C values that become lighter with increasing carbon number. Two groups of oils in this area were identified based on the carbon isotopes of the n-alkanes; groupIoils are similar to extracts of the Wenchang source rocks. However, the groupIIoils are different from both the Wenchang and Enping source rocks and the carbon isotopic profiles of their n-alkanes exhibit a “V” feature with increasing carbon number. The results of artificial thermal maturation experiments indicate that, from the early stage to the peak stage of oil generation (with EasyRo between 0.64% and 1.02%), the δ13C values of n-alkanes in the pyrolysis oils become heavier by about 3‰ with increasing thermal maturity, but the shape of the carbon isotopic profiles are not significantly changed. Calculated δ13C values of n-alkanes in “mixed” artificial pyrolysis oils indicate that the mixture of oils generated from the same source rocks with different maturities could not change the carbon isotopic profile of the n-alkanes, however, a mixing of the Wenchang and Enping oils could give the “V” feature in the profiles, similar to the groupIIoils in this area. The groupIIoils appear to be mixed Wenchang and Enping oils, the latter being the dominant component in the mixture. We conclude that the source organic matter and the degree of mixing are the main factors controlling the carbon isotopic characteristics of n-alkanes in crude oils in the western Pearl River Mouth Basin.  相似文献   

18.
The Upper Cretaceous Mukalla coals and other organic-rich sediments which are widely exposed in the Jiza-Qamar Basin and believed to be a major source rocks, were analysed using organic geochemistry and petrology. The total organic carbon (TOC) contents of the Mukalla source rocks range from 0.72 to 79.90% with an average TOC value of 21.50%. The coals and coaly shale sediments are relatively higher in organic richness, consistent with source rocks generative potential. The samples analysed have vitrinite reflectance in the range of 0.84–1.10 %Ro and pyrolysis Tmax in the range of 432–454 °C indicate that the Mukalla source rocks contain mature to late mature organic matter. Good oil-generating potential is anticipated from the coals and coaly shale sediments with high hydrogen indices (250–449 mg HC/g TOC). This is supported by their significant amounts of oil-liptinite macerals are present in these coals and coaly shale sediments and Py-GC (S2) pyrograms with n-alkane/alkene doublets extending beyond nC30. The shales are dominated by Type III kerogen (HI < 200 mg HC/g TOC), and are thus considered to be gas-prone.One-dimensional basin modelling was performed to analysis the hydrocarbon generation and expulsion history of the Mukalla source rocks in the Jiza-Qamar Basin based on the reconstruction of the burial/thermal maturity histories in order to improve our understanding of the of hydrocarbon generation potential of the Mukalla source rocks. Calibration of the model with measured vitrinite reflectance (Ro) and borehole temperature data indicates that the present-day heat flow in the Jiza-Qamar Basin varies from 45.0 mW/m2 to 70.0 mW/m2 and the paleo-heat flow increased from 80 Ma to 25 Ma, reached a peak heat-flow values of approximately 70.0 mW/m2 at 25 Ma and then decreased exponentially from 25 Ma to present-day. The peak paleo-heat flow is explained by the Gulf of Aden and Red Sea Tertiary rifting during Oligocene-Middle Miocene, which has a considerable influence on the thermal maturity of the Mukalla source rocks. The source rocks of the Mukalla Formation are presently in a stage of oil and condensate generation with maturity from 0.50% to 1.10% Ro. Oil generation (0.5% Ro) in the Mukalla source rocks began from about 61 Ma to 54 Ma and the peak hydrocarbon generation (1.0% Ro) occurred approximately from 25 Ma to 20 Ma. The modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the Mukalla source rocks began from 15 Ma to present-day.  相似文献   

19.
Assessments of the molecular and isotopic composition of hydrate-bound and dissolved gases in pore water were conducted during the multi-phase gas hydrate project (MHP-09) cruise VER09-03 to the southern basin of Lake Baikal in September 2009. To avoid changes in gas composition during core sampling and transport, various headspace methods were investigated aimed at preserving the dissolved gases in pore water. When distilled water was added to the sediment samples, the concentrations of carbon dioxide and oxygen decreased because of dissolution into the water and/or microbial consumption. When the headspace was not flushed with inert gases, trace levels of hydrogen and ethylene were detected. The findings suggest that best preparation is achieved by flushing the headspace with helium, and adding a saturated aqueous solution of sodium chloride. This improved headspace method served to examine the molecular and isotopic compositions of gas samples retrieved at several new sites in the southern basin. Methane was the major component, and the proportion of ethane ranged widely from 0.0009 to 1.67?mol% of the total hydrocarbon gases. The proportions of propane and higher hydrocarbons were small or less than their detection limits. The carbon isotope signatures suggest that microbial-sourced methane and ethane were dominant in the Peschanka study area, whereas ethane was of thermogenic origin at all other study sites in the southern basin of Lake Baikal.  相似文献   

20.
In order to understand the paleoenvironment of the Early Cambrian black shale deposition in the western part of the Yangtze Block, geochemical and organic carbon isotopic studies have been performed on two wells that have drilled through the Qiongzhusi Formation in the central and southeastern parts of Sichuan Basin. It shows that the lowest part of the Qiongzhusi Formation has high TOC abundance, while the middle and upper parts display relative low TOC content. Redox-sensitive element (Mo) and trace elemental redox indices (e.g., Ni/Co, V/Cr, U/Th and V/(V + Ni)) suggest that the high-TOC layers were deposited under anoxic conditions, whereas the low-TOC layers under relatively dysoxic/oxic conditions. The relationship of the enrichment factors of Mo and U further shows a transition from suboxic low-TOC layers to euxinic high-TOC layers. On the basis of the Mo-TOC relationship, the Qiongzhusi Formation black shales were deposited in a basin under moderately restricted conditions. Organic carbon isotopes display temporal variations in the Qiongzhusi Formation, with a positive excursion of δ13Corg values in the lower part and a continuous positive shift in the middle and upper parts. All these geochemical and isotopic criteria indicate a paleoenvironmental change from bottom anoxic to middle and upper dysoxic/oxic conditions for the Qiongzhusi Formation black shales. The correlation of organic carbon isotopic data for the Lower Cambrian black shales in different regions of the Yangtze Block shows consistent positive excursion of δ13Corg values in the lower part for each section. This excursion can be ascribed to the widespread Early Cambrian transgression in the Yangtze Block, under which black shales were deposited.  相似文献   

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