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1.
Andrea Jaeschke Michael D. Lewan Ellen C. Hopmans Stefan Schouten Jaap S. Sinninghe Damst 《Organic Geochemistry》2008,39(12):1735
Anaerobic ammonium oxidation (anammox) has been recognized as a major process resulting in loss of fixed inorganic nitrogen in the marine environment. Ladderane lipids, membrane lipids unique to anammox bacteria, have been used as markers for the detection of anammox in marine settings. However, the fate of ladderane lipids after sediment burial and maturation is unknown. In this study, anammox bacterial cell material was artificially matured by hydrous pyrolysis at constant temperatures ranging from 120 to 365 °C for 72 h to study the stability of ladderane lipids during progressive dia- and catagenesis. HPLC-MS/MS analysis revealed that structural alterations of ladderane lipids already occurred at 120 °C. At temperatures >140 °C, ladderane lipids were absent and only more thermally stable products could be detected, i.e., ladderane derivatives in which some of the cyclobutane rings were opened. These diagenetic products of ladderane lipids were still detectable up to temperatures of 260 °C using GC-MS. Thus, ladderane lipids are unlikely to occur in ancient sediments and sedimentary rocks, but specific diagenetic products of ladderane lipids will likely be present in sediments and sedimentary rocks of relatively low maturity (i.e., C31 hopane 22S/(22S + 22R) ratio <0.2 or ββ/(αβ + βα + ββ) ratio of >0.5). 相似文献
2.
The Menilite Shales (Oligocene) of the Polish Carpathians are the source of low-sulfur oils in the thrust belt and some high-sulfur oils in the Carpathian Foredeep. These oil occurrences indicate that the high-sulfur oils in the Foredeep were generated and expelled before major thrusting and the low-sulfur oils in the thrust belt were generated and expelled during or after major thrusting. Two distinct organic facies have been observed in the Menilite Shales. One organic facies has a high clastic sediment input and contains Type-II kerogen. The other organic facies has a lower clastic sediment input and contains Type-IIS kerogen. Representative samples of both organic facies were used to determine kinetic parameters for immiscible oil generation by isothermal hydrous pyrolysis and S2 generation by non-isothermal open-system pyrolysis. The derived kinetic parameters showed that timing of S2 generation was not as different between the Type-IIS and -II kerogen based on open-system pyrolysis as compared with immiscible oil generation based on hydrous pyrolysis. Applying these kinetic parameters to a burial history in the Skole unit showed that some expelled oil would have been generated from the organic facies with Type-IIS kerogen before major thrusting with the hydrous-pyrolysis kinetic parameters but not with the open-system pyrolysis kinetic parameters. The inability of open-system pyrolysis to determine earlier petroleum generation from Type-IIS kerogen is attributed to the large polar-rich bitumen component in S2 generation, rapid loss of sulfur free-radical initiators in the open system, and diminished radical selectivity and rate constant differences at higher temperatures. Hydrous-pyrolysis kinetic parameters are determined in the presence of water at lower temperatures in a closed system, which allows differentiation of bitumen and oil generation, interaction of free-radical initiators, greater radical selectivity, and more distinguishable rate constants as would occur during natural maturation. Kinetic parameters derived from hydrous pyrolysis show good correlations with one another (compensation effect) and kerogen organic-sulfur contents. These correlations allow for indirect determination of hydrous-pyrolysis kinetic parameters on the basis of the organic-sulfur mole fraction of an immature Type-II or -IIS kerogen. 相似文献
3.
Robert F Dias Katherine H FreemanMichael D Lewan Stephen G Franks 《Geochimica et cosmochimica acta》2002,66(15):2755-2769
Low-molecular-weight (LMW) aqueous organic acids were generated from six oil-prone source rocks under hydrous-pyrolysis conditions. Differences in total organic carbon-normalized acid generation are a function of the initial thermal maturity of the source rock and the oxygen content of the kerogen (OI). Carbon-isotope analyses were used to identify potential generation mechanisms and other chemical reactions that might influence the occurrence of LMW organic acids. The generated LMW acids display increasing 13C content as a function of decreasing molecular weight and increasing thermal maturity. The magnitudes of observed isotope fractionations are source-rock dependent. These data are consistent with δ13C values of organic acids presented in a field study of the San Joaquin Basin and likely reflect the contributions from alkyl-carbons and carboxyl-carbons with distinct δ13C values. The data do not support any particular organic acid generation mechanism. The isotopic trends observed as a function of molecular weight, thermal maturity, and rock type are not supported by either generation mechanisms or destructive decarboxylation. It is therefore proposed that organic acids experience isotopic fractionation during generation consistent with a primary kinetic isotope effect and subsequently undergo an exchange reaction between the carboxyl carbon and dissolved inorganic carbon that significantly influences the carbon isotope composition observed for the entire molecule. Although generation and decarboxylation may influence the δ13C values of organic acids, in the hydrous pyrolysis system described, the nondestructive, pH-dependent exchange of carboxyl carbon with inorganic carbon appears to be the most important reaction mechanism controlling the δ13C values of the organic acids. 相似文献
4.
This study examined the molecular and isotopic compositions of gases generated from different kerogen types (i.e., Types I/II, II, IIS and III) in Menilite Shales by sequential hydrous pyrolysis experiments. The experiments were designed to simulate gas generation from source rocks at pre-oil-cracking thermal maturities. Initially, rock samples were heated in the presence of liquid water at 330 °C for 72 h to simulate early gas generation dominated by the overall reaction of kerogen decomposition to bitumen. Generated gas and oil were quantitatively collected at the completion of the experiments and the reactor with its rock and water was resealed and heated at 355 °C for 72 h. This condition simulates late petroleum generation in which the dominant overall reaction is bitumen decomposition to oil. This final heating equates to a cumulative thermal maturity of 1.6% Rr, which represents pre-oil-cracking conditions. In addition to the generated gases from these two experiments being characterized individually, they are also summed to characterize a cumulative gas product. These results are compared with natural gases produced from sandstone reservoirs within or directly overlying the Menilite Shales. The experimentally generated gases show no molecular compositions that are distinct for the different kerogen types, but on a total organic carbon (TOC) basis, oil prone kerogens (i.e., Types I/II, II and IIS) generate more hydrocarbon gas than gas prone Type III kerogen. Although the proportionality of methane to ethane in the experimental gases is lower than that observed in the natural gases, the proportionality of ethane to propane and i-butane to n-butane are similar to those observed for the natural gases. δ13C values of the experimentally generated methane, ethane and propane show distinctions among the kerogen types. This distinction is related to the δ13C of the original kerogen, with 13C enriched kerogen generating more 13C enriched hydrocarbon gases than kerogen less enriched in 13C. The typically assumed linear trend for δ13C of methane, ethane and propane versus their reciprocal carbon number for a single sourced natural gas is not observed in the experimental gases. Instead, the so-called “dogleg” trend, exemplified by relatively 13C depleted methane and enriched propane as compared to ethane, is observed for all the kerogen types and at both experimental conditions. Three of the natural gases from the same thrust unit had similar “dogleg” trends indicative of Menilite source rocks with Type III kerogen. These natural gases also contained varying amounts of a microbial gas component that was approximated using the Δδ13C for methane and propane determined from the experiments. These approximations gave microbial methane components that ranged from 13–84%. The high input of microbial gas was reflected in the higher gas:oil ratios for Outer Carpathian production (115–1568 Nm3/t) compared with those determined from the experiments (65–302 Nm3/t). Two natural gas samples in the far western part of the study area had more linear trends that suggest a different organic facies of the Menilite Shales or a completely different source. This situation emphasizes the importance of conducting hydrous pyrolysis on samples representing the complete stratigraphic and lateral extent of potential source rocks in determining specific genetic gas correlations. 相似文献
5.
M.D Lewan 《Geochimica et cosmochimica acta》1983,47(8):1471-1479
Acquiring crude oils that have been expelled from the same rock unit at different levels of thermal maturation is currently not feasible in the natural system. This prevents direct correlation of compositional changes between the organic matter retained in a source rock and its expelled crude oil at different levels of thermal maturation. Alleviation of this deficiency in studying the natural system requires the use of laboratory experiments. Natural generation of petroleum from amorphous type-II kerogen in the Woodford Shale may be simulated by hydrous pyrolysis, which involves heating crushed rock in contact with water at subcritical temperatures (<374°C). Four distinct stages of petroleum generation are observed from this type of pyrolysis; (1) pre-oil generation, (2) incipient-oil generation, (3) primary-oil generation, and (4) post-oil generation.The effects of thermal maturation on the δ13C values of kerogen, bitumen, and expelled oil-like pyrolysate from the Woodford Shale have been studied through these four stages of petroleum generation. Similar to the natural system, the kerogens isolated from the pyrolyzed rock showed no significant change in δ13C. This suggests that the δ13C value of kerogens may be useful in kerogen typing and oil-to-source rock correlations. δ13C values of bitumens extracted from the pyrolyzed rock showed an initial decrease during the incipient-oil generation stage, followed by depletion during the primary- and post-oil generation stages. This reversal is not favorable for geochemical correlation or maturity evaluation. Saturated and polar components of the bitumen show the greatest δ13C variations with increasing thermal maturation. The difference between the δ13C of these two components gives a unidirectional trend that serves as a general indicator of thermal maturation and is referred to as the bitumen isotope index (BII).δ13C values of the expelled pyrolysates show a unidirectional increase with increasing thermal maturation. The constancy and similarity of δ13C values of the aromatic components in the expelled pyrolysates and bitumens, with increasing thermal maturation, encourages their use in oil-to-oil and oil-to-source rock correlations. Isotopic type-curves for expelled pyrolysates indicate that they may be useful in oil-to- oil correlations, but have a limited use in oil-to-source rock correlations. 相似文献
6.
Dyman T. S. Wyman R. E. Kuuskraa V. A. Lewan M. D. Cook T. A. 《Natural Resources Research》2003,12(1):41-56
From a geological perspective, deep natural gas resources generally are defined as occurring in reservoirs below 15,000 feet, whereas ultradeep gas occurs below 25,000 feet. From an operational point of view, deep may be thought of in a relative sense based on the geologic and engineering knowledge of gas (and oil) resources in a particular area. Deep gas occurs in either conventionally trapped or unconventional (continuous-type) basin-center accumulations that are essentially large single fields having spatial dimensions often exceeding those of conventional fields.Exploration for deep conventional and continuous-type basin-center natural gas resources deserves special attention because these resources are widespread and occur in diverse geologic environments. In 1995, the U.S. Geological Survey estimated that 939 TCF of technically recoverable natural gas remained to be discovered or was part of reserve appreciation from known fields in the onshore areas and state waters of the United States. Of this USGS resource, nearly 114 trillion cubic feet (Tcf) of technically recoverable gas remains to be discovered from deep sedimentary basins. Worldwide estimates of deep gas also are high. The U.S. Geological Survey World Petroleum Assessment 2000 Project recently estimated a world undiscovered conventional gas resource outside the U.S. of 844 Tcf below 4.5 km (about 15,000 feet).Less is known about the origins of deep gas than about the origins of gas at shallower depths because fewer wells have been drilled into the deeper portions of many basins. Some of the many factors contributing to the origin and accumulation of deep gas include the initial concentration of organic matter, the thermal stability of methane, the role of minerals, water, and nonhydrocarbon gases in natural gas generation, porosity loss with increasing depth and thermal maturity, the kinetics of deep gas generation, thermal cracking of oil to gas, and source rock potential based on thermal maturity and kerogen type. Recent experimental simulations using laboratory pyrolysis methods have provided much information on the origins of deep gas.Technologic problems are among the greatest challenges to deep drilling. Problems associated with overcoming hostile drilling environments (e.g. high temperatures and pressures, and acid gases such as CO2 and H2S) for successful well completion, present the greatest obstacles to drilling, evaluating, and developing deep gas fields. Even though the overall success ratio for deep wells (producing below 15,000 feet) is about 25%, a lack of geological and geophysical information continues to be a major barrier to deep gas exploration.Results of recent finding-cost studies by depth interval for the onshore U.S. indicate that, on average, deep wells cost nearly 10 times more to drill than shallow wells, but well costs and gas recoveries differ widely among different gas plays in different basins.Based on an analysis of natural gas assessments, deep gas holds significant promise for future exploration and development. Both basin-center and conventional gas plays could contain significant deep undiscovered technically recoverable gas resources. 相似文献
7.
John B. Curtis Maciej J. Kotarba Michael D. Lewan Dariusz Wi&#x;c&#x;aw 《Organic Geochemistry》2004,35(11-12):1573
The Oligocene Menilite Shales in the study area in the Polish Flysch Carpathians are organic-rich and contain varying mixtures of Type-II, Type-IIS and Type-III kerogen. The kerogens are thermally immature to marginally mature based on atomic H/C ratios and Rock-Eval data. This study defined three organic facies, i.e., sedimentary strata with differing hydrocarbon-generation potentials due to varying types and concentrations of organic matter. These facies correspond to the Silesian Unit and the eastern and western portions of the Skole Unit. Analysis of oils generated by hydrous pyrolysis of outcrop samples of Menilite Shales demonstrates that natural crude oils reservoired in the flysch sediments appear to have been generated from the Menilite Shales. Natural oils reservoired in the Mesozoic basement of the Carpathian Foredeep appear to be predominantly derived and migrated from Menilite Shales, with a minor contribution from at least one other source rock most probably within Middle Jurassic strata. Definition of organic facies may have been influenced by the heterogeneous distribution of suitable Menilite Shales outcrops and producing wells, and subsequent sample selection during the analytical phases of the study. 相似文献
8.
Anke Putschew Christine Schaeffer-Reiss Philippe Schaeffer Martin P Koopmans Jan W de Leeuw Michael D Lewan Jaap S Sinninghe Damsté James R Maxwell 《Organic Geochemistry》1998,29(8):1875-1890
An immature sulfur-rich marl from the Gessosso-solfifera Formation of the Vena del Gesso Basin (Messinian, Italy) has been subjected to hydrous pyrolysis (160 to 330°C) to simulate maturation under natural conditions. The kerogen of the unheated and heated samples was isolated and the hydrocarbons released by selective chemical degradation (Li/EtNH2 and HI/LiAlH4) were analysed to allow a study of the fate of sulfur- and oxygen-bound species with increasing temperature. The residues from the chemical treatments were also subjected to pyrolysis–GC to follow structural changes in the kerogens. In general, with increasing hydrous pyrolysis temperature, the amounts of sulfide- and ether-bound components in the kerogen decreased significantly. At the temperature at which the generation of expelled oil began (260°C), almost all of the bound components initially present in the unheated sample were released from the kerogen. Comparison with an earlier study of the extractable organic matter using a similar approach and the same samples provides molecular evidence that, with increasing maturation, solvent-soluble macromolecular material was initially released from the kerogen, notably as a result of thermal cleavage of weak carbon–heteroatom bonds (sulfide, ester, ether) even at temperatures as low as 220°C. This solvent-soluble macromolecular material then underwent thermal cleavage to generate hydrocarbons at higher temperatures. This early generation of bitumen may explain the presence of unusually high amounts of extractable organic matter of macromolecular nature in very immature S-rich sediments. 相似文献
9.
Transition metals in source rocks have been advocated as catalysts in determining extent, composition, and timing of natural gas generation (Mango, F. D. (1996) Transition metal catalysis in the generation of natural gas. Org. Geochem.24, 977-984). This controversial hypothesis may have important implications concerning gas generation in unconventional shale-gas accumulations. Although experiments have been conducted to test the metal-catalysis hypothesis, their approach and results remain equivocal in evaluating natural assemblages of transition metals and organic matter in shale. The Permian Kupferschiefer of Poland offers an excellent opportunity to test the hypothesis with immature to marginally mature shale rich in both transition metals and organic matter. Twelve subsurface samples containing similar Type-II kerogen with different amounts and types of transition metals were subjected to hydrous pyrolysis at 330° and 355 °C for 72 h. The gases generated in these experiments were quantitatively collected and analyzed for molecular composition and stable isotopes. Expelled immiscible oils, reacted waters, and spent rock were also quantitatively collected. The results show that transition metals have no effect on methane yields or enrichment. δ13C values of generated methane, ethane, propane and butanes show no systematic changes with increasing transition metals. The potential for transition metals to enhance gas generation and oil cracking was examined by looking at the ratio of the generated hydrocarbon gases to generated expelled immiscible oil (i.e., GOR), which showed no systematic change with increasing transition metals. Assuming maximum yields at 355 °C for 72 h and first-order reaction rates, pseudo-rate constants for methane generation at 330 °C were calculated. These rate constants showed no increase with increasing transition metals. The lack of a significant catalytic effect of transition metals on the extent, composition, and timing of natural gas generation in these experiments is attributed to the metals not occurring in the proper form or the poisoning of potential catalytic microcosms by polar-rich bitumen, which impregnates the rock matrix during the early stages of petroleum formation. 相似文献
10.
M.D Lewan 《Geochimica et cosmochimica acta》1984,48(11):2231-2238
The proportionality of V to Ni in crude oils is determined by the environmental conditions in which their source rocks were deposited. Thermal maturation, migration, and reservoir alterations may change the concentrations of these two metals by addition or subtraction of more labile portions of a crude oil, but their tenacious bonding with high-MW organics suggests that their proportionality to one another should remain unchanged. Eh-pH diagrams offer an explanation of the factors controlling their proportionality and its relationship with S contents. Three Eh-pH regimes are proposed for the natural system. Regime I represents conditions under which Ni+2 is available for bonding and vanadium is unavailable because of its quinquivalent state. Crude oils expelled from source rocks deposited within this regime are expected to have less than 0.10 and low S (<1 weight percent). Regime II represents conditions under which Ni+2-Nickelous cations and vanadyl cations are available with vanadyl cations being hindered in part by the formation of hydroxides and nickelous cations being hindered in part of metastable sulfide ions. Source rocks deposited within this regime expel crude oils with low S contents and V-Ni fractions that range from 0.10 to 0.90. Regime III represents conditions under which vanadyl and trivalent vanadium cations are available for bonding but Ni+2 may be partially hindered by sulfide complexing. Source rocks deposited within this regime expel crude oils that have high S contents and V-Ni fractions greater than 0.50. 相似文献