Primary cracking of kerogens. Experimenting and modelling C1, C2–C5, C6–C15 and C15+ classes of hydrocarbons formed

Mathematical models of hydrocarbon formation can be used to simulate the natural evolution of different types of organic matter and to make an overall calculation of the amounts of oil and/or gas produced during this evolution. However, such models do not provide any information on the composition of the hydrocarbons formed or on how they evolve during catagenesis.From the kinetic standpoint, the composition of the hydrocarbons formed can be considered to result from the effect of “primary cracking” reactions having a direct effect on kerogen during its evolution as well as from the effect of “secondary cracking” acting on the hydrocarbons formed.This report gives experimental results concerning the “primary cracking” of Types II and III kerogens and their modelling. For this, the hydrocarbons produced have been grouped into four classes (C₁, C₂–C₅, C₆–C₁₅ and C₁₅₊). Experimental data corresponding to these different classes were obtained by the pyrolysis of kerogens with temperature programming of 4°C/min with continuous analysis, during heating, of the amount of hydrocarbons corresponding to each of these classes.The kinetic parameters of the model were optimized on the basis of the results obtained. This model represents the first step in the creation of a more sophisticated mathematical model to be capable of simulating the formation of different hydrocarbon classes during the thermal history of sediments. The second step being the adjustment of the kinetic parameters of “secondary cracking”.     

Biomarker distributions in asphaltenes and kerogens analysed by flash pyrolysis-gas chromatography-mass spectrometry

Biomarker distributions in a suite of asphaltenes and kerogens have been analysed by flash pyrolysis directly coupled to a GCMS system. Attention has been focussed on biomarkers of the sterane and triterpane types. The sample suite under investigation consists of sediments with different kerogen types and some crude oils. Biomarker distributions in the pyrolysates have been compared with the “free” biomarkers in the corresponding saturated hydrocarbon fractions.The analyses show significant differences between the distributions of the free biomarkers and those in the pyrolysates. The latter have lower amounts of steranes while diasteranes are absent or present at low concentrations only. In the triterpane traces a shift of maximum intensity from C₃₀ (free compounds) to C₂₇/C₂₉ is observed. Furthermore, the pyrolysates contain a set of triterpenes (not present among the free compounds), and there is a selective loss of “non-regular” triterpanes that are present in the saturated hydrocarbon fractions. The observed differences between pyrolysates and free hydrocarbons can be explained partly by the processes occurring during pyrolysis such as bond rupture and subsequent stabilisation of primary pyrolysis products. To a certain extent these differences also show that maturation processes occurring in sediments have effects on free biomarker molecules different from those on molecules that are enclosed in a macromolecular matrix (kerogen or asphaltenes).Differences between biomarker distributions of asphaltene and kerogen pyrolysates are relatively small. A comparison with the pyrolysates from extracted whole sediments suggests that these differences are mainly caused by interactions between the organic material and the mineral matrix during pyrolysis.Oil asphaltenes behave differently from sediment asphaltenes as their pyrolysates are more similar to the corresponding saturated hydrocarbon fractions, i.e. the differences described above are observed to a much smaller extent. This different behaviour appears to be the result of coprecipitation of a part of the maltene fraction with the oil asphaltenes.     

Geochemical Characteristics of Different Kinds of Crude Oils in the Tarim Basin,Northwest China

Based on the compositions and distributions of biomarkers in thirty-five representative oil samples, oils from the Tarim Basin of northwestern China are mainly divided into two oil families. One oil family contains relatively low amounts of C₁₅-C₂₀ isoprenoid hydrocarbons and shows pristane predominance with Pr/Ph ratios ranging from 1.50 to 3.00. The GC/MS analytical data of these oils show the occurrence of abundant hopanes, and low concentrations of steranes and tricyclic terpanes with hopanes/steranes ratios from 6.25 to 12.24 and tricyclic terpanes/hopanes ratios from 0.03 to 0.24. These oils contain low drimane relative to homodrimane (C₁₅/C₁₆ < 1.0) and abundant rearranged bicyclanes in bicyclic sesquiterpanes. They are dominated by low carbon number (C₁₉-C₂₁) compounds in the tricyclic terpanes, and are rich in rearranged hopanes, C₂₉Ts and an unknown C₃₀ compound in pentacyclic triterpanes. These geochemical characteristics suggest that the oils were generated mainly from terrigenous organic matter. The other oil family shows remarkably different biomarker compositions and distributions. The oils revealed Pr/Ph ratios of about 1.0, high drimane/homodrimane ratios (>1.0), low hopanes/steranes ratios (0.65–2.50), high tricyclic terpanes/hopanes ratios (0.30–2.00) and a dominant peak at C₂₃ in tricyclic tepanes, suggesting a marine organic origin. Oil-source rock correlation indicates that these two oil families seem to have been derived from Mesozoic Jurassic-Triassic terrestrial source rocks (shales and coal seams) and Lower Paleozoic Ordovician-Cambrian marine source rocks, respectively.     

New aromatic biomarkers and possible maturity indicators found in New Albany Shale extracts

Aromatic hydrocarbons from benzene extracts of New Albany Shale were characterized. A biomarker that has a molecular weight of 546 and a structural configuration consistent with that of an alkyl-aromatic hydrocarbon (C₄₀H₆₆) was tentatively identified. It was found that the relative concentrations of the biomarker are indicative of differing levels of thermal maturity of the shale organic matter. A 40-carbon bicyclic carotenoid (C₄₀H₄₈) is proposed as the geochemical precursor of this biomarker. Thermal maturity of the shale organic matter can also be differentiated by observing differences in “fingerprints” as obtained by field-ionization mass spectrometry on the aromatic hydrocarbon fraction. Using this technique, we found that the more mature shale samples from southeastern Illinois contain more low molecular weight extractable aromatic hydrocarbons and the less mature shale samples from northwestern Illinois contain more high molecular weight extractable aromatic hydrocarbons. It was demonstrated that field-ionization and tandem mass spectrometric techniques through fingerprint and individual compound identification, are useful for shale aromatic hydrocarbon fraction characterization and for thermal maturation interpretation.     

Characterization of nC7-soluble fractions of the products from mild oxidation of asphaltenes

A significant quantity of hydrocarbons (including alkanes) is occluded in the skeleton of the asphaltene molecule. The hydrocarbons are probably remnants of the “original oil” which had been retained within the asphaltene matrix and protected from the secondary alteration processes that occurred subsequently in the oil reservoirs. In this work we report that oxidation of asphaltenes by stirring with 30%H₂O₂–HAc or NaIO₄–NaH₂PO₄ can release nC₇-soluble oxidized products, including the occluded hydrocarbons. Characterization of the nC₇-soluble fractions of oxidized products can be applied to highlight some geochemical problems, such as in studies of oil–oil correlation, oil–source correlation and secondary alterations of oil reservoirs. It will be especially useful to recover the original geochemical information of some oil reservoirs heavily degraded by post-depositional processes.     

Gas accumulation from oil cracking in the eastern Tarim Basin: A case study of the YN2 gas field

Oil and gas exploration in eastern Tarim Basin, NW China has been successful in recent years, with several commercial gas accumulations being discovered in a thermally mature to over-mature region. The Yingnan2 (YN2) gas field, situated in the Yingnan structure of the Yingjisu Depression, produces gases that are relatively enriched in nitrogen and C₂₊ alkanes. The δ¹³C₁ (−38.6‰ to −36.2‰) and δ¹³C₂ values (−30.9‰ to −34.7‰) of these gases are characteristic of marine sourced gases with relatively high maturity levels. The distributions of biomarkers in the associated condensates suggest close affinities with the Cambrian–Lower Ordovician source rocks which, in the Yingjisu Sag, are currently over-mature (with 3–4%Ro). Burial and thermal maturity modeling results indicate that paleo-temperatures of the Cambrian–Lower Ordovician source rocks had increased from 90 to 210 °C during the late Caledonian orogeny (458–438 Ma), due to rapid subsidence and sediment loading. By the end of Ordovician, hydrocarbon potential in these source rocks had been largely exhausted. The homogenization temperatures of hydrocarbon fluid inclusions identified from the Jurassic reservoirs of the YN2 gas field suggest a hydrocarbon emplacement time as recent as about 10 Ma, when the maturity levels of Middle–Lower Jurassic source rocks in the study area were too low (<0.7%Ro) to form a large quantity of oil and gas. The presence of abundant diamondoid hydrocarbons in the associated condensates and the relatively heavy isotopic values of the oils indicate that the gases were derived from thermal cracking of early-formed oils. Estimation from the stable carbon isotope ratios of gaseous alkanes suggests that the gases may have been formed at temperatures well above 190 °C. Thus, the oil and gas accumulation history in the study area can be reconstructed as follows: (1) during the late Caledonian orogeny, the Cambrian–Lower Ordovician marine source rocks had gone through the peak oil, wet gas and dry gas generation stages, with the generated oil and gas migrating upwards along faults and fractures to form early oil and gas accumulations in the Middle–Upper Ordovician and Silurian sandstone reservoirs; (2) since the late Yanshanian orogeny, the early oil accumulations have been buried deeper and oil has undergone thermal cracking to form gas; (3) during the late Himalayan orogeny, the seals for the deep reservoirs were breached; and the gas and condensates migrated upward and eventually accumulating in the relatively shallow Jurassic reservoirs.     

The optical features and hydrocarbon-generating model of “barkinite” from Late Permian coals in South China

Leping coal is known for its high content of “barkinite”, which is a unique liptinite maceral apparently found only in the Late Permian coals of South China. “Barkinite” has previously identified as suberinite, but on the basis of further investigations, most coal petrologists conclude that “barkinite” is not suberinite, but a distinct maceral. The term “barkinite” was introduced by (State Bureau of Technical Supervision of the People's Republic of China, 1991, GB 12937-91 (in Chinese)), but it has not been recognized by ICCP and has not been accepted internationally.In this paper, elemental analyses (EA), pyrolysis-gas chromatography, Rock-Eval pyrolysis and optical techniques were used to study the optical features and the hydrocarbon-generating model of “barkinite”. The results show that “barkinite” with imbricate structure usually occurs in single or multiple layers or in a circular form, and no definite border exists between the cell walls and fillings, but there exist clear aperture among the cells.“Barkinite” is characterized by fluorescing in relatively high rank coals. At low maturity of 0.60–0.80%R_o, “barkinite” shows strong bright orange–yellow fluorescence, and the fluorescent colors of different cells are inhomogeneous in one sample. As vitrinite reflectance increases up to 0.90%R_o, “barkinite” also displays strong yellow or yellow–brown fluorescence; and most of “barkinite” lose fluorescence at the maturity of 1.20–1.30%R_o. However, most of suberinite types lose fluorescence at a vitrinite reflectance of 0.50% Ro, or at the stage of high volatile C bituminous coal. In particular, the cell walls of “barkinite” usually show red color, whereas the cell fillings show yellow color under transmitted light. This character is contrary to suberinite.“Barkinite” is also characterized by late generation of large amounts of liquid oil, which is different from the early generation of large amounts of liquid hydrocarbon. In addition, “barkinite” with high hydrocarbon generation potential, high elemental hydrogen, and low carbon content. The pyrolysis products of “barkinite” are dominated by aliphatic compounds, followed by low molecular-weight aromatic compounds (benzene, toluene, xylene and naphthalene), and a few isoprenoids. The pyrolysis hydrocarbons of “barkinite” are mostly composed of light oil (C₆–C₁₄) and wet gas (C₂–C₅), and that heavy oil (C₁₅⁺) and methane (C₁) are the minor hydrocarbon.In addition, suberinite is defined only as suberinized cell walls—it does not include the cell fillings, and the cell lumens were empty or filled by corpocollinites, which do not show any fluorescence. Whereas, “barkinite” not only includes the cell walls, but also includes the cell fillings, and the cell fillings show bright yellow fluorescence.Since the optical features and the hydrocarbon-generating model of “barkinite” are quite different from suberinite. We suggest that “barkinite” is a new type of maceral.     

鄂尔多斯盆地董志——正宁地区原油地球化学特征与成因

鄂尔多斯盆地董志—正宁地区是该盆地中生界油气勘探新区,对该地区原油的地球化学进行研究,了解原油的成因,可以为该地区石油勘探和开发提供科学依据。本研究首次对采集于董志—正宁地区原油和鄂尔多斯盆地烃源岩的烃类生物标志化合物进行了系统的分析,研究了它们的地球化学特征。原油中各类烃类生物标志化合物分布和组成特征指示了原油形成于...     

Stable carbon isotope compositions and source rock geochemistry of the giant gas accumulations in the Ordos Basin, China

Ordos Basin, the second largest sedimentary basin in China, contains enormous natural gas resources. Each of the four giant gas fields discovered so far in this basin (i.e., Sulige, Yulin, Wushenqi and Jingbian) has over 100 billion cubic meters (bcm) or 3.53 trillion cubic feet (tcf) of proven gas reserves. This study examines the stable carbon isotope data of 125 gas samples collected from the four giant gas fields in the Ordos Basin. Source rocks in the Upper Paleozoic coal measures are suggested by the generally high δ¹³C values of C₁–C₄ gaseous hydrocarbons in the gases from the Sulige, Yulin and Wushenqi gas fields. While the δ¹³C_iC4 value is higher than that of the δ¹³C_nC4, the dominant ranges for the δ¹³C₁, δ¹³C₂, and δ¹³C₃ values in these Upper Paleozoic reservoired gases are −34 to −32‰, −27 to −23‰, and −25 to −24‰, respectively. The δ¹³C values of methane, benzene and toluene in gases from the Lower Paleozoic reservoirs of the Jingbian field indicate a significant contribution from humic source rocks, as they are similar to those in the Upper Paleozoic reservoirs of the Sulige, Yulin and Wushenqi gas fields. However, the wide variation and reversal in the δ¹³C₁, δ¹³C₂ and δ¹³C₃ values in the Jinbian gases cannot be explained using a single source scenario, thus the gases were likely derived dominantly from the Carboniferous-Permian coal measures with some contribution from the carbonates in the Lower Permian Taiyuan Formation. The gas isotope data and extremely low total organic carbon contents (<0.2% TOC) suggest that the Ordovician Majiagou Formation carbonates are unlikely to be a significant gas source rock, thus almost all of the economic gas accumulations in the Ordos Basin were derived from Upper Paleozoic source rocks.     

Oil-generating coals of the San Juan Basin, New Mexico and Colorado, U.S.A.

Coal beds of the Upper Cretaceous Fruitland Formation in the San Juan Basin of northwestern New Mexico and southwestern Colorado have significant liquid hydrocarbon generation potential as indicated by typical Rock-Eval Hydrogen Indexes in the range of 200–400 mg hydrocarbon/g organic carbon (type II and III organic matter). Small, non-commercial quantities of oil have been produced from the coal beds at several locations. The oils are characterized by high pristane/phytane (ca 4) and pristane/n-C₁₇ ratios (ca 1.2), abundant C₂₁₊ alkanes in the C₁₀₊ fraction with a slight predominance of odd carbon-numbered n-alkanes, abundant branched-chain alkanes in the C₁₅₊ region, and a predominance of methylcyclohexane in the C₄----C₁₀ fraction. The oils are indigenous to the Fruitland Formation coals and probably migrated at thermal maturities corresponding to vitrinite reflectance values in the range 0.7–0.8%. Although the oils found to date are not present in commercial amounts, these findings illustrate the potential of some coals to generate and expel oil under conditions of moderate thermal heating.     

Constraining the hydrocarbon expulsion history of the coals in Qinshui Basin, North China, from the analysis of fluid inclusions

From the comprehensive study on the homogenization temperatures and the occurrence of fluid inclusions in the framework minerals of the strata between or above the Carboniferous–Permian coals in the Qinshui basin, Shanxi, three stages are predicted of hydrocarbon expulsion from the coals. Combined with the known history of basin evolution, it is deduced that the expulsion of hydrocarbons happened during the J₁ (210–180 Ma), the early K₁ (150–130 Ma) and K₂E₁ (110–60 Ma). In the early stage, the coals produced and discharged coal-generated oils. The average GOI value of four sandstone samples is relatively high, as they have been exposed to high paleo-oil saturation in the strata between or above the coals. The biomarker compositions of oil-bearing fluid inclusions are similar to those of extracts from the coals, and so it is concluded that those oils were derived from the same family of the coals.     

Scarcity of the C30 sterane biomarker, 24-n-propylcholestane,in Lower Paleozoic marine paleoenvironments

24-n-Propylcholestane (24-npc), a C₃₀ sterane compound derived from sterol precursors which are the major sterol constituents of modern pelagophyte microalgae, occurs in certain Neoproterozoic rocks and oils and throughout the Phanerozoic rock record. This broad distribution leads 24-npc to be widely considered a reliable indicator of open to partially restricted marine depositional conditions for source rocks and oils. Here we report two significant hiatuses in the occurrences of 24-npc in the Lower Paleozoic marine rock record: the first in the Middle–Late Cambrian and the second in the Late Ordovician–early Silurian transition for a range of lithofacies (carbonates and siliciclastic rocks), organic carbon contents (both organic-lean and organic-rich), and paleoceanographic environments (shelf and deeper water marine settings) and observed offshore of two paleocontinents, Laurentia and Baltica. The Ordovician–Silurian gap is at least 9 million years, and possibly up to 20 million years, in duration. Robust older occurrences of 24-npc steranes in some Neoproterozoic rocks and oils suggest that oceanographic conditions in our intervals of Lower Paleozoic time were unfavorable for the proliferation of pelagophyte algae as phytoplankton. Caution should therefore be applied when interpreting a lacustrine versus marine depositional environmental setting for source rocks and oils in these intervals of Early Paleozoic time using lipid biomarker assemblages.     

Origin of the Neogene shallow gas accumulations in the Jiyang Superdepression, Bohai Bay Basin

Natural gas resources occur extensively along the east coast of China, with a number of large and medium-sized gas fields being discovered in recent years. Gas reservoirs include Neogene, Paleogene and the underlying Mesozoic and Paleozoic basement. Of the total proven natural gas reserves in the Jiyang Superdepression, Bohai Bay Basin, almost 89.7% is present in the shallow Neogene gas pools, in traps formed on top of the paleotopographic highs and along the margin of the secondary depressions. These gases are closely associated with heavy oils, occurring as gas caps or associated gases within the heavy oil pools, or in separate gas pools above, or updip from, the heavy oil pools. The gases contain over 95% methane and small quantities of alkanes, nitrogen and carbon dioxide. The stable carbon isotopes of methane in these gases are up to 10‰ more positive than those of the thermogenic gases in the deep Paleogene reservoirs, with propane more enriched in ¹³C than butane. This study demonstrated that the majority of the petroleum source rocks in the Jiyang Superdepression tend to be oil-prone, and are currently within or shallower than the conventional oil window (0.45–1.0% Ro). The chemical and carbon isotopic compositions of the gases, together with the moderate to severe biodegradation of the associated heavy oils in the shallow Neogene strata, clearly suggest that the formation of the shallow natural gases in the Jiyang Superdepression result from the anaerobic degradation of accumulated oils in reservoir.     

特提斯构造域东段叠合盆地演化和油气成藏规律特征初论

通过分析特提斯构造域东段区域地质和含油气盆地勘探开发基础数据,从板块构造演化入手,系统编制特提斯构造域东段沉积构造演化剖面图和生储盖组合剖面图,研究盆地演化阶段、叠合特征、油气成藏条件及油气藏类型,揭示中亚和中国西部前陆盆地演化和油气富集规律异同。研究表明：古亚洲洋、古特提斯洋和新特提斯洋控制了特提斯构造域东段的区域构造分带、盆地演化、盆地类型及油气成藏模式。根据古洋壳缝合线可分为北、中、南3个构造带,古生代以来多期微板块的拼贴,导致特提斯构造域东段含油气盆地演化分为3个演化阶段,早古生代伸展、晚古生代挤压、早中生代伸展和新生代挤压构造作用控制了研究区盆地的叠合演化,发育下古生界、上古生界和中生界3套区域分布的优质烃源岩和下古生界、上古生界、中生界和新生界4套储盖组合,形成多种类型的油气藏。     

Carbon isotopic composition of individual n-alkanes in asphaltene pyrolysates of biodegraded crude oils from the Liaohe Basin, China

Biodegraded oils are widely distributed in the Liaohe basin, China. In order to develop effective oil-source correlation tools specifically for the biodegraded oils, carbon isotopic compositions of individual n-alkanes from crude oils and their asphaltene pyrolysates have been determined using the gas chromatography–isotope ratio mass spectrometry technique. No significant fractionation in the stable carbon isotopic ratios of n-alkanes in the pyrolysates of oil asphaltenes was found for anhydrous pyrolysis carried out at temperatures below 340°C. This suggests that the stable carbon isotopic distribution of n-alkanes (particularly in the C₁₆–C₂₉ range) in the asphaltene pyrolysates can be used as a correlation tool for severely biodegraded oils from the Liaohe Basin. Comparison of the n-alkane isotopic compositions of the oils with those of asphaltene pyrolysates shows that this is a viable method for the differentiation of organic facies variation and post-generation alterations.     

中国海相碳酸盐岩的储层类型、勘探领域及勘探战略

中国海相碳酸盐岩有效储层成因类型主要包括古风化壳岩溶储层、礁滩储层及层状白云岩储层三大类。陆上中—古生界盆地三类储层均有分布,海上第三系盆地主要发育礁滩储层。针对我国海相油气地质特别是陆上中—古生界油气成藏的复杂性,提出应该加强对勘探及认识程度相对较低的礁滩储层形成的原生岩性-成岩圈闭油气藏的研究与勘探工作。石灰岩古风化壳岩溶储层具有强烈的非均质性,白云岩储层的含油气性比较依赖于有效储盖组合及构造圈闭。鉴于我国海相油气资源潜力巨大、勘探程度较低,故应该加强海相油气资源特别是陆上主要盆地海相油气资源及南海油气资源的研究与勘探开发,尤其要加强层序地层及岩相古地理编图等基础油气地质研究工作。     

Origin and occurrence of 25-norhopanes: a statistical study

The alkane fraction of more than 200 rocks, biodegraded oils and non-biodegraded oils, have been analysed by means of computerized GC-MS, in order to investigate the effect of natural biodegradation on the occurrence of “demethylated hopanes”, i.e. 17α-25-norhopanes. The results obtained indicate that 25-norhopanes are preexisting biomarkers the concentration of which is enhanced by selective biodegradation of more readily degradable homologs, i.e. regular hopanes, rather than by demethylation of hopanes in reservoirs. However, the use of 25-norhopane enrichment as a palaebiodegradation indicator in apparently non-biodegraded oils is still valuable providing the initial background content in the corresponding source rocks is known. Furthermore, 25-norhopanes appear to be diagnostic of specific environmental conditions (marine and lacustrine source rocks, dysoxic and not very hypersaline). Lastly, one other (novel) bacterially resistant rearranged hopanoic compound, namely a C₂₉ neohopane, is applicable for both biodegradation and maturation evaluation.     

The effect of biodegradation on polycyclic aromatic hydrocarbons in reservoired oils from the Liaohe basin, NE China

The occurrence and distribution of polycyclic aromatic hydrocarbons (PAHs) has been studied in oil columns from the Liaohe basin, NE China, characterized by varied degrees of biodegradation. The Es3 oil column has undergone light to moderate biodegradation – ranging from levels 2 to 5 on the [Peters, K.E., Moldowan, J.M., 1993. The Biomarker Guide: Interpreting Molecular Fossils in Petroleum and Ancient Sediments. Prentice Hall, Englewood Cliffs, NJ, p. 363] scale (abbreviated as ‘PM level’) – while the shallower Es1 column has undergone more severe biodegradation, ranging from PM level 5 to 8. Both columns show excellent vertical biodegradation gradients, with degree of biodegradation increasing with increasing depth toward the oil–water contact (OWC). The compositional gradients in the oil columns imply mass transport control on degradation rates, with degradation occurring primarily at the OWC. The diffusion of hydrocarbons to the OWC zone will be the ultimate control on the maximum degradation rate. The chemical composition and physical properties of the reservoired oils, and the ‘degradation sequence’ of chemical components are determined by mixing of fresh oil with biodegraded oil.The PAH concentrations and molecular distributions in the reservoired oils from these biodegraded columns show systematic changes with increasing degree of biodegradation. The C₃₊-alkylbenzenes are the first compounds to be depleted in the aromatic fraction. Concentrations of the C_0–5-alkylnaphthalenes and the C_0–3-alkylphenanthrenes decrease markedly during PM levels 3–5, while significant isomer variations occur at more advanced stages of biodegradation (>PM level 4).The degree of alkylation is a critical factor controlling the rate of biodegradation; in most cases the rate decreases with increasing number of alkyl substituents. However, we have observed that C₃-naphthalenes concentrations decrease faster than those of C₂-naphthalenes, and methylphenanthrenes concentrations decrease faster than that of phenanthrene. Demethylation of a substituted compound is inferred as a possible reaction in the biodegradation process.Differential degradation of specific alkylated isomers was observed in our sample set. The relative susceptibility of the individual dimethylnaphthalene, trimethylnaphthalene, tetramethylnaphthalene, pentamethylnaphthalene, methylphenanthrene, dimethylphenanthrene and trimethylphenanthrene isomers to biodegradation was determined. The C₂₀ and C₂₁ short side-chained triaromatic steroid hydrocarbons are degraded more readily than their C_26–28 long side-chained counterparts. The C_21–22-monoaromatic steroid hydrocarbons (MAS) appear to be more resistant to biodegradation than the C_27–29-MAS.Interestingly, the most thermally stable PAH isomers are more susceptible to biodegradation than less thermally stable isomers, suggesting that selectivity during biodegradation is not solely controlled by thermodynamic stability and that susceptibility to biodegradation may be related to stereochemical structure. Many commonly used aromatic hydrocarbon maturity parameters are no longer valid after biodegradation to PM level 4 although some ratios change later than others. The distribution of PAHs coupled with knowledge of their biodegradation characteristics constitutes a useful probe for the study of biodegradation processes and can provide insight into the mechanisms of biodegradation of reservoired oil.     

Pacific superplume-related oceanic basalts hosted by accretionary complexes of Central Asia, Russian Far East and Japan

Plume-related oceanic magmatism form oceanic islands, seamounts and plateaus (hereafter “seamounts” or “paleoseamounts”), which are important features in geological history. The accretion of oceanic seamounts to active continental margins significantly contributed to the formation of the continental crust. This paper reviews occurrences of Late Neoproterozoic–Mesozoic seamounts of the Paleo-Asian and Paleo-Pacific oceans, which are hosted by accretionary complexes (ACs) of Russian Altai, East Kazakhstan, Mongolia, Russian Far East and Japan. The paleoseamounts commonly consist of Ti–LREE–Nb-enriched plume-related basalts (OIB-type or intraplate basalts) capped with massive limestone and associated with other units of oceanic plate stratigraphy (OPS): oceanic floor basalts (MORB), pelagic chert, epiclastic slope facies, etc. The paper presents available geochemical data on the plume-related basalts including the first geochemical data on the Middle Paleozoic OIB-type basalts of the Paleo-Asian Ocean hosted by the Ulaanbaatar AC of Mongolia. An emphasis is made for the structural setting of OPS units, specific geochemical features of intraplate basalts, problems of their identification, and distinguishing from magmatic units of a different origin such as MORB, island-arc and back-arc basalts. Finally, we propose a continuous, though periodical, evolution of the Pacific superplume-related magmatism, which can be more reliably proved by studying Middle Paleozoic OPS units hosted by ACs of Mongolia and Tien Shan, and discuss prospects of future studies.     

Terpenoid biomarker distributions in low maturity crude oils

Twenty-seven heavy crude oils of diverse origin were geochemically assessed with respect to both bulk and mlecular composition for the purpose of identifying and quanttfying valid biomarker parameters for low maturity oils. The low thermal maturity level of many of these oils is evident from the bulk and alipathic chromatographic data, and oil sourced from both marine and terrigenous organic matter are represented. Selective metastable ion monitoring (SMIM) was employed to measure separately the distribution of C₂₇, C₂₈, and C₂₉ sterane isomers. The useful maturity indicators include the C₂₉ 5α(H) 20S/20R ratio, the relative quantity of the biological sterane configuration in each of the total normal C₂₇, C₂₈, and C₂₉ steranes, and the rearranged to normal sterane ratio. In addition, C₂₇ rearranged steran es appear to form at a faster rate than C₂₈ or C₂₉ rearranged steranes. However, the isomerization of the C₂₇ biological component appears to occur at a slower rate than the C₂₉ counterpart suggesting that the former may be used as a maturity parameter at higher levels of thermal maturation. In the triterpane distributions, the C₂₇ trisnorhopane isomers and the moretane to hopane ratios appear to be both source and maturity related and cannot be used as successful maturity parameters in oils unless they share a common source. The C₃₁₊ hopane 22S/22R equilibrium ratio appears to increase with increasing molecular weight (C₃₁–C₃₄).