Organic geochemistry of the Silurian Tanezzuft Formation and crude oils,NC115 Concession,Murzuq Basin,southwest Libya

Thirty-six Silurian core and cuttings samples and 10 crude oil samples from Ordovician reservoirs in the NC115 Concession, Murzuq Basin, southwest Libya were studied by organic geochemical methods to determine source rock organic facies, conditions of deposition, thermal maturity and genetic relationships. The Lower Silurian Hot Shale at the base of the Tanezzuft Formation is a high-quality oil/gas-prone source rock that is currently within the early oil maturity window. The overall average TOC content of the Hot Shale is 7.2 wt% with a maximum recorded value of 20.9 wt%. By contrast, the overlying deposits of the Tanezzuft Formation have an average TOC of 0.6 wt% and a maximum value of 1.1 wt%. The organic matter in the Hot Shale consists predominantly of mixed algal and terrigenous Type-II/III kerogen, whereas the rest of the formation is dominated by terrigenous Type-III organic matter with some Type II/III kerogen. Oils from the A-, B- and H-oil fields in the NC115 Concession were almost certainly derived from marine shale source rocks that contained mixed algal and terrigenous organic input reflecting deposition under suboxic to anoxic conditions. The oils are light and sweet, and despite being similar, were almost certainly derived from different facies and maturation levels within mature source rocks. The B-oils were generated from slightly less mature source rocks than the others. Based on hierarchical cluster analysis (HCA), principal component analysis (PCA), selected source-related biomarkers and stable carbon isotope ratios, the NC115 oils can be divided into two genetic families: Family-I oils from Ordovician Mamuniyat reservoirs were probably derived from older Palaeozoic source rocks, whereas Family-II oils from Ordovician Mamuniyat–Hawaz reservoirs were probably charged from a younger Palaeozoic source of relatively high maturity. A third family appears to be a mixture of the two, but is most similar to Family-II oils. These oil families were derived from one proven mature source rock, the Early Silurian, Rhuddanian Hot Shale. There is a good correlation between the Family-II and -III oils and the Hot Shale based on carbon isotope compositions. Saturated and aromatic maturity parameters indicate that these oils were generated from a source rock of considerably higher maturity than the examined rock samples. The results imply that the oils originated from more mature source rocks outside the NC115 Concession and migrated to their current positions after generation.     

Bicyclic alkanes in source rocks of the Triassic Yanchang Formation in the Ordos Basin and their inconsistency in oil-source correlation

The Triassic Yanchang Formation is the main source rocks for Mesozoic oil in Ordos Basin. The formation includes 10 oil-bearing beds (Ch 1–Ch 10), that each can be further divided into two to three intervals. Abundant C₁₂–C₁₄ and C₁₅–C₁₆ bicyclic alkanes have been detected in the formation in the Xifeng oilfield, Ordos Basin. The C₁₂–C₁₄ group is dominated by C₁₂ and C₁₃, and the C₁₅–C₁₆ group contains abundant C₁₅. The groups show three distribution patterns: A) the C₁₂–C₁₄ group is the major component in the non-source rocks of the Ch 7-1 and Ch 8-1 intervals; B) both groups are abundant and are common in source rocks of the Ch 7-3 interval; and C) the C₁₅–C₁₆ group is the major component in source rocks of the Ch 7-3 interval and also in sediments that contain type Ⅰ or partial sapropel type Ⅱ₁ organic matter (OM) in the Ch 7-2 and Ch 8-1 intervals. Although thermal maturities of the source rocks in the Ch 7 section are similar, they show significant differences with respect to the drimane isomerisation index, which indicates that the drimane rearrangement is controlled by thermal evolution of the sediments, but may also be closely related to the depositional environment. This study determined that reducing environments are more conducive to preservation of drimane than oxic environments. The drimane isomerisation index and the value of the hopane parameter Tm/Ts are positively correlated. The parameter Tm/Ts varies over a wide range within the sequence, and the large variations may be a result of terrigenous OM input by turbidity currents and/or gravity flows, mixed with the autochthonous sediments. Abundant homodrimane in both source rocks may reflect reducing environments in deep lakes and major input of higher plant OM. Organic-rich shale and oil shale in the Ch 7-3 interval of the Yanchang Formation are the primary sources of oil in reservoirs in the Xifeng area. The crude oil is rich in bicyclic alkanes that are dominated by C₁₅–C₁₆ as source rocks with pattern C for bicyclic alkanes, which indicates an origin mainly from the Ch 7-3 interval. The main peaks in all of the crude oils are associated with 8β(H)-drimane and lower abundance of rearranged drimane. However, most of the source rocks have a main peak associated with 8β(H)-homodrimane or rearranged drimane. Weak microbial action, selective degradation and water washing may be the cause of the significant difference in bicyclic sesquiterpane composition between the crude oil and the source rocks. The result suggests that oil-source correlations based on the bicyclic sesquiterpanes are questionable.     

Evaluation method and application of the relative contribution of marine hydrocarbon source rocks in the Tarim basin: A case study from the Tazhong area

In total, 2.37 million tons of marine crude oil originating from mixed source rocks has been discovered in the Tarim basin. Geological and geochemical analyses have confirmed that these mixed hydrocarbons are mainly from two sets of source rocks, including the Cambrian – Lower Ordovician and Middle-Upper Ordovician hydrocarbon source rocks. In this study, we determined the set of source rocks primarily responsible for the mixed hydrocarbons and the next location to be explored. Differences in n-alkane carbon isotopes in end-member oils from Cambrian–Lower Ordovician and Middle-Upper Ordovician source rocks were examined. A material balance model and simulation methods were used to evaluate the relative amounts contributed by each source. The results from known reserves in the Tazhong area show that the mixing ratio or contribution is up to 65% from Cambrian–Lower Ordovician source rocks and is generally higher than that from Middle-Upper Ordovician source rocks. The discovery of deep hydrocarbons has caused the total oil contribution from the Cambrian–Lower Ordovician to increase. The mixing ratio of Cambrian–Lower Ordovician oil varies depending on the well, formation, and block. It increases from west to east horizontally and from top to bottom vertically. Hydrocarbons from Cambrian–Lower Ordovician source rocks migrate upward along faults, and the mixing ratio decreases as the distance from the oil source fault increases. Favorable areas for Cambrian–Lower Ordovician hydrocarbon exploration are deep layers and areas near the fault zone that are connected to deep layers. The material balance model for carbon isotopes and evaluation methods for relative contributions considered differences in relative concentration and carbon isotope structure of n-alkanes. Herein, new methods for the identification and evaluation of hydrocarbons in the petroleum system of this superimposed basin are presented.     

Hydrocarbon potential and palynological study of the Latest Ordovician – Earliest Silurian source rock (Sarchahan Formation) in the Zagros Mountains,southern Iran

Source rock studies are one of the key issues of petroleum exploration activities. In the supercontinent of Gondwana, ice ages related to the Upper Ordovician (Hirnantian) and rising sea levels caused by glacial melting at the end of the Ordovician and Early Silurian (Llandoverian) created excellent source rocks along the margin of Gondwana. Investigations conducted in the Arabian Peninsula have been indicated indicating that the lower Qalibah Formation (the so-called Qusaiba Member or Hot Shale) is a good source rock for the Paleozoic petroleum system in this area. Likewise, the Sarchahan Formation was recently introduced as a source rock in the Zagros Basin of Iran, which is probably equivalent to the Qalibah Formation in the Arabian Peninsula. In this study, samples were prepared from surface and subsurface Paleozoic rock units in Iran's Zagros Basin. The emphasis of the paper was on the Sarchahan Formation in Kuh-e Faraghan, ranging in age from the Late Ordovician (Hirnantian) to Lower Silurian (Llandoverian) to determine whether the high richness of organic matter in the Sarchahan Formation is related to the Late Ordovician or Lower Silurian. The basal part of the Sarchahan Formation belongs to the Late Ordovician (Hirnantian) because of the presence of the persculptus graptolite biozone, while the remainder belongs to the Lower Silurian. The Ordovician and early Llandoverian parts of the Sarchahan Formation contain type II and III kerogen with TOC ranging from 2.94 to 7.19, but the rest of the Sarchahan Formation (late Llandoverian) has TOC ranging from 0.1 to 0.58. Therefore, the Hot Shale in Iran falls within the Hirnantian and early Llandoverian (Rhuddanian), and not the latest Llandoverian (Aeronian and Telychian). Utilizing organic petrography, kerogen type was found II/III. The carbon stable isotope studies revealed that the source rock of hydrocarbons in Dalan and Kangan reservoirs has been the Sarchahan Formation. Based on analytical data, the kerogenous shales in the lower part of the Sarchahan Formation are at end of gas window, and the gamma ray amount is approximately 180 API. This research indicates the differences between the source rocks in the southern and northern Persian Gulf and suggesting, the Hot Shale should be considered in different views and used in modeling studies of sedimentary basins for future exploration targets.     

Origin of hydrocarbon fluids and discussion of abnormal carbon isotopic compositions in the Lishui-Jiaojiang Sag,East China Sea Shelf Basin

The hydrocarbon gases in the L1 gas field of the Lishui-Jiaojiang Sag have been commonly interpreted to be an accumulation of pure sapropelic-type thermogenic gas. In this study, chemical components, stable isotopic compositions, and light hydrocarbons were utilized to shed light on the origins of the hydrocarbon fluids in the L1gas pool. The hydrocarbon fluids in the L1 gas pool are proposed to be a mixture of three unique components:mid-maturity oil from the middle Paleocene coastal marine Lin...     

Origin of crude oils from oilfields in the Zagros Fold Belt,southern Iraq: Relation to organic matter input and paleoenvironmental conditions

Crude oil samples from Cretaceous and Tertiary reservoir sections in the Zagros Fold Belt oil fields, southern Iraq were investigated using non-biomarker and biomarker parameters. The results of this study have been used to assess source of organic matter, and the genetic link between oils and their potential source rocks in the basin. The oils are characterized by high sulphur and trace metal (Ni, V) contents and relatively low API gravity values (17.4–22.7° API). This indicates that these oils are heavy and generated from a marine source rock containing Type II-S kerogen. This is supported by their biomarker distributions of normal alkanes, regular isoprenoids, terpanes and steranes and the bulk carbon isotope compositions of their saturated and aromatic hydrocarbons. The oils are characterized by low Pr/Ph ratios (<1), high values of the C₃₅ homohopane index and C₃₁-22R/C₃₀ hopane ratios, relatively high C₂₇ sterane concentrations, and the predominance of C₂₉-norhopane. These biomarkers suggest that the oils were generated predominantly from a marine carbonate source rock, deposited under reducing conditions and containing plankton/algal and microorganisms source input. The presence of gammacerane also suggests water column stratification during source rock deposition.The biomarker characteristics of the oils are consistent with those of the Middle Jurassic Sargelu carbonate as the effective source rock in the basin. Biomarker maturity data indicate that the oils were generated from early maturity source rocks.     

Impact of microorganism degradation on hydrocarbon generation of source rocks: A case study of the Bozhong Sag,Bohai Bay Basin

The discovery of the Bozhong 19-6 gas field, the largest integrated condensate gas field in the eastern China in 2018, opened up a new field for the natural gas exploration deep strata in the Bohai Bay Basin, demonstrating there is a great potential for natural gas exploration in oil-type basins. The ethane isotope of the Bozhong 19-6 condensate gas is heavy, showing the characteristics of partial humic gas. In this paper, aimed at the source rocks of the Bozhong 19-6 gas field in the Bohai Bay Basin, the characteristics of the source rocks in the Bozhong 19-6 structural belt were clarified and the reason are explained from impact of microorganism degradation on hydrocarbon generation of source rocks why the condensate oil and gas had heavy carbon isotope and why it showed partial humic characteristics was explored based on the research of parent materials. The following conclusions were obtained: The paleontology of the Bozhong 19-6 structural belt and its surrounding sub-sags is dominated by higher plants, such as angiosperm and gymnosperm. During the formation of source rocks, under the intensive transformation of microorganism, the original sedimentary organic matter such as higher plants was degraded and transformed by defunctionalization. Especially, the transformation of anaerobic microorganisms on source rocks causes the degradation and defunctionalization of a large number of humic products such as higher plants and the increase of hydrogen content. The degradation and transformation of microorganism don’t transform the terrestrial humic organic matter into newly formed “sapropel” hydrocarbons, the source rocks are mixed partial humic source rocks. As a result, hydrogen content incrased and the quality of source rocks was improved, forming the partial humic source rocks dominated by humic amorphous bodies. The partial humic source rocks are the main source rocks in the Bozhong 19-6 gas field, and it is also the internal reason why the isotope of natural gas is heavy.     

鄂尔多斯盆地塔巴庙地区上古生界源岩热演化特征

鄂尔多斯盆地北部主力气源岩太原组、山西组煤系地层热成熟史的研究对本区天然气充注过程和有利目标区预测具有重要的参考价值。在对研究区烃源岩评价和一维、二维地质建模研究的基础上。利用BasinMod盆地模拟软件对单井以及研究区内二维剖面、平面进行了煤系烃源岩热演化史模拟研究。研究结果表明：（1）该区在中三叠世进入生烃门限,中侏罗世以后,烃源岩持续埋深,早白垩世末期至最大埋深（4000m左右）,绝大多数的天然气都在这一阶段生成,早白垩世末构造抬升以后只有少量天然气生成;（2）研究区上古生界太原组和山西组煤系源岩最大累积生烃强度可达到2200×10^8m^3／km^2,对现今天然气的分布具有较强的控制作用。     

基于无向图Floyd加速模型的海图抽选方法研究

为解决传统海图抽选存在的主观性高和抽选效率低的问题,尝试将图论中的Floyd算法应用到海图抽选问题中,通过在无向图多路径数据结构中对Floyd算法进行加速改进,提出了一种基于无向图Floyd加速模型的海图抽选方法。该方法通过对网络图及算法进行优化,实现了抽选海图航路覆盖范围的最大化和抽选海图数量的最小化,并将时间复杂度降至O(1/2(n)(n-1)~2);通过利用基于等价点数组的最短路径集算法,实现了同等海图数量前提下的不同海图选取方案。最后通过实验验证了上述模型在海图选取中的可行性和优越性。     

Source diagnostic and weathering indicators of oil spills utilizing bicyclic sesquiterpanes

Bicyclic Sesquiterpanes (BSs) are ubiquitous components of crude oils and ancient sediments. BSs in crude oils and diesel oil were identified and characterized, the effects of moderate weathering on BS distributions were discussed, and a methodology using diagnostic indices of BSs was developed for oil correlation and differentiation. The results showed that crude oils and oil products had different abundances and distributions of BSs and, consequently, resulted in different diagnostic ratios. The selected diagnostic ratio indices of BSs, such as BS4/BS5 (ratio of 4,4,8,9,9-pentamethyl-decahydronaphthalene to 8β (H)-drimane), BS6/BS5 (ratio of 4,4,9,9,10-pentamethyl-decahydronaphthalene to 8β (H)-drimane), BS8/BS9 (ratio of the second peak to the third peak of C 16 sequiterpane), and BS8/BS10 (ratio of C 16 sequiterpane to 8β (H)-homodrimane), still maintained better stabilities (%RSD < 5%) after weathering for 30 d. The longer weathering process (150 d) had some effect on such ratios (5% < %RSD < 10%). The facts of the uniqueness, abundance in petroleum, and chemical stability of BSs enable them to be suitable as an effective diagnostic means for identifying spilled oil with moderate weathering, particularly for lighter refined product samples that are difficult to identify by current techniques.     

Geochemical characterization of oils and their correlation with Jurassic source rocks from the Lusitanian Basin (Portugal)

Seeking to identify the oils groups accumulated in the Jurassic of the Lusitanian Basin and the source rock of each group, stable carbon isotope and gas chromatography coupled with mass spectrometry analyses were performed in oils and oil shows from the main discoveries, and on representative organic extracts from the potential source rocks, selected based on previous works and data obtained by total organic carbon and Rock-Eval pyrolysis techniques. The geochemical comparison between the oils, and between the oils and the organic extracts, allowed the identification of three oil groups, whose differences depend on their source rocks: oils generated at the Coimbra Formation (lower-upper Sinemurian) and accumulated in the same formation and in the Água de Madeiros Formation (upper Sinemurian-lower Pliensbachian) in the northern sector of the basin; oils originated from the top of the Cabaços Formation (middle Oxfordian) and accumulated in the Montejunto (middle-upper Oxfordian) and Abadia (lower-upper Kimmeridgian) formations, in the central and southern sectors of the basin; and oil generated and accumulated at the base of the Montejunto Formation in the central sector of the basin. The geochemical correlations between the oils and the organic extracts allowed the identification of the source rocks of the different accumulations of the Jurassic succession, allowing further guidance to the petroleum exploration in the Lusitanian Basin.     

Characteristics and origin of carbon isotopes of n-alkanes in crude oils from the western Pearl River Mouth Basin,South China sea

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.     

Petroleum geochemistry and depositional setting of lacustrine source rocks

Lacustrine sequences are increasingly being recognised as hosts for commercial reserves of petroleum. Petroleum source rocks in lacustrine sequences have organic carbon contents ranging from <1% to >20% and kerogen types range from Type I to Type III. The organic matter can be of land plant, algal or bacterial origin. Most undegraded lacustrine oils are extremely paraffinic and waxy, but a few are asphaltic and rich in sulphur. The crude oils and source rocks contain a wide diversity of biological marker compounds reflecting different source inputs. The diversity of chemistries displayed by lacustrine source rocks and crude oils reflect the wide variety of organic source materials and depositional conditions operative in lakes.Lacustrine sequences preserved in the geological record represent sediments deposited in fluvial lakes on humid flood plains and tectonic lakes in humid, semi-arid and arid environments. Preservation of organic matter in lakes is dependent on the formation of anoxic or micro-oxic bottom waters. This is favoured by stratification of lake waters brought about by temperature and salinity contrasts. Organic material preserved in oligotrophic lakes is largely of land plant origin which has been extensively modified by bacteria under mildly oxidizing conditions and supplemented by the bacterial remains. Source rocks of this type are found in: (1) fluvial - lacustrine settings (e.g. Jurassic of Eromanga Basin, Australia) and (2) the oligotrophic phase of larger tectonic lakes (e.g. early stages of Green River Formation, Uinta Basin USA). As these freshwater lakes become productive, algal remains are contributed to the sediment and anoxic bottom waters can become more firmly established. The green algae Pediastrum and Botryococcus appear to be particularly important although land plant detritus is still significant (e.g. Cretaceous source rocks, Songliao Basin, China). Saline lakes conditions tend to restrict the diversity of the source biota although preservation may be enhanced through anoxia brought about by salinity stratification and inhibition of bacterial decay (e.g. later stages Green River Formation Uinta Basin, USA). Sulphate-rich, and hypersaline lacustrine systems result in the formation of sulphur-rich sources and oils (e.g. Jianghan Basin, China).Because of the diversity of organic matter types, maturation criteria for hydrocarbon generation in lacustrine sequences also vary. However in most cases, higher maturation levels are required for significant hydrocarbon generation. At present, it is uncertain the extent to which algal and bacterial organic matter contribute to the source for the waxy hydrocarbons which are characteristic of lacustrine oils. Organic-rich rocks formed in large freshwater and saline lakes are the most productive type of lacustrine source rock, although sources formed in lakes of flood plains and deltas are also widespread.     

Lacustrine basin unconventional resource plays: Key differences

There has been a revival in hydrocarbon source rock characterization and development associated with growing interest in unconventional resources, where these fine-grained organic-rich rocks act as both source and reservoir. To-date, the exploration focus on shale reservoirs has been largely on marine systems. Lacustrine source rocks for conventional resources are geographically important, dominating regions such as China, Indonesia, and Brazil's resource-base. However, they have been generally untested for unconventional resources.There are a number of key differences in the nature of these hydrocarbon systems that should be considered when assessing whether lacustrine systems may represent future unconventional opportunities in areas where the conventional resource-base is dominated by lacustrine-sourced oil. Among the key differences between these depositional systems is the greater sensitivity to high frequency climatic variability within lacustrine systems. Lacustrine systems are highly sensitive to changes in the balance between precipitation and evaporation, which may lead to rapid changes in lake level, potentially exceeding 600 m. These changes in depositional conditions are geologically rapid and may occur over periods of thousands of years. Such changes can reduce the areal extent of potentially thick source rock intervals to only those portions of a basin where a permanent deep lake was present. Thus the core unconventional target area may be geographically limited compared with their marine counterpart. Although potentially areally limited, a review of many lacustrine source rocks suggests that their thicknesses are often significantly greater than marine source rocks. An examination of the more distal portions of lacustrine systems, where better source rock potential is present reveals that there is generally limited connectivity between source and conventional reservoir. In these settings, such as the Wind River basin (Waltman Shale), the hydrocarbons remain trapped within the shales, potentially leading to over-pressured hydrocarbon charged systems. Such conditions suggest that although areally limited, viable unconventional targets may exist, if suitable reservoir conditions are present. Finally, the character of the oils produced is different in these settings, with lacustrine oils being waxy and displaying different hydrocarbon generation and cracking kinetics. High wax oils display distinct flow characteristics, being more viscous, and may offer different production challenges than their non-waxy marine equivalents. Additionally, differences in their cracking kinetics may indicate that the timing of gas generation for shale gas plays may differ significantly from marine systems.     

Hydrocarbon migration and accumulation of the Suqiao buried-hill zone in Wen'an Slope,Jizhong Subbasin,Bohai Bay Basin,China

The hydrocarbon migration and accumulation of the Suqiao deep buried-hill zone, in the Jizhong Subbasin, the Bohai Bay Basin, eastern China, was investigated from the perspective of paleo-fluid evidence by using fluid inclusions, quantitative fluorescence techniques (QGF), total scanning fluorescence method (TSF) and organic geochemical analysis. Results show that the current condensate oil-gas reservoirs in the study area once were paleo-oil reservoirs. In addition, the reservoirs have experienced at least two stages of hydrocarbon charge from different sources and/or maturities. During the deposition of the Oligocene Dongying Formation (Ed), the deep Ordovician reservoirs were first charged by mature oils sourced from the lacustrine shale source rocks in the fourth member of Shahejie and Kongdian Formations (Es₄+Ek), and then adjusted at the end of Ed period subsequently by virtue of the tectonic movement. Since the deposition of the Neogene Minghuazhen Formation (Nm), the reservoirs were mainly charged by the gas that consisted of moderate to high-maturity condensate and wet gas sourced from the Es₄+Ek lacustrine shale source rocks and mature coal-derived gas sourced from the Carboniferous-Permian (C-P) coal-bearing source rocks. Meanwhile, the early charged oil was subjected to gas flushing and deasphalting by the late intrusion of gas. The widely distributed hydrocarbon inclusions, the higher QGF Index, and FOI (the frequency of oil inclusions) values in both gas-oil and water zone, are indicative of early oil charge. In addition, combined with the homogenization temperatures of the fluid inclusions (<160 °C) and the existence of solid-bitumen bearing inclusions, significant loss of the n-alkanes with low carbon numbers, enrichments of heavier components in crude oils, and the precipitation of asphaltene in the residual pores suggest that gas flushing may have played an important role in the reservoir formation.     

柳珊瑚Leptogorgia rigida中甾体类成分研究

首次对南海柳珊瑚Leptogorgia rigida中甾体类次生代谢产物进行研究。采用硅胶柱柱层析、十八烷基硅烷键合硅胶填料、Sephadex LH-20、高效液相色谱(HPLC)及薄层色谱(TLC)等多种方法进行分离纯化, 通过核磁共振波谱(NMR)、质谱(MS)等现代波谱分析及物理常数对照等方法进行结构鉴定。从南海柳珊瑚Leptogorgia rigida次生代谢产物中分离得到8个甾类化合物, 结构依次为: 3β, 6β, 11-trihydroxy-9, 11-seco-5α-chloest-7-en-9-one (1); 3β, 6α, 11- trihydroxy-9, 11-seco-5α-chloest-7-en-9-one (2); 3β, 6α, 11-trihydroxy-5α-chloest-7, 22(E)-dien-9-one (3); pregnan-4-en-3, 20-dione (4); 5α-pregnan-3, 20-dione (5); 3β-hydroxy-pregnan-5-en-20-dion (6); 3β-hydroxy-5α-pregnan-20-one (7); 和3β, 6α, 11-trihydroxy-9, 11-seco-5α-gorgosterol (8)。所有化合物均首次从Leptogorgia属中得到。     

群体感应抑制活性导向分离腐皮镰刀菌中代谢产物

本实验采用群体感应抑制(quorum sensing inhibitory, QSI)活性导向法,对分离自山东威海近海底泥的真菌 WH7-2开展代谢产物研究。综合菌落形态和转录间隔区(Internal Transcribed Spacer, ITS)全序列分析,菌株 WH7-2 鉴定为腐皮镰刀菌 Fusarium solani。综合运用多种色谱方法,从该真菌大米发酵产物的活性部位中分离得到 11 个化合物。分别鉴定为(2E, 5E)-3, 5, 7-三甲基-2, 5-辛二烯酸(1)、不饱和脂肪酸酯混合物(2 4)、镰红菌素-3-甲醚(5)、脱水镰红菌素(6)、(22E)-5α, 8α-过氧化麦角甾-6, 22-二烯-3β-醇(7)、(22E)-5α, 8α-过氧化麦角甾-6, 9 (11), 22-三烯-3β-醇(8)、3β-羟基-胆甾-5-烯-7-酮(9)、6β-羟基-胆甾-4-烯-3-酮(10)和(22E)-胆甾-5, 22-二烯-3β-醇(11)。其中不饱和脂肪酸酯混合物(2 4)具有 QSI 活性,其他化合物无 QSI 活性。除 5 和 6 外,其他化合物均为首次从腐皮镰刀菌 F. solani 中发现。     

鼠尾藻的化学成分研究

利用正相硅胶柱层析、反相硅胶柱层析、凝胶Sephadex LH-20柱层析、制备薄层层析(PTLC)及重结晶等分离手段,从鼠尾藻(Sargassum thunbergii)中分离得到8个化合物,通过MS、1D和2D NMR等波谱技术鉴定结构为:黑麦草内酯(1);Hexahydro-3a,6-dihydroxy-4,4,7a-trimethyl-2(3H)-benzofuranone(2);5-甲酯基-5-羟基-3-甲氧基-2-环戊烯-1-酮(3);顺-1,6,9,12,15,18-二十一碳六烯酸(4);顺-5,8,11,14-二十碳四烯酸(5);顺-5,8,11,14,17-二十碳五烯酸甲酯(6);植醇(7)和岩藻甾醇(8).这些化合物均为首次从该海藻中分离获得.     

Thermal maturity history and petroleum generation modelling for the Lower Cretaceous Abu Gabra Formation in the Fula Sub-basin,Muglad Basin,Sudan

Two petroleum source rock intervals of the Lower Cretaceous Abu Gabra Formation at six locations within the Fula Sub-basin, Muglad Basin, Sudan, were selected for comprehensive modelling of burial history, petroleum maturation and expulsion of the generated hydrocarbons throughout the Fula Sub-basin. Locations (of wells) selected include three in the deepest parts of the area (Keyi oilfield); and three at relatively shallow locations (Moga oilfield). The chosen wells were drilled to depths that penetrated a significant part of the geological section of interest, where samples were available for geochemical and source rock analysis. Vitrinite reflectances (Ro %) were measured to aid in calibrating the developed maturation models.The Abu Gabra Formation of the Muglad Basin is stratigraphically subdivided into three units (Abu Gabra-lower, Abu Gabra-middle and Abu Gabra-upper, from the oldest to youngest). The lower and upper Abu Gabra are believed to be the major source rocks in the province and generally contain more than 2.0 wt% TOC; thus indicating a very good to excellent hydrocarbon generative potential. They mainly contain Type I kerogen. Vitrinite reflectance values range from 0.59 to 0.76% Ro, indicating the oil window has just been reached. In general, the thermal maturity of the Abu Gabra source rocks is highest in the Abu Gabra-lower (deep western part) of the Keyi area and decreases to the east toward the Moga oilfied at the Fula Sub-basin.Maturity and hydrocarbon generation modelling indicates that, in the Abu Gabra-Lower, early oil generation began from the Middle- Late Cretaceous to late Paleocene time (82.0–58Ma). Main oil generation started about 58 Ma ago and continues until the present day. In the Abu Gabra-upper, oil generation began from the end of the Cretaceous to early Eocene time (66.0–52Ma). Only in one location (Keyi-N1 well) did the Abu Gabra-upper reach the main oil stage. Oil expulsion has occurred only from the Abu Gabra-lower unit at Keyi-N1 during the early Miocene (>50% transformation ratio TR) continuing to present-day (20.0–0.0 Ma). Neither unit has generated gas. Oil generation and expulsion from the Abu Gabra source rocks occurred after the deposition of seal rocks of the Aradeiba Formation.     

Geochemical assessment of the Colombian oils based on bulk petroleum properties and biomarker parameters

This geochemical survey defines the typical features of representative oils from the major Colombian basins, and proposes a classification scheme useful for hydrocarbon exploration. This work is based on properties of whole oils such as API gravity, sulfur, vanadium and nickel concentrations, and gas chromatography fingerprints. The framework is completed by inclusion of biomarker parameters derived from GCMS and GCMSMS analysis.Oils from the basins of the Middle Magdalena Valley, Upper Magdalena Valley, Sinú - San Jacinto, Putumayo-Caguan, Lower Magdalena Valley and Catatumbo were assessed. Conclusions were drawn regarding possible sources of origin, oil families, degree of thermal evolution, biodegradation, mixing and refreshing, and inferences regarding exploration implications.The oils from the Middle Magdalena Valley and Upper Magdalena Valley (intermontane basins) and Putumayo (foreland basin), except those from the Caguan area, are oils with similar characteristics. In these three cases the oils are probably coming from source rocks intervals deposited in a marine Cretaceous platform, with variable carbonate/siliciclastic features. In these basins there are no oils derived from Tertiary source rocks.In Sinú-San Jacinto and Lower Magdalena Valley basins the main proportions of oils comes from very proximal environments, probably deltaic type, of Tertiary age with a minor proportion of oils coming from Cretaceous source rocks of marine anoxic environment (the only marine Cretaceous oils discovered so far in the Sinú-San Jacinto and Lower Magdalena Valley basins).The oils from Eastern Foothills of the Eastern Cordillera, look to be derived mainly from proximal Cretaceous source rocks with some mixing of oils derived from Tertiary strata. In the Catatumbo basin there are oils derived mainly from Cretaceous source rocks and some from Tertiary source rocks.Regarding the processes after entrapment, in all of the basins, the biodegradation effects were observed in varying degrees. These processes are dominant toward more quiescent regions, beyond the areas with more tectonic activity, far from the foothills of the Eastern Cordillera. Instead, close to the Eastern Cordillera are more common the paleobiodegradation processes due to reburial of younger molasses. The effects of mixing or refreshing are remarkable close to the Eastern Cordillera foothills in Llanos, Middle Magdalena Valley, and Upper Magdalena Valley basins.