Occurrence of Highly Mature Organic Matter in Marine Black Shale Petroleum Source Rocks of Basal Cambrian from Northern Tarim Basin, China

More and more evidence indicates that organic matter (OM) in immature organicrich sediments and sedimentary rocks is chemically adsorbed onto the outer surfaces of minerals and into interlayer (inner) surfaces of smectitic clay minerals in the form of amorphous molecular-scale carbon. But there have been few reports about the occurrence of highly mature OM in marine black shales ( petroleum source rocks ). The occurrence of highly mature OM in the black shales of basal Cambrian from northern Tarim Basin is studied in this paper. Based on the comprehensive analyses of total organic carbon contents (TOC) , maximum thermolysis tempera tures ( Tmax ) of OM, mineral surface areas (MSA) ,and scanning electronic microscopic (SEM) and transmission electronic microscopic (TEM) observations of the black shales, it is concluded that the highly mature OM in the marine black shales of the basal Cambrian from northern Tarim Basin occurs in particulates ranging in size from 1 to 5 μm in diameter. Through the contrast of the occurrence of the highly mature OM in the black shales with that of the immature ones in modern marine continental margin sediments, some scientific problems are proposed, which are worth to study further in detail.     

Lower palaeozoic and precambrian petroleum source rocks and the coalification path of alginite

Organic-rich samples derived from a Middle Cambrian Formation in the Georgina Basin, and from the Middle Proterozoic of the McArthur Basin in northern and central Australia, yielded alginite ranging from immature oil shale material to overmature residue. A maturation scale has been developed based on the thermal evolution of alginite as determined from reflectance and fluorescence. The coalification path of alginite is marked by jumps in contrast to the linear path of wood-derived vitrinite. Six zones have been recognised, ranging from undermature (zone I), through the mature (zones II/III), followed by a stable stage of no change (zone IV) to the overmature (zones V and VI). The onset of oil generation in alginite as evident from the present study is at 0.3% R_{o Alg.} and is expressed in a change of fluorescence from yellow to brown, and a coalification jump from 0.3 to 0.6% R_o of Alg. In many boreholes zone III can be distinguished between 0.6 and 0.8% R_o of Alg. where subsequent oil generation occurs. Zones II and III represent the oil window.A zone of little or no change designated zone IV, at of alginite follows zones II/III. A marked coalification jump characterises zone V, where a pronounced change in reflectance occurs to >1.0% R_{o Alg.}, signifying peak gas generation. The border of oil preservation lies at the transition of zone V and VI, at 1.6% R_{o Alg.} In zone VI gas generation only occurs.Comparison of reflectance results with experimental and geochemical pyrolysis data supports high activation energies for hydrocarbon generation from alginite, and therefore a later onset of oil generation than other liptinite macerals (i.e. cutinite, exinite, resinite) as well as a narrow oil window.Transmission electron microscopy (TEM) confirms that alginite does not go through a distinct intermediate stage but that the percentage of unreacted organic matter decreases as maturation proceeds. A clear distinction can be made in TEM between immature alginite, alginite after oil generation, and alginite residue following gas generation. Alginite beyond 1.6% R_o acquires very high densities and the appearance of inertinite in TEM.Bitumens/pyrobitumens make a pronounced contribution to the organic matter throughout the basins and have been shown to effect pyrolysis results by suppressing T_max. The bitumens/pyrobitumens have been divided into four groups, based on their reflectance and morphology, which in turn appears to be an expression of their genetic history. Their significance is in aiding the understanding of the basins' thermal history, and the timing of oil and gas generation.     

Proteins as a possible source material of low molecular weight petroleum hydrocarbons

Low temperature cracking experiments of a representative protein, at temperatures not far above the observed temperature range of 130–160°C of mature California oil source rocks, indicate the formation of all gaseous and of some gasoline range hydrocarbons of petroleum. Based on protein derivatives only it is estimated that a maximum of at least 3–8% by weight of the total organic matter of oil source sediments may be converted into such hydrocarbons. This is in addition to hydrocarbons originating from lipids.     

Geochemical studies related to the occurrence of oil and gas in the dampier sub-basin,Western Australia

An organic geochemical study has been made of sediments from five petroleum exploration wells and liquid hydrocarbons from seven oil and gas condensate discoveries in the offshore Dampier Sub-basin. Hydrocarbon generation has occurred between 3000 and 4250 m and the probable source rocks have been identified. Oils and condensates in the basin are of two types; a paraffinic-naphthenic type derived from Jurassic source beds and a naphthenic type coming from Cretaceous source sediments. Mixing of the two oil types appears to have occurred in the Egret reservoir.     

Thermal maturity of the lower carboniferous Horton group, Nova Scotia

The Thermal Alteration Index (TAI) obtained from spore colouration is a useful maturity indicator that may be obtained from palynological preparations. Thermal maturity is an important parameter in determining the hydrocarbon potential of the Lower Carboniferous lacustrine and fluviatile sediments of the Horton Group, and coeval rocks, of Nova Scotia. Samples studied from fifty-two separate localities indicate a wide range in thermal maturity from low (TAI 2 to 3) to high (TAI 4 to 5?). Variation in depth of burial was probably the main factor responsible for the regional differences in thermal maturity. The thickness of Horton sedimentation varied considerably in a series of half grabens, as did the overburden of post-Tournaisian Lower Carboniferous, Upper Carboniferous, Permian and possibly Triassic rocks.The organic matter in most samples is composed of exinous (Type II) and woody and coaly material (Types III and IV). Locally in a few localities amorphous algal material (Type I) consisting of Botryococcus sp. is common. The composition of the organic matter and the thermal maturity data suggest that in most of the study area rocks of the Horton Group are in the dry gas generation zone, although in some areas oil generation may have taken place; in a few localities where the thermal maturity is high the organic matter has been altered beyond the dry gas preservation limit.     

Pregnanes as molecular indicators for depositional environments of sediments and petroleum source rocks

Steroids with unconventional side chains have increasingly been applied as diagnostic markers for geological source and age assessments. However, one of the most distinctive characteristics, the abnormal abundance of pregnane and homopregnane in ancient sediments and petroleum, remains unresolved. Higher pregnane and homopregnane, as well as C₂₃–C₂₆ 20-n-alkylpregnanes, relative to the regular steranes were observed in samples collected from different petroleum basins in China. These included Precambrian marine carbonate-derived petroleum (NW Sichuan Basin), Lower Paleozoic marine marl derived crude oils (Tarim Basin), and Eocene hypersaline lacustrine carbonate source rocks and associated petroleum (Bohai Bay Basin). However, all of the samples have many common biomarker characteristics, such as pristane/phytane ratios < 1, low amounts of diasteranes and high C₂₉/C₃₀ hopane (∼0.6–1), C₃₅/C₃₄ hopane (mostly ⩾ 1) and dibenzothiophene/phenanthrene (DBT/PHEN, mostly 0.5–1) ratios revealing a contribution from anoxic carbonate/marl source rocks deposited in restricted, clastic-starved settings. We suggest that 5α,l4β,l7β-pregnane and homopregnane, as well as their higher C₂₃–C₂₆ homologues, are geological products derived from steroids bound to the kerogen by a sulfurized side chain. Carbon or carbonate minerals are considered to be natural catalysts for this cracking reaction via preferential cleavage of the bond between C-20 and C-22. Similar distributions occur in the short chain analogues of 4-methylsterane, triaromatic steroid and methyltriaromatic steroid hydrocarbons, providing circumstantial evidence for this proposal. The ratio of pregnane and homopregnane to the total regular steranes and the ratio of C₂₇ diasteranes to cholestanes can be sensitive indicators of sedimentary environments and facies. In general, high diasteranes and low pregnanes (with homologues) indicate an oxic water column or significant input of terrigenous organic matter in clay rich source rocks and some organic lean carbonate rocks. Low diasteranes with high pregnanes implies restricted, sulfur rich conditions, typical of anoxic carbonate source rocks. Furthermore, the two ratios may be useful to assess the variation of mineralogy and openness of source rock depositional settings.     

济阳坳陷下古生界碳酸盐岩烃源岩评价

应用生油生气量计算模型、岩石吸附油气量计算模型、油溶水溶气量计算模型、扩散气量计算模型计算了济阳坳陷(车镇、沾化和东营)下古生界碳酸盐岩的生烃量和残留耗散烃量,进而根据物质平衡原理计算出排烃量,根据排烃量的大小对目标层进行了烃源岩评价。结果表明,车镇、沾化和东营凹陷下古生界碳酸盐岩均为非油源岩、非气源岩。结合车25井、孤古2井和草古101井有机质成烃剖面,认为造成研究区烃源条件差的原因是有机质丰度过低。     

生烃动力学、同位素动力学方法在烃源岩研究中的应用

生烃动力学、同位素动力学常用于烃源岩评价、油气源对比研究中.生烃动力学参数结合盆地热史,可恢复烃源岩在任一时代的生烃史,对构造复杂盆地的二次生烃研究具有独特的优势.利用生烃动力学方法可以实现有机质总量的恢复,在此基础上对高-过成熟样品原始有机质丰度是否有必要恢复进行了讨论;而基于生烃动力学的油气源对比综合考虑热史、成藏期次、成藏过程等各种地质参数对烃源岩生烃的影响,是一种动态的研究方法.     

生烃动力学、同位素动力学方法在烃源岩研究中的应用

生烃动力学、同位素动力学常用于烃源岩评价、油气源对比研究中。生烃动力学参数结合盆地热史,可恢复烃源岩在任一时代的生烃史,对构造复杂盆地的二次生烃研究具有独特的优势。利用生烃动力学方法可以实现有机质总量的恢复,在此基础上对高—过成熟样品原始有机质丰度是否有必要恢复进行了讨论;而基于生烃动力学的油气源对比综合考虑热史、成藏期次、成藏过程等各种地质参数对烃源岩生烃的影响,是一种动态的研究方法。     

湖相碳酸盐岩烃源岩有机显微组分分类及其岩石学特征——以酒西盆地为例

酒西盆地主力烃源岩为下白垩统下沟组和赤金堡组暗色半深湖相-深湖相的白云质泥岩和泥质白云岩,是典型的湖相碳酸盐岩烃源岩。通过对酒西盆地下白垩统二百多块湖相碳酸盐岩烃源岩详细的有机岩石学研究,解剖了湖相碳酸盐岩烃源岩中有机质的赋存形式,揭示了藻纹层为有机质纹层的主要发育形式,其与富泥晶白云石纹层和富粘土纹层构成湖相碳酸盐岩烃源岩特有的"三元式纹层"沉积结构,系统总结了各显微组分的光性、成因、生烃性及分布规律,提出了以全岩和干酪根为基础的湖相碳酸盐岩有机显微组分分类方案,首次鉴定出对酒西盆地油气有贡献的主要生烃组分为腐泥无定形体、腐殖无定形体以及浮游藻类体、孢粉体、壳屑体五种有机显微组分。     

塔里木盆地寒武系海相烃源岩有机成熟度及演化史

原生有机组分(镜状体和动物有机组分)反射率是评价塔里木盆地寒武系海相烃源岩有机成熟度的有效方法。从分析的探井和露头区110多个寒武系样品有机组分反射率数据来看，塔里木盆地寒武系烃源岩均处于高过成熟阶段，尚未发现目前仍处于生油窗阶段的寒武系中等成熟的烃源岩。利用BasinMod-1D软件计算了250口探井，26条地震测线中约340个人工井点有机成熟度随时间的变化，据此编制不同地质时期塔里木盆地台盆区寒武系有机成熟度平面变化图。目前满加尔凹陷中下寒武统烃源岩镜质体反射率在3％以上，中下寒武统烃源岩成熟度相对较低区分布在塔中隆起主垒带、塔北隆起的凸起区(英买力凸起)和巴楚断隆—部分地区，其等效镜质体反射率R^ 在1．6％～2．0％之间。     

Petroleum system analysis of the Khatatba Formation in the Shoushan Basin,north Western Desert,Egypt

The Middle Jurassic Khatatba Formation is an attractive petroleum exploration target in the Shoushan Basin, north Western Desert, Egypt. However, the Khatatba petroleum system with its essential elements and processes has not been assigned yet. This study throws the lights on the complete Khatatba petroleum system in the Shoushan Basin which has been evaluated and collectively named the Khatatba-Khatatba (!) petroleum system. To evaluate the remaining hydrocarbon potential of the Khatatba system, its essential elements were studied, in order to determine the timing of hydrocarbon generation, migration and accumulation. Systematic analysis of the petroleum system of the Khatatba Formation has identified that coaly shales and organic-rich shales are the most important source rocks. These sediments are characterised by high total organic matter content and have good to excellent hydrocarbon generative potential. Kerogen is predominantly types II–III with type III kerogen. The Khatatba source rocks are mature and, at the present time, are within the peak of the oil window with vitrinite reflectance values in the range of 0.81 to 1.08 % Ro. The remaining hydrocarbon potential is anticipated to exist mainly in stratigraphic traps in the Khatatba sandstones which are characterised by fine to coarse grain size, moderate to well sorted. It has good quality reservoir with relatively high porosity and permeability values ranging from 1 to 17 % and 0.05–1,000 mD, respectively. Modelling results indicated that hydrocarbon generation from the Khatatba source rocks began in the Late Cretaceous time and peak of hydrocarbon generation occurred during the end Tertiary time (Neogene). Hydrocarbon primarily migrated from the source rock via fractured pathways created by abnormally high pore pressures resulting from hydrocarbon generation. Hydrocarbon secondarily migrated from active Khatatba source rocks to traps side via vertical migration pathways through faults resulting from Tertiary tectonics during period from end Oligocene to Middle Miocene times.     

塔里木盆地下寒武统底部高熟海相烃源岩中有机质的赋存状态

近年来的研究证明,中新生代未熟—低熟海相富有机质泥质烃源岩中有机质是通过溶解在水中的分子规模的碳有机质以化学吸附的形式被吸附到矿物表面上和蒙脱石结构层内。然而,对于高熟海相泥质烃源岩中有机质的赋存状态却少有报道。通过对塔里木盆地下寒统底部高熟海相泥质烃源岩的有机碳含量、矿物表面积、扫描电镜和透射电镜的综合分析,得到了其有机质以细小的颗粒状保存于沉积物颗粒之间的结论。同时,通过高熟海相烃源岩与现代未熟海相烃源岩有机质赋存状态的对比,提出了值得进一步研究的有关科学问题。     

Hydrocarbon generation and expulsion characteristics of Lower Permian P1f source rocks in the Fengcheng area,northwest margin,Junggar Basin,NW China: implications for tight oil accumulation potential assessment

Combined with the actual geological settings, tight oil is the oil that occurs in shale or tight reservoirs, which has permeability less than 1 mD and is interbedded with or close to shale, including tight dolomitic oil and shale oil. The Fengcheng area (FA), at the northwest margin of the Junggar Basin, northwest China, has made significant progress in the tight oil exploration of the Fengcheng (P₁f) Formation recently, which indicates that the tight oil resources have good exploration prospects. Whereas the lack of recognition of hydrocarbon generation and expulsion characteristics of Permian P₁f source rocks results in the misunderstanding of tight oil resource potential. Based on the comprehensive analysis of geological and geochemical characteristics of wells, seismic inversion, sedimentary facies, tectonic burial depth, etc., the characteristics of P₁f source rocks were investigated, and the horizontal distributions of the following aspects were predicted: the thickness of source rocks, abundance and type of organic matter. And on this basis, an improved hydrocarbon generation potential methodology together with basin simulation techniques was applied to unravel the petroleum generation and expulsion characteristics of P₁f source rocks in FA. Results show that the P₁f source rocks distribute widely (up to 2039 km²), are thick (up to 260 m), have high total organic content (TOC, ranging from 0.15 to 4 wt%), are dominated by type II kerogen and have entered into low mature–mature stage. The modeling results indicate that the source rocks reached hydrocarbon generation threshold and hydrocarbon expulsion threshold at 0.5% Ro and 0.85% Ro and the comprehensive hydrocarbon expulsion efficiency was about 46%. The amount of generation and expulsion from the P₁f source rocks was 31.85 × 10⁸ and 15.31 × 10⁸ t, respectively, with a residual amount of 16.54 × 10⁸ t within the source rocks. Volumetrically, the geological resource of shale oil is up to 15.65 × 10⁸ t. Small differences between the amounts calculated by the volumetric method compared with that by hydrocarbon generation potential methodology may be due to other oil accumulations present within interbedded sands associated with the oil shales. Copyright © 2015 John Wiley & Sons, Ltd.     

Evaluation of the petroleum composition and quality with increasing thermal maturity as simulated by hydrous pyrolysis: A case study using a Brazilian source rock with Type I kerogen

Hydrous pyrolysis (HP) experiments were used to investigate the petroleum composition and quality of petroleum generated from a Brazilian lacustrine source rock containing Type I kerogen with increasing thermal maturity. The tested sample was of Aptian age from the Araripe Basin (NE-Brazil). The temperatures (280–360 °C) and times (12–132 h) employed in the experiments simulated petroleum generation and expulsion (i.e., oil window) prior to secondary gas generation from the cracking of oil. Results show that similar to other oil prone source rocks, kerogen initially decomposes in part to a polar rich bitumen, which decomposes in part to hydrocarbon rich oil. These two overall reactions overlap with one another and have been recognized in oil shale retorting and natural petroleum generation. During bitumen decomposition to oil, some of the bitumen is converted to pyrobitumen, which results in an increase in the apparent kerogen (i.e., insoluble carbon) content with increasing maturation.The petroleum composition and its quality (i.e., API gravity, gas/oil ratio, C₁₅₊ fractions, alkane distribution, and sulfur content) are affected by thermal maturation within the oil window. API gravity, C₁₅₊ fractions and gas/oil ratios generated by HP are similar to those of natural petroleum considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. API gravity of the HP expelled oils shows a complex relationship with increasing thermal maturation that is most influenced by the expulsion of asphaltenes. C₁₅₊ fractions (i.e., saturates, aromatics, resins and asphaltenes) show that expelled oils and bitumen are compositionally separate organic phases with no overlap in composition. Gas/oil ratios (GOR) initially decrease from 508–131 m³/m³ during bitumen generation and remain essentially constant (81–84 m³/m³) to the end of oil generation. This constancy in GOR is different from the continuous increase through the oil window observed in anhydrous pyrolysis experiments. Alkane distributions of the HP expelled oils are similar to those of natural crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. Isoprenoid and n-alkane ratios (i.e., pristane/n-C₁₇ and phytane/n-C₁₈) decrease with increasing thermal maturity as observed in natural crude oils. Pristane/phytane ratios remain constant with increasing thermal maturity through the oil window, with ratios being slightly higher in the expelled oils relative to those in the bitumen. Generated hydrocarbon gases are similar to natural gases associated with crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous, with the exception of elevated ethane contents. The general overall agreement in composition of natural and hydrous pyrolysis petroleum of lacustrine source rocks observed in this study supports the utility of HP to better characterize petroleum systems and the effects of maturation and expulsion on petroleum composition and quality.     

Association of oil source algae in some Tertiary basins,northern Thailand

A coal petrographic study of sediments, including coals, oil shale, and oil source rocks, in the fossil fuel deposits of northern Thailand revealed changes in alginite associations. In the Lower part of these Tertiary deposits, especially in the Fang oilfield, alginite A (a Botryococcus sp.) was the only type of alga found. Later, the association of Botryococcus braunii, Pila algae, thick-walled alginite B, and temperate palynomorphs were recognized in many coalfields, as well as in the middle part of the deposits in the Fang Basin. Their ages were Late Oligocene (?) to Early Miocene. In the upper part of the fossil fuel deposits, alginite B is dominant in many basins, together with Botryococcus-related taxa such as Pila algae, Reinschia and fresh-water-dwelling ferns. In the Mae Sod Basins Reinschia was found to be dominant in the northern part, whereas lamaginite dominated in the south, showing different environmental conditions in different parts of the basin during deposition. These different associations indicate changes in depositional environments in northern Thailand, resulting from climatic and/or sea level changes during Tertiary time.     

The deep subsurface temperature controlled origin of the gaseous and gasoline-range hydrocarbons of petroleum

In recent surface sediments there is no indication of any of the saturated C₃–C₇ gasolinerange hydrocarbons which are so common in petroleum. Appreciable gasoline-range hydrocarbon generation (85–180°C) of 80 ppm by weight of dry rock, or more, occurs only with increased temperature due to deeper burial, below about 8000 ft in the Los Angeles basin and below 12,500 ft in the Ventura basin. Because of the lower temperature gradient in the Ventura basin, the zone of substantial gasoline generation is considerably deeper there than in the Los Angeles basin. However, the subsurface temperature range over which substantial gasoline generation occurs is practically the same in the two basins. This demonstrates that the subsurface temperature, not depth, is the controlling factor in gasoline generation in source rocks. For appreciable gasoline generation somewhat higher subsurface temperatures are required than for equivalent generation of heavy hydrocarbons boiling above 325°C. Appreciable generation of the C₁–C₄ wet gas components of 75 ppm by weight of dry rock, or more, takes place quite deep also; in the Los Angeles basin it occurs below 10,000 ft.The composition of the gasoline-range hydrocarbons generated changes gradually with increasing depth, temperature and age of the shales. In deep strata the gasolines from shale cannot be distinguished from the gasolines of waxy crude oils in the same basin. The gasoline-range hydrocarbons mature with depth, temperature and age of the sediments, very much like the heavy hydrocarbons investigated earlier.Based on the similarity of analyses of heavy as well as of gasoline-range hydrocarbons from crude oils and from certain deep shales, a secure identification has been made of mature oil source beds in the Los Angeles and San Joaquin Valley oil basins of California. The combined results of these studies provide strong evidence for the origin of petroleum from the organic matter of sediments.     

Supercritical Carbon Dioxide Extraction of Organic Matter from Petroleum Source Rocks and Its Implications

Organic matter was experimentally extracted by supercritical fluids(CO2 1% isopropanol)from petroleum source rocks of different thermo-maturities at different buried depths in the same stratigraphic unit in the Dongying Basin.The results show that supercritical fluid extraction(SFE)is more effective than Soxhlet extraction(SE),with higher amounts and greater varieties of hydrocarbons and soluble organic matter becoming extractive.The supercritical CO2 extraction is therefore considered more valuable in evaluation of petroleum source rocks and oil resources,particularly those of immature types.     

Hydrocarbon source potential of the Jurassic sediments of Salam-3X borehole,Khalda Concession,Northern Western Desert,Egypt

A total of 51 samples, collected from the Jurassic sediments (Ras Qattara, Yakout, Khatatba, Masajid, and Alam El Bueib (member 6) formations) of Salam-3X well, were subjected to organic geochemical analysis. Of the samples, nine have been subjected to palynofacies investigation. Based on the sedimentary organic matter, these sediments show only one palynofacies type, indicating the presence of gas- and oil-prone source rocks and reflecting deposition under marginal dysoxic–anoxic to shelf-to-basin transition conditions. The total organic content of the samples analyzed is characterized by a wide range of content, including fair, good, very good, and excellent. The organic matter quality of these samples is concentrated around types III (gas prone), III–II (gas and oil prone), and II (oil prone), reflecting gas- and oil-prone sediments, with a tendency to generate gas rather than oil; the result matches with the palynological analysis data. The temperature of maximum pyrolytic hydrocarbon generation of analyzed samples are ranging between 440 and 457 °C, reflecting thermally mature organic matter.     

Neoproterozoic and Lower Cambrian rock complexes in central areas of the Siberian Craton: Their structure and petroleum prospects

The paper summarizes data on the geology, lithology, and geochemistry of petroliferous Riphean, Vendian, and Lower Cambrian rocks in the central parts of the Siberian Craton. The petrological-geological properties of these sediments have been assessed based on results of paleogeographic analysis of these rocks, discrimination of oil reservoirs and oil-source successions, determination of secondary alterations of the rocks, and sources of oil generation and regional migration of hydrocarbons into various traps in zones of possible oiland-gas accumulation.