Generation and expulsion of oils from Permian coals of the Sydney Basin,Australia

Organic geochemical and petrological assessment of coals/coaly shales and fine grained sediments, coupled with organic geochemical analyses of oil samples, all from Permo–Triassic sections of the Southern Sydney Basin (Australia), have enabled identification of the source for the widely distributed oil shows and oil seeps in this region. The Permian coals have higher hydrogen indices, higher liptinite contents, and much higher total organic matter extract yields than the fine grained sediments. A variety of source specific parameters obtained from n-alkanes, regular isoprenoids, terpanes, steranes and diasteranes indicate that the oil shows and seeps were generated and expelled predominantly from higher plant derived organic matter deposited in oxic environments. The source and maturity related biomarkers and aromatic hydrocarbon distributions of the oils are similar to those of the coals. The oil-coal relationship also is demonstrated by similarities in the carbon isotopic composition of the total oils, coal extracts, and their individual n-alkanes. Extracts from the Permo–Triassic fine grained sediments, on the other hand, have organic geochemical signatures indicative of mixed terrestrial and prokaryotic organic matter deposited in suboxic environments, which are significantly different from both the oils and coal extracts. The molecular signatures indicating the presence of prokaryotic organic matter in some of the coal extracts and oils may be due to thin sections of possibly calcareous lithologies interbedded within the coal measures. The genetic relationship between the oils and coals provides new evidence for the generation and expulsion of oils from the Permian coals and raises the possibility for commercial oil accumulations in the Permian and Early Triassic sandstones, potentially in the deeper offshore part of the Sydney Basin.     

煤和煤系泥岩生油能力再评价

煤和分散有机质（煤系泥岩或页岩）对煤成油田的贡献大小一直没有获得统一认识,这导致煤是否具有生排油能力直到现在仍然争论不休。选择了两个典型侏罗系煤和一个煤系泥岩样品,分别进行了限定体系热解生烃模拟,结果表明热解特征较差的泥岩（H／C 0．77,IH 146mg／g）却比中等富氢煤（H／C 0．82,IH 260mg／g）的生油量高出2．7倍,是一般煤（H／C 0．75,IH 199mg／g）生油潜力的6倍。这暗示着在煤成油评价中,不能简单把煤和煤系分散有机质对等进行评价,不然会低估煤系相对分散有机质的贡献而过高估计了煤的作用。热解模拟结果与吐哈盆地台北凹陷煤系岩石中有机质含量对比结果表明,该凹陷煤成油更可能来自于煤系泥岩而不是煤本身。此外,通过分析发现煤中液态烃稳定性较差,一般在低熟阶段就开始裂解生气,因此,被国内外学者普遍采纳的,IH（或S1）随成熟度变化的趋势不能作为判断煤排油门限的有效参考。     

焉耆盆地侏罗纪煤系源岩显微组分组合与生油潜力

焉耆盆地为我国西部含煤、含油气盆地, 侏罗系含煤地层是最重要的潜在源岩.对侏罗纪煤系中的暗色泥岩、碳质泥岩和煤层分别进行了有机岩石学、Rock-Eval热解分析和核磁共振分析.泥岩、碳质泥岩和煤层具有不同的有机岩石学和有机地球化学特征, 其中煤层具有3种有机显微组分组合类型, 不同显微组分组合类型的煤层具有不同的生油、生气潜力或倾油、倾气性.基质镜质体、角质体、孢子体等显微组分是煤中的主要生烃组分.侏罗系泥岩、碳质泥岩和煤层具有不同的生物标志物分布特征, 生物标志物组合分析表明焉耆盆地已发现原油是泥岩、碳质泥岩和煤层生成原油的混合产物.含煤地层的地球化学生烃潜力分析和已发现原油的油源对比均表明, 含煤地层不仅是重要的气源岩, 而且可成为有效的油源岩.      

Compound-specific stable carbon isotope analysis as a tool for correlating coal-sourced oils and interbedded shale-sourced oils in coal measures: an example from Turpan basin, north-western China

Molecular geochemical methods have shown that it is often difficult to differentiate between coal- and interbedded shale-sourced oils, even though coals and interbedded shales may exhibit considerable organic influx variation (e.g. land plant vs algal organic matter) due to the changes of depositional setting. However, compound-specific stable carbon isotopic compositions are sensitive to the source input variations. Typically, specific molecules are more depleted in ¹³C with increasing content of aqueous biota. This hypothesis is examined and exemplified by comparing the stable carbon isotopic ratios of n-alkanes from source rock extracts and related oils of the Turpan basin, north-western China. Stable carbon isotopic values of n-alkanes extracted from coals and interbedded shales show that δ¹³C values of n-alkanes with less than 20 carbon atoms vary only slightly. However, there are dramatic changes in the isotopic compositions of higher molecular weight n-alkanes. Furthermore, n-alkanes from coal extracts are enriched in ¹³C relative to that of interbedded shales with excursions up to 2–3‰. This comparison enables the differentiation of coal- and interbedded shale-sourced oils, and provides information useful in assessing the hydrocarbon system of a basin.     

渤海湾盆地南堡凹陷原油成因类型及其分布规律

南堡凹陷近年油气勘探取得了重大突破,为揭示该区滩海与陆地油气成因及分布规律,对67个原油和油砂样品进行了详细的地球化学研究。南堡凹陷原油具有低硫、中高蜡含量特征,陆相成因特点显著。共分为4种类型原油:(1)陆地沙三段深部层系原油,具有高4-甲基甾烷丰度、低奥利烷丰度与低甲基菲指数值和轻微偏高成熟度特征;(2)陆地Es1—Ed原油与Ng和Nm原油,其特征与第一类原油相反;上第三系原油普遍遭遇生物降解;(3)滩海东营组原油,以较高伽马蜡烷/C30藿烷和高甾烷/藿烷值区别于陆地原油;(4)滩海奥陶系潜山原油,具有低丰度甾萜类生物标志物、相对高丰度孕甾烷、三环萜烷与重排甾烷系列等特征,显示较高成熟度。上述4种成因类型原油指示南堡凹陷陆地、滩海均存在多层导有利烃源岩;同层位中滩海Es1-Ed存在较陆地更为优越的有利烃源岩,南堡滩海地区具有广泛的油气勘探前景。     

Generation and hydrocarbon entrapment within Gondwanan sediments of the Mandapeta area, Krishna-Godavari Basin, India

The discovery of hydrocarbons (mainly gas) in commercial quantities from Gondwanan sediments in the Mandapeta field of Krishna-Godavari Basin, India, provided impetus for intensified exploration in Mandapeta and the adjoining Kommugudem, Draksharama and Endamuru fields. Both oil and gas have been found in the reservoirs of Mandapeta (Triassic) and Golapalli (Early Cretaceous) formations. Mature, localised, basal shales (1.0–1.1% Ro) in the Mandapeta formation have sourced the oils from the Mandapeta Sandstone reservoir (Triassic). The oils being produced from Golapalli Sandstone reservoir (Early Cretaceous) are relatively less mature and have been sourced by the underlying shales in the Mandapeta Formation at a maturity level of 0.80–0.85% Ro. The source and maturity data preclude liquid hydrocarbon sourcing from the Kommugudem (Permian) sequence. Permian coals and shales of the Kommugudem Formation are the major source rocks for gaseous hydrocarbons in this area. The hydrocarbon generation started in Early Cretaceous in the Kommugudem Formation, but the intermittent tectonic activity (with associated structural developments) has resulted in reorientation and redistribution of the then existing trap configurations. The present day maturity level of the Permian sediments in the Mandapeta field is 1.2% Ro or greater, capable of generating gas dominantly. The Raghavapuram shale in the Mandapeta area is adequately mature and has good hydrocarbon potential for oil generation. The probability of finding hydrocarbon reserves in the sands of Raghavapuram shales and other suitable traps is high. Modern seismic information together with geologic models can give new exploration leads.     

崖城地区渐新统不同沉积相带烃源岩生物标志物组合特征及其烃源意义

基于40余个不同岩性烃源岩及原油饱和烃组分的GC/MS和GC/MS/MS分析资料,揭示了琼东南盆地崖城地区渐新统不同沉积相带烃源岩的生物标志物组合特征,并与崖城油气田原油进行油源精细对比,提出了新的认识。研究结果表明,海岸平原沼泽相煤及碳质泥岩呈姥鲛烷优势(Pr/Ph>5.0),三环萜烷以低碳数化合物为主(C₁₉/C₂₃>3.0),甾烷丰度低(藿烷/甾烷>5.0), C₂₉甾烷优势显著(>60%),指示高等植物为主要的有机源,且沉积于氧化环境。浅海相泥岩中Pr/Ph值大多在1.0~2.5,表征弱还原-弱氧化环境;其三环萜烷以C₂₁或C₂₃为主峰,甾烷呈"V"字型分布,藿烷/甾烷比值小于3.0,具陆源和水生双重有机质生源。煤及碳质泥岩中奥利烷和双杜松烷等陆源标志物均较少,而泥岩中却普遍富含这些化合物,反映了近岸海相沉积有机质的特殊性。因而,在近海盆地地层中奥利烷和双杜松烷丰度并不能代表总体有机质中陆源的输入比例,更可能是指相标志。通过与烃源岩的分子地球化学对比表明,崖城油气田的主体原油兼具煤成烃和泥岩所生油的生物标志物组成,为混源油,来自渐新统不同沉积相带烃源岩。     

从海陆对比探讨东海南部中生代油气勘探前景

为探讨东海南部中生代油气勘探前景,开展了东海及邻近陆域中生代油气勘探现状、区域构造和烃源岩条件等对比分析。结果显示,海陆中生代深部地质结构存在较大差异,二者在中生代地层分布的面积与厚度、岩浆岩的分布与强度以及烃源岩条件等方面均表现出明显的不同。综合分析认为,海域中生代构造更稳定、地层分布更广、厚度更大、烃源岩条件更好,因而推测其具有好的油气勘探前景。     

Regional geology, depositional environment and maturity of organic matter of Early to Middle Jurassic coals, coaly shales, shales and claystones from the Eastern Pontides, NE Turkey

Jurassic coals, coaly shales, shales and claystones from the Eastern Pontides in NE Turkey have been investigated using microscopical, petrophysical and detailed organic geochemical methods in order to determine their catagenetic stage, to reveal the composition of the organic matter and to discuss the depositional environment. The Liassic–Dogger period in the Eastern Pontides was characterised by the presence of a rift system which resulted in rock units of very variable lithology and facies. Coal seams, ranging from a few centimetres to several decimetres and intercalated with shales, claystones and sandstones occur within the basal part (the Aggi Formation) as well as in the uppermost part (the Hamurkesen Formation) of the rift deposits. All coal seams investigated are at a catagenetic maturation stage corresponding to subbituminous B up to low volatile bituminous ranks. They represent a depositional environment of short-lived swamp areas with intense aerobic reworking of the higher plant detritus by heterotrophic bacteria, but with possible anaerobic microenvironments at deeper levels. At least some coal seams were influenced temporarily by marine ingressions. Most samples are impure humic coals with highly variable chemical compositions as indicated by the broad range of their hydrogen contents. This variation in hydrogen content is partly attributed to variable contributions of algal material. On the other side, considering several analytical results, the hydrogen variation is primarily due to bacterial reworking that affected the composition of the organic matter to variable extent and resulted especially in an enrichment of bacterial lipids. Bacterial reworking by an active microbial community within the upper layer of the peat swamp is inferred from elevated concentrations of iso-alkanes even exceeding those of the corresponding n-alkanes in several samples which, to the best of our knowledge, have not been observed with coals before.     

The relative role of lower and upper crustal processes in the formation of trace element compositions of oils

This study presents the analysis of correlation between trace element compositions of caustobioliths (oils, coals, oil and black shales), upper and lower continental crust, and living matter. It was shown that trace element concentrations in coals and oil shales have the better correlation with the upper crustal values, whereas trace elements in oils correlate well with the lower crustal values. The statistically significant, yet poorer correlation was observed for trace element compositions of oils and living matter as compared to correlations between oils and lower crust. The results suggest that oils are compositionally more homogeneous on a basin scale and possibly have more heterogeneous composition in different petroleum basins. A suite of characteristic trace elements (Cs, Rb, K, U, V, Cr, and Ni) that was used for analysis allowed a consistent interpretation of the relative upper and lower crustal contributions to the trace element composition of oils.     

Application of light hydrocarbons (C4–C13) to oil/source rock correlations:: a study of the light hydrocarbon compositions of source rocks and test fluids from offshore Mid-Norway

Relatively little work has been published on the correlation between the light hydrocarbon distributions in reservoir fluids and their proposed source rocks [Philippi, G. T. (1981)]. The aim of our work was to study this relationship in detail for samples from Mid-Norway. The main source rocks offshore Mid-Norway are the marine shales of the Late Jurassic Spekk Formation and the coals and paralic shales of the Early Jurassic Åre Formation. Reliable light hydrocarbon (C₄–C₁₃) data for source rock samples were acquired by thermal extraction-GC of the source rocks. Of these, notably the hydrocarbons in the C₆–C₈ range (routinely measured in test fluids) were used to discriminate between the Spekk and Åre Formation samples. A total of twenty-six samples from the Spekk Formation and twenty-four samples from the Åre Formation at different maturity levels and facies were analyzed. In general, the two source rock types differ in their light hydrocarbon composition by the presence of relatively more aromatics and cyclohexanes in the Åre samples, while the Spekk samples are richer in cyclopentanes and acyclic hydrocarbons. We show that source rock facies is a more important indicator of light hydrocarbon composition than maturity variation. Differences in the chemical composition, which can be used to discriminate between the two source rocks, were supported by differences in the carbon isotope composition of individual components of the same fraction, as determined by GHM-IR-MS analysis of eleven samples. Further, the light hydrocarbon compositions of reservoir fluids (oils and condensates) were compared with those for the source rock(s). Sixty-six gas chromatograms of oils and condensates, representing most of the known petroleum accumulations in Mid-Norway, were collected. Of these, five oil samples were selected for detailed isotopic analysis of individual components (GC-IR-MS). When using a classification scheme based on data from sediment samples, data for the light hydrocarbon fraction of oils and condensates indicate that the Spekk Formation is the dominant source for most of the fields from Mid-Norway, with a significant contribution from the Åre Formation being detected principally in one field. Differences in the chemical composition of the C₆–C₈ fractions were supported by differences in the carbon isotope composition of individual components, which also discriminate between the oils. Although the classification diagrams used in this study are based on source rock data from Mid-Norway, the method can be applied to other areas, providing that the diagrams are calibrated with source rock data from the area of interest.     

Evaluation of the liquid hydrocarbon potential of coal by artificial maturation techniques

In certain areas, relatively large accumulations of liquid hydrocarbons have been attributed to coals. Evaluating the source rock potential of coal requires definition of both the generative potential (quantity and composition of generated hydrocarbons), and expulsion efficiency. Hydrous pyrolysis experiments were completed using Tertiary lignites (R_o < 0.35%) from North Dakota and the Far East to evaluate the source rock potential of coal. The North Dakota lignite is vitrinite-rich (93%) and liptinite-poor (3%); the Far East lignite is liptinite-rich (32% of total maceral content). These lignites have Hydrogen Index values of 123 and 483 mg HC/g OC, respectively. Differences in oil-pyrolysate yield, composition, and temperature of maximum pyrolysate yield from hydrous pyrolysis experiments for these two lignites are related to the type and amount of liptinite and vitrinite macerals. A maximum of 48 and 158 mg oil-pyrolysate/g OC is generated and expelled from the North Dakota and Far East lignites, respectively. Although these lignites consist predominantly of gas-prone vitrinitic components, their organic-rich nature can compensate for their poor convertibility to liquid hydrocarbons. The composition of these artificially generated oil-pyrolysates are similar to some non-marine oils, suggesting that this type of organic matter can be a significant contributor to many oils. Although the overall composition of the generated products from the two lignites is similar, the distribution of these products is significantly different. Homologous series of methyl ketones and alkyl benzenes have been identified in both oil-pyrolysates. Their presence and characteristic distribution suggest that microbial degradation occurred during the formation of these lignites. Although many coals generate significate amounts of liquid hydrocarbons that are similar to naturally occurring oils, poor explusion efficiency limits their source rock potential. Significant amounts of liquid products are assimilated by the vitrinitic matrix of most coals prior to expulsion, severely limiting the amount of petroleum available for migration and reservoir accumulation. However, adequate expulsion may occur in certain liptinite-rich coals or coals occurring in unique depositional settings.     

卟啉的研究现状及其应用

在前人研究资料及作者近年来的研究成果的基础上，综述了卟啉化合物地球化学研究的现状，包括金属卟啉的类型，卟啉的化学结构系列，高度脱链基卟啉和高碳数咔琳等及其它们在沉积物(如油页岩、煤和现代沉积物)中的分布特征和成因机理。指出了今后需要加强研究的领域，如沉积物中新的金属卟啉类型探讨和卟啉化学结构的确定等。文章还综述了卟啉化合物地球化学指标在地质勘探中的应用，如:评价生油岩质量，油源对比，油气运移研究，古沉积环境研究和有机质热成熟度研究等。     

Application of multivariate modelling to detect hydrocarbon components for optimal discrimination between two source rock types

The present study presents a multivariate procedure to reveal light hydrocarbon components which significantly distinguish between source rock thermal extracts. The two source rocks included in this study are the marine shales of the Late Jurassic Spekk Formation and the coals and paralic shales of the Early Jurassic Åre Formation offshore Mid-Norway.Because of the large number of components in the C₄–C₁₃ hydrocarbon fraction of source rock extracts a multivariate approach was required. The procedure consists of three distinct steps: (1) Principal component analysis of the whole data set for detection of non-significant individual components. This reduced the number of individual components from 46 to 22. (2) Separate principal component analysis of the two source rocks (Åre and Spekk) to detect outliers. (3) Principal component modelling of each of the two source rocks after deletion of outliers and non-discriminating variables to detect those hydrocarbon components which are most significant and robust for the separation of the two source rocks.The resulting model shows that there is a definitive compositional difference between the source rocks investigated.     

Exploration Potential of Marine Source Rocks Oil-Gas Reservoirs in China

So far,more than 150 marine oil-gas fields have been found onshore and offshore about 350. The marine source rocks are mainly Paleozoic and Mesozoic onshore whereas Tertiary offshore.Three genetic categories of oil-gas reservoirs have been defined for the marine reservoirs in China:primary reservoirs,secondary reservoirs and hydrocarbon-regeneration reservoirs.And three exploration prospects have also been suggested:(1)Primary reservoirs prospects,which are chiefly distributed in many Tertiary basins of the South China Sea(SCS),the Tertiary shelf basins of the East China Sea (ECS)and the Paleozoic of Tarim basin,Sichuan basin and Ordos basin.To explore large-middle-scale even giant oil-gas fields should chiefly be considered in this category reservoirs.These basins are the most hopeful areas to explore marine oil-gas fields in China,among which especially many Tertiary basins of the SCS should be strengthened to explore.(2)Secondary reservoirs prospects,which are mainly distributed in the Paleozoic and Mesozoic of the Tarim basin,Sichuan basin,Qiangtang basin and Chuxiong basin in western China,of which exploration potential is less than that of the primary reservoirs.(3)Hydrocarbon-regeneration reservoirs prospects,which are chiefly distributed in the Bohai Bay basin,North Jiangsu-South Yellow Sea basin,southern North China basin,Jianghan basin, South Poyang basin in eastern China and the Tarim basin in western China,of which source rocks are generally the Paleozoic.And the reservoirs formed by late-stage(always Cenozoic)secondary hydrocarbon generation of the Paleozoic source rocks should mainly be considered to explore,among which middle-small and small oil-gas fields are the chief exploration targets.As a result of higher thermal evolution of Paleozoic and Mesozoic source rocks,the marine reservoirs onshore are mainly gas fields,and so far marine oil fields have only been found in the Tarim basin.No other than establishing corresponding marine oil-gas exploration and development strategy and policy, sufficiently enhancing cognition to the particularity and complexity of China's marine petroleum geology,and applying new thoughts,new theories and new technologies,at the same time tackling some key technologies,it is possible to fast and effectually exploit and utilize the potential huge marine oil-gas resources of China.     

Oil-generating potential of Tertiary coals and other organic-rich sediments of the Nyalau Formation,onshore Sarawak

The oil-generating potential of coals and other organic-rich sediments from the Late Oligocene–Early Miocene Nyalau Formation, the offshore extension of which is believed to be a major source rock, is evaluated. Coals of the Nyalau Formation are typically dominated by vitrinite, with moderate and low amounts of exinite and inertinite, respectively. Significant amounts of clay minerals are present in these coals and those containing between 15 to 65% mineral matter by volume are termed carbargilite. The samples analysed range from sub-bituminous to high-volatile bituminous rank, possessing vitrinite reflectance in the range 0.42% to 0.72%. T_max values range from 425°–450°C which is in good agreement with vitrinite reflectance data. Good oil-generating potential is anticipated from these coals and carbargilites with moderate to rich exinite content (15–35%). This is supported by their high hydrogen indices of up to 400 mgHC/gTOC, Py–GC (S2) pyrograms with n-alkane/alkene doublets extending beyond nC₃₀, and their being in the early to mid-mature oil-window range. Petrographically, the most significant evidence of the oil-generating potential of these coals is the generation of petroleum-like materials (exsudatinite) visible under the microscope. Exsudatinite is a secondary maceral, commonly considered to represent the very beginning of oil generation in coal, which is shown here to also have an important role to play in hydrocarbon expulsion. The precursor of exsudatinite in these coals is the maceral bituminite which readily expels or mobilizes to hydrocarbon-like material in the form of oil smears and/or exsudatinite as observed under the microscope. The maceral bituminite is considered to play a major generative role via early exsudatinite generation, which is considered to facilitate the overall expulsion process in coaly source rocks.     

江陵凹陷下第三系两个含油系统油源岩的地化特征

本文论述了江陵凹陷下第三系两个含油系统中原油地化特征截然不同是由两套烃源岩成烃母质不同和成熟度不同造成的。第一含油系统新沟咀组下段Ⅱ油组中、下部-泥隔层上部为主力烃源岩，已达到中等-好生油岩级别，可提供较丰富的油源。研究表明，这套主力烃源岩在不同区带存在自身单一油源供油或自身与外来双重油源供油两种模式，石油运移距离可达１０ｋｍ以上，它基本上控制了新沟咀组油田和荆沙组油藏的分布范围。第二含油系统潜江组烃源岩尽管埋深多浅于２０００ｍ（Ｒｏ＜０.５%）不成熟，但在潜江组潜三、四段地层中发现了有机质丰度很高，母质类型为ⅠＳ型和Ⅰ型干酪根的烃源岩，具有早期生成未成熟油的潜力，可以形成原生油藏，应在勘探中给予重视。     

中国西北侏罗纪煤系显微组分生烃潜力、产物地球化学特征及其意义

从吐哈盆地侏罗纪煤中分离富集了藻类体、孢子体、角质体、镜质体、基质镜质体和丝质体6种主要显微组分,进行了热解及热模拟实验,并对各显微组分热模拟生成的产物热解油进行了碳同位素组成等分析。各显微组分热解生烃潜力及其热解产物热解油的碳同位素组成表明,煤系有机质中藻类体的生油潜力最高,生成的液态烃类的碳同位素组成最轻;孢子体、角质体等陆源富氢组分生烃潜力低于藻类体,生成的液态烃类的碳同位素组成重于藻类体生成的液态烃类,与煤系含油气盆地中原油的碳同位素组成基本一致。这些富氢显微组分应该是煤系有机质中主要的生油显微组分。镜质体和基质镜质体的生油潜力相对较低,其生成的液态烃类的碳同位素组成比一般煤系原油重得多,而且这些组分本身对液态烃具有较强的吸附力,尽管其在煤系有机质中所占的比例很大,仍然难以成为生成液态石油的主要显微组分,只能在高成熟演化阶段成为良好的生气显微组分。丝质体等惰性组分生烃潜力极低,不可能成为生油组分。此外,结合原煤的显微组分组成、生烃潜力和元素分析,提出仅仅以壳质组的含量高低来评价煤的生烃潜力不完全可靠,热解是经济、快速、有效的评价方法。     

Organic Geochemical and Petrographic Characteristics of the Coal Measure Source Rocks of Pinghu Formation in the Xihu Sag of the East China Sea Shelf Basin: Implications for Coal Measure Gas Potential

Coal measure source rocks, located in the Xihu Sag of the East China Sea Shelf Basin, were analyzed to define the hydrocarbon generation potential, organic geochemistry/petrology characteristics, and coal preservation conditions. The Pinghu source rocks in the Xihu Sag are mainly gas-prone accompany with condensate oil generation. The coals and shales of the Pinghu Formation are classified from "fair" to "excellent" source rocks with total organic carbon(TOC) contents ranging from 25.2% to 77.2% and 1.29% to 20.9%, respectively. The coals are richer in TOC and S1+S2 than the shales, indicating that the coals have more generation potential per unit mass. Moreover, the kerogen type of the organic matter consists of types Ⅱ-Ⅲ and Ⅲ, which the maturity Ro ranges from 0.59% to 0.83%. Petrographically, the coals and shales are dominated by vitrinite macerals(69.1%–96.8%) with minor proportions of liptinite(2.5%–17.55%) and inertinite(0.2%–6.2%). The correlation between maceral composition and S1+S2 indicates that the main contributor to the generation potential is vitrinite. Therefore, the coals and shales of the Pinghu Formation has good hydrocarbon generation potential, which provided a good foundation for coal measure gas accumulation. Furthermore, coal facies models indicates that the Pinghu coal was deposited in limno-telmatic environment under high water levels, with low tree density(mainly herbaceous) and with low-moderate nutrient supply. Fluctuating water levels and intermittent flooding during the deposition of peat resulted in the inter-layering of coal, shale and sandstone, which potentially providing favorable preservation conditions for coal measure gas.