The Huanghua subbasin in the Bohai Bay Basin of China has recorded significant breakthroughs in shale oil production in its Paleogene lacustrine systems, in which fine-grained dark mud- stones act as both the source and the reservoir rock. These tight shales are emerging as a new productive play, and their study is important to boost China's shale oil production. Drawing from a rich database consisting of cores and drilling cuttings, geological and geochemical analytical data, wire-line logs, three-dimensional seismic sections, and well production data, this study aimed at documenting the salient geological and geochemical properties of the shale play, describing the sweet spot delineation procedures, discussing the main factors controlling well performance, and stating key implications. The quality of mudstone intervals in order of priority depends upon seven parameters: Rock-Eval measure of the hydrocarbons already present in the sample before pyrolysis, brittleness index, lamination, total organic carbon (TOC), oil saturation index, vitrinite reflectance (R-o), and porosity. The performance of horizontal wells is controlled by four factors: mudstone quality, lateral length and orientation, well spacing, and reservoir stimulation and extraction technologies. Landing into the high-quality mudstone interval is essential for a productive horizontal well. Favorable mudstones are characterized with low clay abundance (<25%), highly laminated structure, TOC content of similar to 2 to 6 wt. %, and moderate maturity of similar to 0.9% to 1.1% R-o. The successful development of the tight shale oil in the Huanghua sub- basin implies that tight lacustrine mudstone can be an economically viable shale oil play. Its success is governed by the optimal combination of favorable geological and geochemical properties and the application of appropriate engineering technologies.

The Sverdrup Basin is one of the important petroliferous basins in the Arctic. It has abundant oil and gas resources, but the exploration degree is relatively low. Based on the IHS database and literatures in the public domain, this paper documented the geological characteristics and distribution of oil and gas in the Sverdrup Basin, and classified the petroleum systems and hydrocarbon plays in the basin. The undiscovered hydrocarbons were eventually assessed by Monte Carlo simulation and the favorable exploration areas were predicted. The investigation results show that the discovered oil and gas accumulations are mainly distributed in the western area of the basin, which consists of Sabin and Edinburgh sub-basins. Oil and gas are mainly reserved in the Jurassic and Triassic clastic reservoirs. Two petroleum systems, which are the Paleozoic and Mesozoic systems, were identified in the basin. The Mesozoic petroleum system has a far greater exploration potential. Undiscovered recoverable reserves (mean value) in the Mesozoic petroleum system are 474.81 MMbbl (1 MMbbl=1×106 bbl, 1 bbl=0.137 t) of oil, 13 620.82 Bcf (1 Bcf=1×109 ft3, 1 ft3=0.028 3 m3) of natural gas and 63.66 MMbbl of condensate, amounting to 2 808.61 MMboe (3.85×108 t), of which the natural gas accounts for 80.82%. The Lower Jurassic structural hydrocarbon play in the western area of the basin, the Upper Triassic-Lower Jurassic structural hydrocarbon play in the Edinburgh sub-basin and the Upper Jurassic structural hydrocarbon play in the Sabine sub-basin are the most promising exploration areas.

The hydrocarbon accumulation modes and differences in the Tethyan realm serve as a hot research topic in the petroleum geology community at home and abroad. Both the Persian Gulf Basin in the Middle East and the Sichuan Basin in China, situated on the southern and northern sides of the Tethyan realm, respectively, record the whole geological process of the opening and closure of the Prototethys, the Paleotethys, and the Neotethys sequentially, exhibiting anomalous hydrocarbon enrichment Based on the analysis of the plate tectonic evolution in the Tethyan realm, this study dissects the structures and hydrocarbon accumulation conditions of both basins. Followed by a systematic comparative analysis of the factors controlling hydrocarbon enrichment in the process of plate breakup and convergence in the Tethyan realm, this study proposes petroleum exploration targets in the realm. The results are as follows: (1) Since the Meso-Neoproterozoic, the Persian Gulf Basin and the Sichuan Basin have undergone similar tectonic evolution in the early stage but different in the late stage. Under the influence of the formation and evolution of the Prototethys, Paleotethys, and Neotethys oceans, both basins experienced multi-stage development and modification, forming two major extension-convergence cycles. Consequently, both basins are characterized by the vertical orderly superimposition of various basin prototypes in the order of rift-intracratonic basin (passive continental margin)-foreland. (2) The fact that the Tethyan realm was long located at medium-low latitudes and the local anoxic environment formed in the process of plate breakup and convergence played a vital role in the formation of extensive source rocks. The source rocks are predominantly distributed in underfilled rifts and deep depressions that were connected to the ocean in the unidirectional continental breakup process; basin-slopes and intra-shelf basins on passive continental margins; basinal lows within intracratonic basins, and underfilled foredeeps in foreland basins. The favorable areas for the formation of carbonate reservoirs include platform margins, submarine highs and paleo-uplifts within platforms, and fault zones. The evaporite cap rocks, intimately associated with the basin evolutionary stages and global dry-hot events, are critical for large-scale hydrocarbon preservation. (3) Under the influence of Tethyan evolution, the Persian Gulf Basin and the Sichuan Basin share similar primary factors controlling hydrocarbon enrichment. The moderate tectono-sedimentary differentiation and structural modification in the process of prototype basin superimposition, as well as the spatio-temporal matching of elements critical for hydrocarbon accumulation, are beneficial for the development of large oil and gas fields. The macroscopic hydrocarbon distribution is dictated by source rock-cap rock assemblages, while the local hydrocarbon distribution is governed by trap-reservoir assemblages. The critical factors determining the differential hydrocarbon enrichment in the Persian Gulf Basin and the Sichuan Basin include plate size and position, basement stability, eustatic movement, paleoclimate, and tectonic transformation. Besides, different tectonic modification intensities are closely related to the type, enrichment degree, and distribution of hydrocarbon reservoirs.

The West Barents Sea Basin in the Arctic is one of the most promising petroleum basins in the world. With the latest data from the IHS database, this study investigated the petroleum geology of the basin, documented the distribution characteristics of petroleum resources, systematically analyzed the petroleum systems and plays, evaluated the resource potential, and predicted the favorable exploration fairways in the West Barents Sea Basin. The results show that regionally, discovered oil and gas accumulations are mainly distributed in the southwest area of the basin; stratigraphically, oil and gas reserves are mainly confined to the Jurassic and Triassic reservoirs, which host 72.6% and 15.5% of the total proved and probable reserves, respectively. The basin has two known petroleum systems: the Jurassic/Triassic composite petroleum system and the Permian/Carboniferous composite petroleum system. The resource evaluation by the Monte Carlo statistical methodology indicates that the means of undiscovered resources in the West Barents Sea Basin are 487.4×10~6 t of oil, 1375.6×10~9 m~3 of gas, and 84.6×10~6 t of condensate, amounting to 1681.9×10~6 t, of which the gas accounts for 66.0%. Based on the results of resource evaluation and comprehensive analysis of petroleum geology, two favorable exploration fairways were selected: the favorable exploration zone of the Jurassic play and the favorable exploration zone of the Triassic play in the southern area of the basin.

在"双一流"建设背景下,积极构建资源勘查工程国际化人才培养体系,推进《全球油气分布》全英文课建设具有必要性和急迫性,对培养高素质的资源勘查工程国际化综合人才具有重要的意义.根据中国石油大学(北京)2018年"本科教学工程"建设指导思想的要求,确定了《全球油气分布》全英文课建设目标,制定了该门课的建设方案,并对存在的困难和面临的挑战进行了讨论.为更好地推进课程建设,《全球油气分布》全英文课将以过程性教学为指导,以学生为中心,充分利用雨课堂、智慧教室等软硬件条件,推进线上、线下混合教学,充分调动学生的主观能动性,增强互动性,在拓展学生专业知识面的基础上,重点培养学生英文文献查阅、归纳整理、专业英语汇报、表述的能力,并根据学生的反馈不断优化课程.

In recent years, primary hydrocarbon accumulations of Precambrian-Lower Cambrian have caused an increasing attention in the oil and gas explorations worldwide. The Eastern Siberian Basin in Russia, the Oman Basin in the Middle East, and the Sichuan Basin in China are endowed with the richest oil and gas reserves in the Precambrian-Lower Cambrian primary hydrocarbon accumulations. This study takes these three basins as examples to systematical and comprehensively document the geological characteristics and distribution of the global Precambrian-Lower Cambrian primary hydrocarbon accumulations through a large amount of data analysis and statistics, to provide insights for further breakthroughs of oil and gas explorations in ancient stratigraphic successions of sedimentary basins. The global proven and controlled reserves of Precambrian-Lower Cambrian primary hydrocarbon accumulations have reached 30.09×109 boe (4.12×108 t), of which 84.2% are distributed in the Eastern Siberian Basin, while the Oman Basin and the Sichuan Basin account for 8.9% and 6.5%, respectively. The source rocks are dominated by marine mudstones, shales and carbonate rocks, which are generally immature to over-mature and mostly distribute in low structural parts. Carbonate rocks and clastic rocks are important types of reservoir rocks. Early dolomitization, superficial leaching and hydrocarbons injection are important mechanisms for the development of ancient carbonate reservoirs. Most of the hydrocarbons in deep and ultra-deep ancient strata are stored in carbonate rocks. At the same time, the extensively developed high-quality regional caprocks are the key to preserving abundant hydrocarbons. Three types of accumulation models, self-generating and self-preserving, reservoirs adjacent to source rocks, and reservoirs isolated to source rocks, constitute the main models of Precambrian-Lower Cambrian primary hydrocarbon accumulations.

With acquisition of geochemical data of oils and source rocks in mature basins, oil source re-identification is important for petroleum system analysis and subsequent exploration. In the Baxian Depression of the Bohai Bay Basin, the main source rocks are in the Sha-3 (Es3) and Sha-1 (Es1) Members of the Paleogene Shahejie Formation. These cannot be differentiated using the standard mass chromatograms and bivariate cross-plots of biomarker parameters obtained from the representative samples of the source rocks. In this paper, discriminant analysis (DA) was employed to highlight the difference between these two sets of the source rocks samples and to identify the sources of the oils in the multivariate space. Based on a comprehensive literature review, we selected twenty three candidate parameters that may reflect the oil sources, and excluded ones which are affected by the thermal maturity and biodegradation in the study area. Eight informative parameters were chosen with stepwise DA from these candidate parameters to establish a discriminant model for the oil-source correlation. The model achieved a high correct discrimination rate using leave-one-out cross-validation (90.7%) and original validation (94.4%). We found that these 8 parameters can describe the characteristics of the main sources and can effectively differentiate these sources. The high posterior probabilities in the oil-source correlation results indicate that the oils in the Wen?an Slope were mainly sourced from the source rock in Es3. These results, together with geological mapping of reservoir sand-bodies, suggest that more oil derived from the Es3 source rocks may exist below the thick shale and/or mudstone sequence in the Es1 than previously thought.

Using multiple biomarker parameters to quantitatively unravel mixed oils from different sources: an example from the slope of the Qikou Depression, Bohai Bay Basin, China L. ZHANG*, G. BAI, X. ZHAO, L. ZHOU, S. ZHOU, W. JIANG, Z. WANG 1 Key Laboratory of Petroleum Resource, Institute of Geology and Geophysics, CAS, Beijing 100029, China (*correspondence: lpzhang@mail.iggcas.ac.cn) 2 State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China 3 Dagang Oilfield Company of PetroChina, Tianjin 300280, China

The integrated analyses, classification and comparison of petroleum systems, combined with the latest oil and gas field data from the Middle East and the previous research results, indicate how tectonic-depositional evolution, source rocks and seals, and petroleum resource endowment are inter-linked. The impacts of these factors on the enrichment of petroleum resources could be established. There are four super petroleum systems in the passive margin basins of the Arabian Plate, namely, the intra-craton, the back-arc, the passive margin and the active margin, among which the passive margin and intra-craton super petroleum systems are the most significant. Regionally, oil and gas in the study area are mainly concentrated in the Central Arabian Basin and the Rub' Al Khali Basin. Stratigraphically, oil is mainly reservoired in the Cretaceous and Jurassic whereas the gas in the Permian and Triassic. The diffe-rential enrichment of hydrocarbons is mainly controlled by three factors: the distribution of high-quality effective source rocks and the positive structural trends of basins, which have a dominant control on the regional distribution of oil and gas, and the regional seals, which govern the stratigraphic distribution of oil and gas.

Systematic analyses of statistical data of shale oil resources and an integrated investigation of geological elements in major shale oil basins in USA were made. They characterize the distribution features of shale oil resources and document the controlling factors for shale oil endowment in USA. The results provide insights for shale oil exploration and production in China. Recoverable shale oil resources amount to 1 51×109 bbl in USA, of which 36.5×109 bbl have already been proven with a discovery rate of 24.2%. The shale oil resources are unevenly distributed. The Permian Basin has the lion's share of the total, followed by the Gulf and Williston basins. The enrichment of shale oil resources is largely governed by the volume of high quality source rocks, the extensive top and bottom seals of shale oil plays and the scale of "sweet spots" in shale oil reservoir intervals. The former two control the total endowment of shale oil resources and the latter controls the production volume of shale oils. It is suggested that China's shale oil exploration should focus on the selection of favorable plays and their fairways in large sedimentary basins. The delineation of new "sweet spots" and the expansion of the extent of known "sweet spots" are the keys for the new breakthroughs of shale oil exploration and the increase of both shale oil production and reserves.

Deeply buried (3.5–4.5 km) fan deltaic and braided deltaic sandstones of the Eocene Shahejie Formation are important hydrocarbon reservoirs in the Raoyang Sag of the Bohai Bay Basin (North China). An integrated approach incorporating petrophysics, thin‐section petrography, scanning electron microscope (SEM), cathodoluminescence (CL), and well log analysis was applied to investigate diagenesis, diagenetic minerals, and their impacts on reservoir quality. The sandstones of the Sha‐3 (the third Member of the Shahejie Formation) are dominated by lithic arkoses and arkoses with a low‐moderate compositional maturity and a moderate textural maturity. The pore systems are dominated by secondary pores resulting from dissolution of framework grains, micropores among authigenic clays, and minor amounts of primary intergranular pores. Chemically unstable framework grains such as feldspar and lithic fragments experienced alteration and resulted in formation of authigenic kaolinite. Dissolution and alteration of feldspars and rock fragments and pressure solution of detrital quartz grains were the main sources for quartz cements. Mechanical compaction and cementation by calcite, dolomite, quartz, kaolinite, and mixed‐layer illite/smectite destroyed primary pores, whereas dissolution of framework grains generated secondary pores. Five types of diagenetic facies are identified based on framework mineralogy, texture, diagenetic minerals, and pore systems. These comprise the following: (a) quartz‐cemented sandstone, (b) tightly compacted sandstone, (c) carbonate‐cemented sandstone, (d) clay‐mineral‐cemented sandstone, and (e) clean dissolved sandstone. Diagenetic processes and evolution sequences for the five diagenetic facies were reconstructed based on textural relationships from thin section, SEM, and CL studies. The reservoir quality evolution of various diagenetic facies is predicted by considering variations in grain size, sorting, shape, and matrix content of sandstones. This work, which investigates the diagenetic sequence of sandstones, will provide insights into reservoir quality prediction for low‐permeability sandstones with similar tectono‐depositional settings.

The commonly-used tools for oil-source correlation, such as mass chromatograms of biomarkers and bivariate cross-plots of geochemical parameters, cannot deal with multiple geochemical parameters and plenty of samples simultaneously, leading to uncertainties in the results and even failures sometimes. In this paper, the discriminant analysis (DA) is selected from supervised machine learning algorithms, as it is superior to the commonly-used tools as well as other multivariate statistical methods, with the accumulation of geochemical data of source rocks and oils. In the slope of the Qikou Depression, the main source rocks in the third (Es-3) and first members (Es-1) of the Paleogene Shahejie Formation were deposited in similar depositional environments. The source rocks cannot be distinguished with the commonly-used tools. We firstly extended geochemical parameters and then used stepwise DA to select informative parameters and to develop a discriminant model for oil-source correlation. The 22 selected parameters are supported by geochemical characteristics of the source rocks in the study area. The DA of these parameters for oil-source correlation achieved a high correct rate of original validation (96.8%) and leave-one-out cross-validation (89.4%), indicating a sufficient discriminatory power. The oilsource correlation results with high posterior probabilities, showing strong similarity between the sources and oils, coincide with geological conditions and illustrate that there is still much exploration potential in the study area, especially for the Es-3 petroleum system. All these illustrate that DA is one of the most useful tools for oil-source correlation with the accumulation of geochemical data of source rocks and oils.

Fractal geometry provides an effective method for characterization of the complex and irregular pore structure of Eocene Shahejie low permeability sandstones in the Raoyang Sag, the Bohai Bay Basin, China. Laboratory measurements including porosity, permeability, scanning electron microscope (SEM), thin sections, nuclear magnetic resonance measurements (NMR) and X-ray computed tomography (CT) technology are used to provide insights into the fractal characteristics of pore structure in sandstones of Eocene Shahejie Formation in the Bohai Bay Basin, China. Quantitative CT analysis reveals the pore radius is not always linear to T2 (transverse relaxation time) value obtained from the NMR tests, but instead power function of T2. Fractal analysis was performed on the T2 distribution using various fractal models, and the related fractal dimensions are calculated. The fractal dimensions calculated using various fractal models are correlated with NMR parameters and permeability. The fractal curves break into two segments at the T2cutoff (T2 separating the immovable and movable fluids) value or smaller when using fractal model Ⅰ and fractal model Ⅱ, and only the large-scale pore networks can be described by the fractal geometry. Mostly the entire pore size distributions (micro-pores to large-scale pore networks) can be described by the fractal model Ⅲ, and the calculated fractal dimensions are in accordance with the CT scanning and thin section data, and are strongly correlated with the T2gm (geometric mean of T2), permeability and BVI (bulk volume of immovable fluids). The fractal behaviors of pore size distributions from NMR analysis have implications for pore structure evaluation in low permeability sandstones with similar geological settings.

In order to reveal the development mechanism of high-quality clastic rock reservoir, the basic characteristics of Sha-3 Member of the Shahejie Formation in the Raoyang sag, Bohai Bay Basin, are analyzed based on cores observation, thin-sections and SEM images, and petrophysical properties measurements as well. It is found that high-mature composition and texture, early oil charging, and dissolution are the main factors controlling the formation and preservation of pores in deep reservoirs. Compaction is the major factor destructing pores, whereas formation overpressure is conducive to the preservation of original pores, high compositional and medium textural maturity can enhance the resistance capacity to compaction and protect primary pores. Early oil charging could lead to temporary cessation of diagenesis and thus inhibit the cementation. When organic acids entered reservoir formations, considerable amounts of secondary pores were formed, leading to the local improvement of petrophysical properties. When predicting good quality belt in exploration of deep basin, it is recommended that the superimposing effects of the multiple factors（overpressure, early oil charging, compositional and textural maturity, diagenesis） be taken into consideration.

Mercury intrusion capillary pressure (MICP), nuclear magnetic resonance (NMR), routine core analysis, thin sections, and scanning electron microscope (SEM) analysis were used to gain insight into the pore structure of the Eocene Sha-3 (the third member of the Shahejie formation) low-permeability sandstones in the Raoyang sag, including pore type, pore geometry, and pore size. Quantitative NMR parameters and petrophysical properties were integrated to build up the relationship between microscopic pore structure and macroscopic performance. The pore systems of Sha-3 sandstones are dominantly of residual intergranular pores, intragranular dissolution pores, and intercrystallite micropores associated with authigenic clay minerals. The high threshold pressure and low mercury withdrawal efficiencies from MICP analysis indicate the poor pore connectivity and strong heterogeneous. Both uni- and bimodal transverse relaxation time (T-2) spectrum can be found because of the coexistence of small and large pores, and the T-2 of major pore size occurring at about 1.0 to 100 ms. The Sha-3 sandstones have a relatively high irreducible water content and short T-2 components in the T-2 range. Long T-2 components can only be observed in samples rich in large pores or microfractures. T-2gm (the geometric mean of the T-2 distribution) correlates well with irreducible water saturation and permeability. A methodology for pore structure classification is presented integrating NMR parameters of T-2gm, bulk volume of immovable fluid (BVI), and petrophysical parameters such as reservoir quality index (RQI) and permeability. Consequently, four types of pore structures (types A, B, C, and D) are identified, and characteristics of individual pore structure are summarized. The comprehensive analysis of NMR measurements combined with thin sections, SEM and MICP analysis is useful for describing microscopic pore structure, which is important to maintaining and enhancing petroleum recovery in low-permeability sandstone reservoirs.

The United Arab Emirates (UAE) is the 8th largest oil producing country and is rich in oil and gas resources. By the end of 2015, 68 oil and 23 gas fields had been discovered. The initial proved and probable (2P) oil, gas and condensate reserves amount to 81,135.9 MMb (million barrels), 192.09 Tcf (trillion cubic feet), and 6496.58 MMb respectively, which are mostly reservoired in the Jurassic and Cretaceous carbonates. With the latest field data, this study attempts to document the salient features of petroleum systems in UAE. Based on depositional facies of source rock intervals, pods of source rocks were delineated. On the basis of an oil-and gas-source correlation, five known petroleum systems were identified and they are Lower Silurian-Upper Permian Khuff gas, northeast foreland Upper Jurassic-Lower Cretaceous gas, Upper JurassiceJurassic petroleum, Upper Jurassic/Lower Cretaceous-Lower Cretaceous composite petroleum, and Middle Cretaceous- Middle to Upper Cretaceous/Cenozoic petroleum systems. Of them, the Upper Jurassic/Lower Cretaceous-Lower Cretaceous composite petroleum system contains 73.2% of the total 2P reserves and thus it is the focus of this study. The Upper Jurassic and Lower Cretaceous source rocks consist of argillaceous limestone, mudstone and shale, which were deposited as intrashelf basin facies. The distribution of oil and gas in this system is controlled by the source kitchens and the regional evaporite seal.

在加蓬海岸盆地最新油气田相关数据与油气地质资料基础上,以储层为核心将盆地划分了盐上、盐下两类共6个油气成藏组合,其中位于盐下有贝利阿斯阶砂岩成藏组合、阿普特阶砂岩成藏组合,盐下油气成藏组合特征为:陆相储层、盐岩上覆遮挡封盖、断裂带运移;而位于盐上有阿尔布阶—赛诺曼阶砂岩成藏组合、马斯特里赫特阶碎屑岩成藏组合、康尼亚克阶—坎潘阶浊积岩成藏组合、始新统—渐新统河道砂岩成藏组合,盐上油气成藏组合特征为:海相储层、盐构造控藏、盐运动沟通源储。以蒙特卡洛模拟为计算方法,以成藏组合为单元进行油气资源评价,计算出加蓬海岸盆地未来30年待发现资源量为6895×10~6bbl,其中石油资源量为5893×10~6bbl,天然气资源量为6005×10~9ft3;凝析油资源量为34×10~6bbl。结合加蓬海岸盆地成藏组合特征分析与资源评价结果,认为阿普特阶砂岩成藏组合为最有利勘探区。

There are rich oil and gas resources in marine carbonate strata worldwide.Although most of the oil and gas reserves discovered so far are mainly distributed in Mesozoic,Cenozoic,and upper Paleozoic strata,oil and gas exploration in the Proterozoic–Lower Paleozoic（PLP）strata—the oldest marine strata—has been very limited.To more clearly understand the oil and gas formation conditions and distributions in the PLP marine carbonate strata,we analyzed and characterized the petroleum geological conditions,oil and gas reservoir types,and their distributions in thirteen giant oil and gas fields worldwide.This study reveals the main factors controlling their formation and distribution.Our analyses show that the source rocks for these giant oil and gas fields are mainly shale with a great abundance of type I–II organic matter and a high thermal evolution extent.The reservoirs are mainly gas reservoirs,and the reservoir rocks are dominated by dolomite.The reservoir types are mainly karst and reef–shoal bodies with well-developed dissolved pores and cavities,intercrystalline pores,and fractures.These reservoirs arehighly heterogeneous.The burial depth of the reservoirs is highly variable and somewhat negatively correlated to the porosity.The cap rocks are mainly thick evaporites and shales,with the thickness of the cap rocks positively correlated to the oil and gas reserves.The development of high-quality evaporite cap rock is highly favorable for oil and gas preservation.We identified four hydrocarbon generation models,and that the major source rocks have undergone a long period of burial and thermal evolution and are characterized by early and long periods of hydrocarbon generation.These giant oil and gas fields have diverse types of reservoirs and are mainly distributed in paleo-uplifts,slope zones,and platform margin reef-shoal bodies.The main factors that control their formation and distribution were identified,enabling the prediction of new favorable areas for oil and gas exploration.

The Proterozoic–Lower Paleozoic marine facies successions are developed in more than 20 basins with low exploration degree in the world. Some large-scale carbonate oil and gas fields have been found in the oldest succession in the Tarim Basin, Ordos Basin, Sichuan Basin, Permian Basin, Williston Basin, Michigan Basin, East Siberia Basin, and the Oman Basin. In order to reveal the hydrocarbon enrichment roles in the oldest succession, basin formation and evolution, hydrocarbon accumulation elements, and processes in the eight major basins are studied comparatively. The Williston Basin and Michigan Basin remained as stable cratonic basins after formation in the early Paleozoic, while the others developed into superimposed basins undergone multistage tectonic movements. The eight basins were mainly carbonate deposits in the Proterozoic–early Paleozoic having different sizes, frequent uplift, and subsidence leading to several regional unconformities. The main source rock is shale with total organic carbon content of generally greater than 1% and type I/II organic matters. Various types of reservoirs, such as karst reservoir, dolomite reservoir, reef-beach body reservoirs are developed. The reservoir spaces are mainly intergranular pore, intercrystalline pore, dissolved pore, and fracture. The reservoirs are highly heterogeneous with physical property changing greatly and consist mainly of gypsum-salt and shale cap rocks. The trap types can be divided into structural, stratigraphic, lithological, and complex types. The oil and gas reservoir types are classified according to trap types where the structural reservoirs are mostly developed. Many sets of source rocks are developed in these basins and experienced multistage hydrocarbon generation and expulsion processes. In different basins, the hydrocarbon accumulation processes are different and can be classified into two types, one is the process through multistage hydrocarbon accumulation with multistage adjustment and the other is the process through early hydrocarbon accumulation and late preservation.

The Niudong Buried Hill Field, which lies in the Baxian Depression of the Bohai Bay Basin, is the deepest oil/gas accumulation in eastern China. Its Precambrian dolomite reservoir occurs at burial depths of 5860 m–6027 m. This paper attempts to document the hydrocarbon charging and accumulation history in this field, which could greatly enhance the understanding of the mechanisms for the formation of deep hydrocarbon accumulations. Our previous study of oil trapped in fluid inclusions has demonstrated that the ratio parameters of the fluorescence spectral intensities at 425 nm and 433 nm (Q425/433 ratio), and at 419 nm and 429 nm (Q419/429 ratio) can be more effective for revealing hydrocarbon charging history than the previously-used fluorescence parameters such as Lambda max and red/green quotient as well as fluorescence colors. The hydrocarbon charging and accumulation history in the Niudong Buried Hill Field was studied with an integrated approach involving the application of these two spectral parameters of petroleum inclusion fluorescence as well as utilization of other data including homogenization temperatures of aqueous inclusions coeval with petroleum inclusions, and cross-cutting relationships of cements and “oil veins” in pores and fractures. The results indicate that the dolomite reservoir in the Niudong Buried Hill Field experienced three episodes of hydrocarbon charging. In the first two episodes (between 38.5Ma and 25Ma), the low mature and mature oils, which were derived from source rocks in the Sha-4 Member of the Eocene Shahejie Formation, migrated into the reservoir, but part of them leaked out due to normal faulting at the updip margin of the buried hill. These early-charged oils were preserved mainly in small pores in micritic dolomites by oil-wettability and capillary pressure. In the Neogene, the basin subsided as a whole and local faults at the updip margin became inactive and played a sealing role. By approximately 13Ma, the source rocks became highly mature and the generated hydrocarbons then migrated into the reservoir and accumulated. Therefore, the last charging is the most important for hydrocarbon accumulation in the Niudong Buried Hill Field.