The Bangong Lake-Nujiang suture zone is an extreme important tectonic boundary in the Tibetan Plateau which is not only closely related to evolution of the Tethyan tectonic domain, but also directly controls the formation and inversion of the Mesozoic southern Qiangtang oil and gas-bearing basin. Based on stratigraphic correlation, sandstone petrography analysis and detrital zircon U-Pb dating, this paper reconstructs provenance changes in the Dongqiao-Beila area and reveals multi-stage subduction processes and microblock amalgamations in the central Bangong Lake-Nujiang Ocean (BNO). The BNO branch (Amdo Ocean) at Dongqiao-Beila area began to subduct in the Early Jurassic, resulting in amalgamation of the Amdo block to the southern Qiangtang terrane and rifting the Dongkaco microblock away from the northern Lhasa terrane and formed two new BNO branches of the Dongqiao Ocean to the north and Beila Ocean to the south. The lower Xihu Group close to the Beila suture in the south of the Dongkaco micoblock shows recycle deposits from the underlying Upper Triassic Quehala Group, while the upper Xihu Group close to the Dongqiao suture in the north of the Dongkaco microblock began to receive detritus from the southern Qiangtang terrane, indicating the Dongqiao Ocean demised and the Dongkaco microblock has amalgamated on the southern margin of the Qiangtang terrane with a peripheral foreland basin developed during the Middle Jurassic. Subsequent subduction of the Beila Ocean droved the Dongkaco microblock continuing to converge with south Qiangtang terrane in the Middle Jurassic and promote abundant materials from the south Qiangtang terrane transporting into the Middle-Upper Jurassic Jienu Group in the foreland basin on the Dongkacuo microblock. Wide collision between the Qiangtang and Lhasa terrane occurred during the latest Jurassic and Early Cretaceous (147-141 Ma) and continued during Aptian (ca. 120 Ma) until the Beila Ocean finally dimed at Dongqiao-Beila Area. In response to multi-stage northward subductions of the BNO, the south Qiangtang Basin changed from passive continental margin to active continental margin during earliest Jurassic and developed arc-related basin system of eastwest extending back-arc basin, volcanic arc and fore arc basin from north to south. The Lower Jurassic Quse black shale and overlying Buqu bioclastic limestone deposited in the back-arc basin. Continuous convergence and microblock collision contributed to rapid regression and uplift of the south Qiangtang basin,resulting in the deposition of tidal Xiali Formation with gypsum and mudstone during the Middle Jurassic. As the result of collision between the Lhasa and Qiangtang terrane in the Early Cretaceous, the south Qiangtang Basin evolved in fold thrust belt of the peripheral foreland basin and resulted in differential burial and denudation of the Jurassic successions. During the Late Jurassic-Early Cretaceous, the Quse black shale and Buqu bioclastic limestone were correspondingly buried rapidly due to the tectonic compression and entered the stage of oil generation and dolomitization, making it become the most important accumulation period in the south Qiangtang Basin.

Due to lower exploration degree, the stratal pattern and correlation is still controversial in the oil-bearing Qiangtang Basin, one of the largest sedimentary archives with thick organic carbon-rich strata in the Tibetan Plateau, which impacting the basin evaluation of petroleum conditions and oil-bearing systems. Based on investigations of biostratigraphy, chronostratigraphy, sequence stratigraphy and basin evolution of the Qiangtang Basin, we conduct a comprehensive data compilation to analyze the depositional history and ages of the basin rock record. The results reveal that: (1) New isotopic chronology data confirm that there is a Precambrian metamorphic crystalline basement in the Qiangtang Basin. The Paleozoic basement fold system is buried at a depth of 7-15 km, which is overlaid unconformably by the Mesozoic deposits. (2) The proposed age of the Nadikangri Formation is the Upper Triassic, contradicting previous suggestion of Lower-Middle Jurassic. (3) The dolomites of the paleo-reservoir in the southern Qiangtang Basin belong to the Late Triassic rather than the Middle Jurassic in age, and the dolomites are probably "allochthonous root-less" and tectonic contact with the Buqu Formation. (4) The Bilong Co oil shales in the southern Qiangtang Basin belong to the Lower Jurassic rather than the Middle Jurassic. (5) The Quemo Co Formation has an age not younger than the Middle to Lower Jurassic rather than the original suggestion of the Middle Jurassic. (6) Facies changes and paleontological analysis combined with isotopic data indicate that the Shenglihe-Changsheshan oil shale was deposited in a marine environment during the Early Cretaceous. (7) Isotopic chronology and field geological survey confirm that the Kangtuo and Suonahu Formations comprise simultaneous strata with different sedimentary facies. The data synthesis and progress in stratigraphic research of the Qiangtang Basin provide a new basis for the development of the stratigraphic division and correlation scheme of the basin, as well as the analysis of its petroleum system and potential.

The overall research level of the Qiangtang Basin is at its primal stages due to lack of data and uneven distribution, which makes the predictions of hydrocarbon source rocks and reservoirs imprecise. Based on the analysis of basin attributes, sedimentary systems and their combination-coupling relationships, this article solves the problems of multiple interpretations of sedimentary facies in regions with abundant data and lack of sedimentary model guidance in regions lacking data. Hence, three geological acknowledgments are acquired as follows. First, we specify two distinct consecutive stages of basin property of the north and the south subterrains in Qiangtang Basin based on the systematically summarized closing history of the Koh Xil-Jinsha River Ocean, Bangong Lake-Nujiang Ocean and Longmuco-Shuanghu Ocean. During the Late Triassic-Early Cretaceous epoch, the north Qiangtang terrain evolved from a compound foreland basin to a weak-compressional in-land residual sea basin and entered into a rapid uplift-denudation period with multiple folds and faults. The south Qiangtang terrain, meanwhile, transferred from a passive continental margin to an active continental margin, and also entered into a rapid uplift denudation period with multiple folds and faults. Basin attributes of eight key sedimentary periods are clarified. Second, we compile ten tectonic-lithofacies paleogeography maps in the Late Triassic -Early Cretaceous epoch of Qiangtang Basin and distribution maps of igneous rocks of Nadigangri Formation based on basin properties, sedimentary systems, and the coherent relationships among them. These maps reveal the controlling effect of tectonic background on sedimentary process in Qiangtang Basin and enhance the precision of sedimentary facies prediction in data-poor areas. Third, we figure out the tectonic-lithofacies paleogeography in developing periods of hydrocarbon source rocks and reservoirs explicitly. The distribution of hydrocarbon source rocks of Bolila Formation-Bagong Formation is controlled by foreland depression and deep-water shelf of the passive continental margin, and that of Quse Formation is controlled by a back-arc extensional basin and weak-compressional in-land residual sea basin. The dolomite reservoirs of the Buqu Formation are developed at the platform margin belt. With this knowledge, we compile four distribution maps of hydrocarbon source rocks and reservoirs. All these new acknowledgments will boost the oil-gas exploration process in the Qiangtang Basin.

The Qiangtang Basin, located in the eastern part of the Tethys domain, is the only large-scale superimposed basin in China where no industrial oil or gas fields have been discovered. Based on the new round of comprehensive research on oil and gas geology in recent years, a set of widely distributed black mudstone with large thickness (600-800 m) of Bagong Formation is found being developed in the front delta-shallow water shelf during the foreland basin stage of Late Triassic in Qiangtang Basin, which is of great significance for oil and gas exploration. In order to study the organic geochemical characteristics of the black mudstone of Bagong Formation in the eastern margin of the North Qiangtang Depression, 61 core samples from shallow well and 64 hand-drilled plunger samples are collected to carry out geochemical and mineralogical analysis, and the source rock potential and sedimentary environment are evaluated. The results show that: (1) The black mudstone of the Bagong Formation, with TOC of 0.06%-5.81%, is poor-medium source rock on the whole, and some reach the standard of high-quality. Formed in weak oxidation-weak reduction environment, the organic matter type is II2―III, mainly belonging mixed organic matter. It is in the late mature to high mature stage with Ro of 0.95%- 1.90%. (2) The Bagong source rock has great hydrocarbon generation potential, due to high organic matter abundance, good organic matter type, and moderate maturity. (3) There developed a source-reservoir assemblage of “lower generation and upper reservoir” between the Bagong source rock and the glutenite reservoir at the bottom of the Quemocuo Formation, which lays a foundation for the formation of large and medium-size oil and gas fields. Besides, the Bagong mudstone is a favorable layer for shale oil exploration. In general, the Bagong source rock is of great significance for conventional and unconventional oil and gas exploration in the eastern margin of the North Qiangtang Depression.

Based on the data of seismic, well logging, core, cast thin sections and conventional physical properties, taking the middle-lower section of Mishrif Formation in the Middle East X Oilfield as an example, the identification of sequence stratigraphic orders and the controlling effects of sequence stratigraphic orders on sedimentary evolution are studied. The results show that: (1) The Mishrif Formation is divided into 5 third-order sequences (SQ1-SQ5) and 10 fourth-order se⁃ quences (PSS1-PSS10). The MB2—MC1 single layers in the middle-lower section of Mishrif Formation correspond to SQ2-SQ3, including 4 fourth-order sequences (PSS3-PSS6), in which multiple fifth-order and sixth-order sequences are developed. (2) Carbonate open platform-weakly rimmed platform of a sub-basin is developed in the study area, and the reservoirs mainly exist in platform margin shoals and open platform shoals. The shoal facies can be further subdivided into rudist shoal, rudist-containing bioclastic shoal, bioclastic-arene shoal, bioclastic-spherical shoal and bioclastic shoal ac⁃ cording to bioclastic types. (3) The sixth-order sequence controls the sedimentary sequence of a single shoal body, the fifth-order controls the combination characteristics of multiple shoal bodies, the fourth-order sequence determines the evolution characteristics of sedimentary microfacies, and the third-order sequence determines the evolution characteristics of sedimentary systems. (4) In the early stage of PSS3 and PSS4 of SQ2 sequence, the two fourth-order sequences are in a platform front slope environment, with the development of lens-shaped collapsed coarse-grained sediments. In the later stage of PSS3 and PSS4, a sedimentary sequence of the platform margin intershoal → medium energy shoal is developed. The PSS5 and PSS6 of the SQ3 sequence develop a sedimentary sequence of platform margin intershoal → medium energy shoal → high energy shoal. After the completion of SQ3 sedimentation, a special incision filling sedimentation is formed.

Permian marine shale is widely distributed in Hefeng area, western Hunan-Hubei fold belt. It is rich in organic matter and is a set of high-quality source rock. Compared with the shale gas of Niutitang Formation and Wufeng Formation-Longmaxi Formation, the research degree of marine shale gas of Middle-Upper Permian is relatively low. Survey well HD1 reveals the reservoir characteristics of the Gufeng-Dalong shale of Middle-Upper Permian and its gasbearing properties in the core of Chenjiawan anticline, Hefeng area. So taking the Well HD1 as the research target, analysis of organic geochemistry and data of X-ray diffraction whole rock mineral, SEM, high pressure mercury intrusion, isothermal adsorption and on-site experimental permit to characterize the marine shale heterogeneity of Gufeng Formation-Dalong Formation in Middle-Upper Permian in Hefeng area. The results show that four types of lithofacies are developed in Gufeng-Dalong marine shale as siliceous shale facies, mixed shale facies, calcareous shale facies and clay shale facies. Controlled by lithofacies, the linear density of fracture diversities among different lithofacies, and the micro pore-fracture structures of different types and scales are developed. Siliceous shale in the lower part of Dalong Formation and Gufeng Formation has high organic carbon content, large specific surface area and total pore volume. The differential, onrush and variation coefficient of permeability show that the heterogeneity of mixed and calcareous lithofacies in Dalong Formation is weak, while that of siliceous lithofacies is strong. Different types of lithofacies in Xiayao Formation and Gufeng Formation show strong heterogeneity. The heterogeneity of gas generation capacity and reservoir capacity result in the gas content having the characteristics of strong heterogeneity in different lithofacies. In general, the shale layers with high organic carbon content, relatively well developed brittle minerals, natural macro fractures, micro organic pores and micro fractures in minerals, with good reservoir physical properties and high gas content are all siliceous shale facies, and located in the bottom part of Dalong Formation and Gufeng Formation.

In 2022, a significant gas breakthrough was achieved in the key exploration well (Kuitan-1) located in the Kuihuadao structural belt of the eastern offshore, Liaohe Depression, with high-productivity gas flows in Dongying Formation, Shahejie Member 3, and Jurassic Xiaodonggou Formation. It is worth noting that there are significant differences in methane carbon isotope composition (δ13C1) between the Mesozoic and Cenozoic natural gas formations. Determining the origin of natural gas and its source rock is significant for assessing the potential of natural gas resources and selecting exploration targets. This paper systematically analyzes geochemical data such as the components and stable carbon isotope composition of natural gas samples from the three gas-bearing strata. The results indicate that there are organic thermogenic gas and inorganic gas in the eastern offshore: (1) The natural gas in the Dongying Formation and Shahejie Formation belongs to the coal-type organic thermogenic gas, mainly consisting of methane, the dryness coefficient is at the range of 0.789-0.949. δ13C1 is mainly around -35‰. Natural gas originates from the mature mudstone in the middle and lower part of Shahejie Formation in Gaizhoutan sag, and accumulates during the late Dongying-Minghuazhen periods. According to the empirical formula, Ro of gas source rock ranges from 0.77% to 1.59%. There is a clear indication of migration effects for natural gas in the middle and shallow Dongying Formation, with clearly higher Ro of gas source rock than the mudstone at the same depth. In the deep Shahejie Member 3, it accumulates in situ or with short distance migration, indicated by the similar or slightly higher Ro of gas source rock than the mudstone at the same depth. (2) The natural gas in Jurassic Xiaodonggou Formation is of inorganic origin. It has an average dryness coefficient of 0.991 and is characterized by extremely heavy methane carbon isotope (δ13C1＞-20‰). It’s inferred that the natural gas originates from Fischer-Tropsch synthesis in the deep crust or mantle, migrates and accumulates along the deep-seated fault with strike-slip activity during the late Dongying period. These natural gas reservoirs of two genetic types have obvious vertical separation and different accumulation processes. Plays around the Shahejie mature source rocks in the Gaizhoutan sag and the Yingkou-Tong'erbu strike-slip zone are favorable to organic thermogenic gas and inorganic gas respectively.

Under the new situation that the ways to obtain the oil and gas exploration right has been reformed from the previous application first, "no cost" acquisition to open competition through bidding, auction, listing and "the one with the highest price or the best evaluated bidder obtains", it is urgent to establish a set of block value evaluation techniques and methods for oil and gas exploration right, determine the value of the granting block, and formulate a bidding scheme to obtain the exploration right by open competition. Aiming at the uncertainty of oil and gas geological conditions, exploration and development technology, market and other aspects in the exploration and development of oil and gas mineral resources, this paper puts forward an economic evaluation method of discounted cash flow based on Monte Carlo simulation. According to the uncertainty of expected oil and gas resources, exploration and development investment, operating cost and sales income, this method can obtain the value of the granting blocks under different probability conditions and then provide a basis for the preparation of bidding scheme. This method has been applied to the value evaluation of the granting block of oil and gas exploration right in Tarim Basin, Xinjiang. Corresponding to different competitive quotations, the probability of occurrence for enterprise's internal rate of return is calculated respectively. When the quotation is 485 million yuan, it is estimated that the probability of the internal rate of return exceeding 8% is 75.4%. Ultimately, the exploration right of the granting block was clinched a deal with 485.32 million yuan, indicating that the evaluation method is feasible. The economic evaluation method of discounted cash flow based on Monte Carlo simulation provides decision-making basis for enterprises to adapt to the competitive granting policy of oil and gas mining right, and has important practical significance for enterprises to openly compete for oil and gas mining right.

The fracture-cavity carbonate reservoirs is characterized by complex spatial distribution and high heterogeneity. The establishment of an accurate and reliable three-dimensional geological model is fundamental and essential for the efficient development of such reservoirs. This paper presents a comprehensive overview of the developing stages in the technology and methods employed for modeling fracture-cavity carbonate reservoirs. The evolution of fracture-cavity reservoir modeling can be delineated into three distinct phases: In the first phase, reservoir modeling techniques introduce concepts like "zone division" and "karstic control" as methods for modeling reservoir bodies, with a primary reliance on variogram-based statistical algorithms. In the second phase, it is emphasized of the modeling of internal cave structures, which involves categorizing cave types and summarizing different combinations of cave types. These endeavors are underpinned by the application of geological constraints to construct various karstic control models, with a predominant focus on target-based and multi-point geological statistics as modeling algorithms. In the third phase, the researcher further delve into the causal factors governing the formation of reservoir bodies, specifically focusing on factors such as underground rivers. For these unique causal factor-driven cave reservoirs, field outcrop and cave data were employed to construct training images. Mathematical integration of prior geological causative models and posterior seismic responses result in the development of comprehensive constraint probability bodies. The models generated in this phase exhibite finer detail and have the capacity to represent internal structural elements within underground river reservoirs. This paper concludes by offering a forward-looking perspective on the technological advancements in geological modeling of fracture -cavity carbonate reservoirs. It highlights the imperative need for further research in fracture-controlled karst reservoir modeling methods and underscores that the future trajectory lies in artificial intelligence geological modeling methods based on deep learning.