The deep-seated strata of oil-bearing basins have become a practical area for oil and gas exploration. The Junggar Basin has a long evolution history and complex tectonic background. Based on the current exploration status, the new exploration fields have been systematically summarized. Four new exploration areas in the basin's deep-ultra-deep strata have been proposed: the prototype marine basin, the unconventional inner source hydrocarbon accumulation in Permian in the Western Depression, large-scale stratigraphic hydrocarbon accumulations in the hydrocarbon-rich depression, and the Jurassic-Cretaceous strata in the southern margin. The prototype marine basin is controlled by Carboniferous hydrocarbon source rocks spread across multiple sedimentary centers, forming relatively independent whole petroleum system around each source center. The inner source hydrocarbon accumulations of Permian in the Western Depression show the hydrocarbon accumulation patterns with orderly distribution of conventional-unconventional resources. The deep strata of the Pen 1 Well West-Shawan Sag are a practical area for finding trillion cubic meter gas regions. In the hydrocarbon-rich depression, the deep strata are jointly controlled by paleogeomorphology and lake level, forming large-scale stratigraphic traps and clustered hydrocarbon reservoirs in trough areas. The southern margin's deep Jurassic-Cretaceous strata have large-scale structural traps, with high-quality reservoirs still present below 8000 meters, meeting the geological conditions for forming large-scale gas reservoirs. Analysis of these four areas shows that the Junggar Basin has entered a new stage of deep-strata-focused exploration. Its hydrocarbon resources generally exhibit the characteristics of conventional-unconventional hydrocarbons coexisting in order. High-quality hydrocarbon source rocks and effective reservoir formation factors provide a solid material basis and favorable reservoir formation conditions for hydrocarbon accumulation in the basin's deep strata.

The exploration and development of marine carbonate rocks in the Tarim Basin have been underway for nearly 40 years. Through five revolutionary shifts in mindset, focusing on changes in understanding karst reservoirs and hydrocarbon accumulation, and aiming to achieve quantitative modeling of karst-fractured cavities, the theory of ultra-deep marine carbonate oil and gas geology and exploration technology has been innovated and developed. This has guided the transformation of carbonate exploration targets from buried-hill karst, reef-shoal karst, and interlayer karst to fault-controlled karst. The exploration frontier is continuously approaching source rocks, moving from ancient uplifts to ultra-deep ancient slopes and paleo-depressions, leading to the discovery of several large carbonate oil and gas fields. Breakthroughs have led to the development of high-density 3D seismic exploration technology in large desert areas and quantitative modeling of fractures and cavities, confirming geological reserves equivalent to 2 billion tons of oil, and achieving an annual oil and gas output equivalent to 5 million tons, advancing the establishment of largest ultra-deep oil and gas production base in China. In the practice of exploring ultra-deep carbonates in the Tarim Basin, the success of rapid exploration discoveries has been attributed to the philosophy of unrestricted exploration, continuous innovation in karst theory and understanding of hydrocarbon accumulation, advances in 3D seismic exploration technology, and the integration of exploration and development. Under special geological conditions such as long-term shallow burial, late-stage rapid deep burial, and a cold basin environment, effective source rocks developed in the early basin stages. Large effective reservoir-caprock combinations have developed in ultra-deep formations, forming extensive belts of hydrocarbon accumulation. With ongoing theoretical innovation and technological advancement, ultra-deep carbonate remains a critical area for substantial reserve growth in the future.

To address the challenges faced by Chinese petroleum enterprises in overseas risk exploration, including difficulties in acquiring high-quality assets and limitations in developing existing assets, the study systematically analyzes the risk exploration decision-making mechanisms of leading international oil companies. Core data were collected through expert interviews and consulting research, focusing on six representative international firms, including ExxonMobil, Eni, and Shell, with an in-depth examination of three strategically balanced enterprises. The findings indicate that international oil companies have established a four-stage standardized decision-making process (preliminary assessment, in-depth study, program implementation, and execution) supported by three core mechanisms: （1） a professional team division system integrating exploration new project teams, technical teams, management teams, and quality control teams for full-process support; （2）strategically-oriented portfolio optimization to balance risks and returns; and （3） technology collaborative innovation mechanisms that enhance decision efficiency through high-performance computing platforms and intelligent decision-making systems. Case studies reveal that Equinor shortened decision-making chains via regionally integrated organizational structures, Eni achieved strategic goals through a “dual exploration model” and multi-track parallel decision-making, while Shell optimized exploration targets using its play portfolio analysis framework. Tailored to Chinese enterprises’ institutional characteristics, this research proposes a four-dimensional improvement framework: strategic-asset portfolio synergy optimization, standardized decision-process reengineering, intelligent management platform development, and internal control system enhancement. These recommendations provide theoretical and practical insights for improving overseas oil and gas exploration decision quality in China, facilitating a transition from scale-driven expansion to value-centric operations.

Ten thousand meters deep is one of the important areas of natural gas exploration in Kuqa depression, and it is a potential replacement area because of its large resources, good preservation conditions and convenient oil and gas charging. But there are still some key problems such as structural trap, scale reservoir and reservoir formation type.Based on the geological structure anatomy of deep structure, hydrocarbon generation potential evaluation, reservoir physical simulation and comprehensive research of accumulation combination, the key conditions and fields selection of gas accumulation at 10000 meters deep depth are analyzed.The results show that large fault-anticlines, anticlines and fault-block structures, which are controlled by coal measure strata, giant thick mudstone and Paleozoic unconformity double detachment strata, are developed in the 10000 meter deep area of Kuqa Depression, and the Kelasu thrust belt is the most concentrated.Huge thick Triassic-Lower Jurassic high-over-mature coal measures and lacustrine mudstone source rocks are developed in the depth area of 10000 meters, with hydrocarbon generation capacity of （1000~3000）×10⁸m³/km². Under the large-area distribution of braided river delta plain-front giant thick sand body and late rapid deep burial, ultra-high temperature and ultra-high pressure strong structural compressive stress, the large-scale development of fracture-porosity reservoir still has 5%~10% porosity and more than 1mD permeability at the depth of 10000 meters.The 10000-meter deep area is mainly regional reservoir-cap combination in the Triassic-Lower Jurassic near/within the source, which is dominated by structure-lithologic gas reservoirs and tight sandstone gas reservoirs. The strategic exploration area of the preferred Kelasu thrust belt is 4200km², and the natural gas resources are up to 1.5×10⁸m³ and the trap under Keshen gas field is a favorable target area.The research results will provide the basic understanding for the exploration of natural gas in the field of clastic rock in the depth of 10000 meters in China, and lay the geological theoretical foundation for further exploration of large gas fields under the Kela and Keshen reservoirs in the thrust belt of Kuqa foreland basin.

With the continuous advancement of hydrocarbon exploration in petroliferous basins across China, expanding strategic replacement areas has become a critical issue for oil and gas development. Recent exploration breakthroughs reveal that in-situ tight gas within source rocks of the Sichuan Basin possesses resource potential exceeding 1×10¹² m³, emerging as a prospective new strategic replacement area. Detailed core descriptions, well log interpretations, and geochemical data analyses are integrated in this study to investigate the genetic types and stratigraphic distribution characteristics of in-situ tight gas in the Sichuan Basin, elucidate its hydrocarbon accumulation patterns, and clarifie resource potential with future exploration directions. Key findings include:① Influenced by multicyclic tectonic evolution and frequent sea-lake level fluctuations, the Sichuan Basin has developed multiple sets of high-quality thick source rocks, forming both marine and terrestrial in-situ tight gas systems.② Two distinct source-reservoir configurations are identified: a) Near-source accumulation enveloped by source rocks with superior sealing conditions (e.g., Qiongzhusi Formation tight gas and Xu5 member tight gas); b) Integrated source-reservoir systems with overpressure preservation (e.g., tight gas in the Lei-32 submember and Mao-1 Member marine marl). ③ Three in-situ tight gas systems demonstrate combined resource potential exceeding 1×10¹² m³: (1) Qiongzhusi Formation tight sandstones (most favorable area: Ziyang-Penglai region); (2)Leikoupo Formation marine marls (primary prospective area: southern-central Sichuan); (3)Xu5 member tight sandstones (key exploration target: Penglai-Jinhua area). These systems represent crucial future exploration frontiers, with particular emphasis on the Ziyang-Penglai region for Qiongzhusi tight gas development.

Field outcrops and drilling data reveal that the Paleozoic–Mesozoic coal rocks are widely distributed in Qaidam B asin, with certain hydrocarbon generation potential and good reservoir performance, which is a new exploration field in the basin. However, the level of research and understanding is relatively low. A systematic study on coal rocks in the Middle Jurassic Dameigou Formation and the Upper Carboniferous Keluke Formation in Qaidam Basin is conducted, including sedimentary environment, distribution, coal properties, reservoir characteristics, resource amount, and gas enrichment rules. In addition, gas resource potential in coal rocks is evaluated, and exploration deployment orientations are proposed in Qaidam Basin. The study results show that: (1) The limnic facies coal rocks in the Middle Jurassic have a single layer thickness of 2 – 30 m and a distribution area of 11100 km²; The transitional facies coal rocks in the Upper Carboniferous have a single layer thickness of 1 – 6 m and a distribution area of 5689 km². (2) The coal rocks in the Middle Jurassic and the Upper Carboniferous are semi-bright to bright coals in a middle coal rank stage, all possessing gas generation capacity; TOC of coal rocks in the Middle Jurassic Dameigou Formation is 32.22%–79.50%, with an average of 62.85%, and R_o is 0.77%–1.38%, with an average of 0.9%; TOC of coal rocks in the Upper Carboniferous Keluke Formation is 35.67%–98.34%, with an average of 72.40%, and R_o ranges in 0.92%–1.82%, with an average of 1.57%. (3) The coal rock reservoirs are characterized by good porosity and permeability properties, and the coal cleats have a high density, showing a reticular distribution pattern and good connectivity; The matrix pores such as stomata, mold pores, dissolution pores, intercrystal pores and plant tissue pores are observed; The measured porosity of coal rocks ranges from 5.26% to 34.01%, with an average of 15.65%; The permeability is 5.11–12.60 mD, with an average of 8.91 mD. (4) Five types of gas accumulation and dispersion combinations are classified vertically in coal rocks, among which the widely distributed coalrock–mudstone and coal rock–limestone gas accumulation combinations have good sealing conditions and high peak values of total hydrocarbon gas logging shows, indicating the most favorable combinations for coal rock gas enrichment. (5) The favorable areas of the Middle Jurassic in Yuandingshan–Jiulongshan area in the northern margin of Qaidam Basin and the Upper Carboniferous in Dulan–Wulan in Delingha area are optimally selected for further strategic exploration deployment. The above understanding is expected to guide the strategic deployment of coal rock gas in Qaidam Basin, open up a new field for coal rock gas exploration, and unveil a new chapter in natural gas exploration in the basin.

Over the past fifty years, breakthroughs have been continuously made in the exploration of the Jurassic system in the Ordos Basin. In order to clarify its controlling factors and exploration potential, based on the previously discovered oil reservoirs and completed drilling and evaluation wells, using drilling geological data, core analysis, and seismic data, a detailed characterization of the pre Jurassic paleogeomorphology, sand bodies, and structures in the basin has been systematically carried out. The characteristics of fault development in the three-dimensional area have been analyzed, and the types and controlling factors of Jurassic oil reservoirs in the study area have been identified. The exploration direction and potential of the Jurassic system in the basin have been pointed out. The results show that: （1）The pre Jurassic paleogeomorphology presents a “U+V” - shaped multi-stage ancient river structure, with nine types of subdivided units such as inter river hills and terraces, and significant reservoir control characteristics; （2）The Jurassic oil source mainly comes from the Triassic Chang 7 source rocks, and the Late Jurassic Early Cretaceous episodic charging laid the foundation for the widespread distribution of oil reservoirs; （3）The coupling of ancient rivers and low amplitude nose uplift structures controls the distribution of reservoir clusters, and the three-stage fault relay transmission forms a three-dimensional reservoir formation model; （4）The complex fault zone on the western edge of the basin, the northeastern part of the Jingbian slope, and mature areas still have the potential for billions of tons of resources through fine exploration. The research results have deepened the theoretical understanding of Jurassic reservoir formation and supported new breakthroughs in exploration.

The Lower Qiulitag Formation of the Upper Cambrian in Tabei area is adjacent to the Northern Depression and the Kuche Depression, with dual hydrocarbon supply conditions and favorable petroleum geological conditions. The breakthrough in the Xiongtan 1 well had revealed its significant exploration potential. The researches of the detailed sedimentary characteristics, micro-facies distribution patterns, and sedimentary models within a sequence framework were lack in the Lower Qiulitage Formation, which restrict the further exploration of the Lower Qiulitage Formation. Through the measurement of 2334.4 meters of strata in six sections in the Xiaoerblak outcrop area, as well as the measurement of GR curves and carbon isotope curves in two sections, 555 samples collection and making thin sections for analysis, the stratigraphic and sequence characteristics, sedimentary features, and depositional models of the Lower Qiulitag Formation were systematically identified. Based on the comparison of lithology, GR curves and carbon isotope curves, it has been clarified that the Lower Qiulitage Formation in the study area corresponds to SQ7 and the top-missing SQ8 in the platform-basin region. The main rock types include granular dolomite, thrombolite dolomite, stromatolite dolomiteand laminated dolomite. The overall depositional environment was a restricted platform facies, comprising 5 subfacies and 6 microfacies，which grouped into 7 typical sedimentary sequences. Influenced by the Wensu-Yaha paleo-uplift, during the SQ7 period, the deposition was characterized by tidal flat subface with frequent cyclic changes of various microfacies, showing minor lateral variations. And a depositional model was established, that the supratidal zone, intertidal zone, and subtidal zone developed sequentially from the paleo-uplift toward the basin. During the SQ8 period, the deposition transitioned from tidal flat subface to intra-platform shoal subface, with significant lateral differences in the proportions of mound and shoal，And a depositional model was established, that the intertidal zone, subtidal high-energy zone, and intra-platform shoal developed sequentially from the paleo-uplift toward the basin. There wewe 61~74 sedimentary sequences developed inside the outcrop area of SQ7, and a single sedimentary sequence can form a high-quality reservoer-cap combination. The sedimentary sequences developed continuously in the over-100-meter stratum have the potential to form an overlapping and contiguous lithologic reservoir.The reservoir is widely developed in SQ8 and has the potential to form high-quality structural oil and gas reservoirs. The west Tabei area, controlled by Wenshu-Yahagu uplift, widely developped mound and shoal reservoirs with high quality. When somewhere was overlaid by tight lithology and existing fractures of connected source rock, high-quality oil and gas reservoirs were easy to form, which is a favorable area for exploration.The research results provide the direction for the next oil and gas exploration of Lower Qiulitag Formation in Tabei area.

Deep-ultradeep layers have become a key focus of petroleum exploration and research both domestically and internationally due to their abundant hydrocarbon resources. Revealing the maximum depth of deep-ultradeep oil and gas reservoirs has important practical significance for evaluating deep hydrocarbon resources, deploying ultradeep drilling, and understanding exploration risks. In this paper, a method and process for predicting the maximum depth of deep-ultradeep oil and gas reservoirs based on the theoretical of the Whole Petroleum System (WPS) was proposed. This method can quantitatively predict the maximum depth of conventional, tight, and shale oil and gas reservoirs in petroliferous basins. This article uses discovered oil and gas reservoirs and drilling data as examples to predict the maximum depth of hydrocarbon reservoirs in petroliferous basins such as Tarim, Junggar, Sichuan, Ordos, Songliao, and Bohai Bay in China. The results show that the maximum depths of conventional, tight, and shale oil and gas reservoirs in China’s six major petroliferous basins are usually between 800-4400m, 5050-7990m, and 5400-9300m. The maximum depth of oil and gas reservoirs in petroliferous basins increases with the decrease of geothermal gradient, improvement of organic matter types, and the enhancement of reservoir oil affinity. With the improvement of drilling technology and prediction level, the field of discovering hydrocarbon resources will continue to expand. Additionally, tectonic movements can also change the maximum depth of hydrocarbon reservoirs under actual geological conditions. The maximum depth of ultradeep oil and gas reservoirs in Cambrian-Ordovician carbonate of Tarim Basin were predicted to be more than 9500±50m and 10500±100m according to the results of actual shallow-medium-deep oil and gas drilling.

According to the “Technical Specification of Seismic Data Interpretation” (GB/T 33684-2017), oilfield companies use the accuracy of well–seismic depth errors as an important indicator for assessing the precision of seismic interpreted structure results. There are two problems during the implementation process. Firstly, the absolute error and relative error accuracies are artificially specified in the national standard, lacking certain theoretical basis and technical support, which has a low operability in actual practice; Secondly, oilfield companies have established corresponding enterprise standards, with the continuously higher accuracy requirements of well seismic–depth errors far exceeding the vertical seismic resolution. Based on the practice of oil and gas exploration in Sichuan Basin, four main controlling factors that affect well–seismic depth errors are deeply analyzed, including (1) migrated imaging methods; (2) velocity errors in variable-speed depth conversion; (3) horizon calibration; and (4) vertical resolution of seismic exploration. The absolute error of well–seismic depth is related to the magnitude of the longitudinal resolution wavelength λ in seismic exploration. Therefore, based on the wavelength theory of vertical resolution in seismic exploration, and targeted at various exploration stages (exploration, appraisal, development, and fine development) of oil fields, different fractional values of seismic wavelength (λ_n and K_λn) can be taken as important reference indicators for the absolute and relative errors of well–seismic depth, which is operable in practice and can be used as a reference for oil field managers to assess the accuracy of seismic interpreted structure results.

Changqing Oilfield’s tight oil production construction has a long history and a large scale, and it remains a key focus in oilfield production and construction, with new production capacity accounting for 36.6%. Targeting the geological characteristics of tight oil, with the goal of achieving the best adaptation between well patterns and fracture networks, an integrated geological engineering research approach is employed. Through methods such as numerical simulation, big data analysis, and field practice, fracturing optimization design is carried out, resulting in the formation of precise segmented fracturing technology for short horizontal wells with coiled tubing. The integrated technology package includes key technologies such as “optimization of fracturing timing, differential fracture design, precise fracture control, enhanced imbibition oil displacement, multi-stage temporary plugging within fractures, and directional perforation.” This technical model has been implemented in over 200 wells in the Changqing Oilfield’s tight oil reservoirs, significantly improving the degree of horizontal well fracture control and oil production. Microseismic monitoring results show that the degree of fracture control has increased from 60% to over 85%, and the initial production of a 100-meter horizontal section has increased from 1.5 t/d to 3.2 t/d. Single well production remains stable, reaching an annual production rate of 3.0 t/d, with overall good results. The fracturing key technologies developed from this research effectively support the efficient development of tight oil in the Ordos Basin and provide direction for the next phase of technical breakthroughs. The insights gained offer references and lessons for the large-scale and efficient development of similar oilfields in China.

The reservoir buried depth in HT1 well area in Hutubi area is relatively deep, low porosity, low permeability and dense. The fracture propagation law under the condition of high temperature, high pressure and natural fracture development is not clear, which poses challenges for fracturing construction. To solve this problem, the core of the target layer is subjected to triaxial compression experiment under high temperature and high pressure, and the elastic modulus, Poisson ratio and other parameters are obtained. Based on the 3D geological model, a 3D geomechanical model is established to simulate the diagenetic environment of the block by using the relevant experimental data, core data, well logging data and seismic interpretation. Finally, under the constraints of the geomechanical model, the fracturing extension simulation, construction parameter optimization design, production history fitting and prediction of vertical well considering natural fractures are carried out. The results show that: ① The average value of Young’s modulus in the target block is 37.5GPa, the average value of Poisson’s ratio is 0.25, the average value of maximum horizontal principal stress is 220MPa, the average value of minimum horizontal principal stress is 180MPa, The maximum and minimum horizontal principal stress values are much higher than those of conventional gas reservoirs (generally less than 100MPa). ② Based on the inversion of the fracture parameters based on the pressure drop of the shut down pump, the length of the compression fracture is fitted by setting the parameter length of the small scale atural fracture 70m and the interval 150m. ③ Discharge rate of 8~9m³/min, perforation length of 8m, liquid volume of 910m³ and sand ratio of 10%~16% are the optimal construction parameters. ④ Under fracturing operation, the stable production time is extended by 8 years, the cumulative gas production increases by 16.13×10⁸m³, and the fracturing effect is significantly improved, which provides guidance for the development of related blocks.