In the deep-ultra-deep area of the Sichuan Basin, Anyue and Penglai gas fields have been discovered, with reserves exceeding 100 trillion cubic meters, making them two super-large gas fields in Sinian-Cambrian system. In order to find their replacements, it is urgent to clarify the main controlling factors of their accumulation. Based on the previous studies, a systematic study on the gas genesis and the main controlling factors of the Anyue and Penglai gas fields was conducted by using geological and geochemical data. The research concludes that the formation of deep-ultra-deep super-large gas fields is mainly controlled by four main controlling factors: （1）The development of two intracontinental rifts, namely the Deyang-Anyue and Wanyuan-Dazhou rifts, during the Late Sinian to Early Cambrian periods, which controlled the formation of high-quality main source rocks in the Lower Cambrian. The thickness of source rocks in these rifts is three to four times that of adjacent areas, and their gas generation intensity is two to three times higher.（2）The development of the Anyue-Fengjie shelf margin platform during the Late Sinian to Early Cambrian periods, which controlled the formation of four high-quality reservoirs: the second and fourth members of the Dengying Formation of the Sinian System and the lower member of the Canglangpu Formation and the Longwangmiao Formation of the Cambrian System. The reservoirs in the shelf margin zone are thick and have good storage properties. （3）The long-term inheritance of the Gaoshitiji-Moxi giant paleo-uplift formed during the Tongwanian period, which controlled the formation of large structural and lithologic traps in the core of the paleo-uplift and lithologic traps in the slope area. The areas of the Dengying Formation traps in the core and slope of the paleo-uplift are 7500 km² and 5720 km², respectively. （4）The in-situ cracking of large ancient oil reservoirs to form gas fields, with high accumulation efficiency. A large number of liquid hydrocarbon inclusions were found in different host minerals, with abundances ranging from 10% to 80%. The content of reservoir bitumen in the gas-rich areas is high, mainly ranging from 1% to 8%.Based on the factors such as the platform margin shoals and the platform interior shoals, the scale of source rocks, the structure of the target layer and the exploration degree, as well as the geological conditions that the study area has the potential for three-dimensional hydrocarbon accumulation and multiple enrichment, three types of favorable areas for the formation of large and super-large gas fields are evaluated. The first type of area is the development zone of the platform margin shoals and the platform interior shoals where the Anyue and Penglai gas fields have been discovered, namely the Anyue-Penglai zone. The second type of area is the development zones of the platform margin shoals and the platform interior shoals where breakthroughs have been made or which have the potential for large-scale exploration, such as Hongya-Leshan, Yilong-Guangyuan, Rongchang-Gulin, Bazhong-Dazhou, and Shizhu-Lichuan. The third type of area is the development zones of the platform interior shoals, such as Chongqing-Liangping and Weiyuan-Luzhou.The research results have significant implications for deep and ultra-deep oil and gas exploration.

The high-efficiency exploration is key initiatives to establish independent and controllable overseas core oil and gas production zone, and promote the high-quality development of overseas oil and gas business. In response to the four major characteristics of overseas exploration, such as restrictions, risks, economy, and internationalization, CNPC has researched and formed the “1435” high-efficiency exploration system in recent years. “1” represents the goal of creating world-class value creation of overseas exploration. “4” refers to four sets of management systems characterized by “unified management and centralized decision-making”, including business management, risk exploration, whole lifecycle engineering, and collaborative innovation. “3” refers to evaluation work in three aspects of exploration targets,single exploration project, and full cycle exploration. “5” refers to five major projects of “mountain area exploration” technology, risk exploration, centralized exploration, fine exploration, and rolling exploration. As a result, significant achievements have been made in four aspects, i.e., fields without breakthrough for long periods, exploration in new areas and new fields, expanding reserve scale in mature areas,and increasing reserves and production in old areas, discovering two world-class one-billion-ton level oil fields, a trillion-cubic-meter level large natural gas zone, one 500-million-ton level oil field group, and 10 high-quality reserve areas, which effectively support the beneficial and steady production of 100-million-ton equity production and further consolidate the resource foundation for high-quality development of overseas oil and gas business. The “1435” high-efficiency exploration system will provide solid support for China’s oil companies to continuously enhance their global resource control and ensure the national energy security.

The fourth member of Xujiahe Formation in Jianyang Block of Tianfu Gas Field is an emerging area for increasing reserves and production of near-source tight gas in Sichuan Basin, and the study of its reservoir characteristics and main controlling factors is very important. In this study, the basic characteristics and classification of reservoirs are discussed in detail by means of casting thin slice, particle size analysis, whole rock, scanning electron microscope and high-pressure mercury intrusion, and the main controlling factors of reservoir development and evolution are systematically analyzed in many aspects. The delta-lake sedimentary system is mainly developed in Xu 4 member of Jianyang Block, and the high-quality reservoirs are mainly concentrated in the microfacies of underwater diversion channel at the delta front. The reservoir lithology is mainly lithic feldspar sandstone and feldspar lithic sandstone, among which intragranular and intergranular dissolved pores develop frequently. The porosity of the reservoir is mainly distributed between 6 and 8%, and the permeability is between 0.05 mD and 0.3 mD. Based on the comprehensive sedimentary facies belt, reservoir characteristics and fracture development degree, the classification evaluation standard of Class Ⅰ-Ⅳ tight sandstone reservoirs in the fourth member of Xu Formation is established, and the study area is dominated by Class Ⅱ fracture-pore reservoirs. The microfacies of underwater diversion channel and estuary dam lay the foundation for reservoir development, and the intragranular (intergranular) dissolved pores formed by feldspar and cuttings during hydrocarbon generation and acid drainage period are the key to the development of high-quality reservoirs, and structural fractures are an important supplement to reservoirs. The main exploration direction of tight gas is the underwater diversion channel and estuary bar sand body in the delta front with good source-reservoir configuration, developed structural faults and improved fault activity in the foreland slope zone.

In order to reveal the pore development characteristics and controlling factors of lacustrine carbonate reservoir in the Qianjiang Formation in Qianjiang Sag, Jianghan Basin, the rock lithofacies and reservoir physical properties were systematically studied by means of XRD, thin section, porosity, and high-pressure mercury injection, taking the third member of the typical well system as the research object. The results show that: (1) eight rock types were identified: granular carbonate, micrite carbonate, granular mixed stone, fine grained mixed stone, felsic-rich clastic rock, clay-rich shale, sulphate rock, and salt rock. (2) Four major lithofacies assemblages are formed, which are felsic-rich clastic rock and shale lithofacies assemblage from north to south, granular and fine-grained mixed lithofacies with shale lithofacies assemblage,grain carbonate rock and mudstone carbonate rock intercalation shale facies association, salt rock intercalation shale lithofacies association. (3) Total porosity across different rock types is comparable, averaging between 5.5% and 7.3%, but pore sizes vary significantly. Granular carbonate and felsic-rich clastic rock exhibit larger pore sizes, with high-pressure mercury intrusion revealing an average pore volume ratio of >10% and average throat radius >140 nm for micron-sized pores; in contrast, micrite carbonate and fine-grained mixed rocks have smaller throats, with pore volume ratios <5% and average throat radius <10 nm. It is pointed out that granular carbonate rock and felsic-rich clastic rock have great reservoir property and large pore size, which is conducive to the accumulation, seepage, and production of hydrocarbons. They are the beneficial lithofacies types in carbonate reservoir, and are also the most favorable targets for shale oil exploration in the study area.

The exploration practice indicates that the reservoir sedimentary characteristics are the key factors affecting the oil and gas production of the pre-salt lacustrine carbonate rocks in the Santos Basin. The high-quality reservoirs are mainly microbial reefs and shoal carbonate rocks deposited on the palaeo-uplifts. Based on the structural analysis of seismic data and gravity data, this paper redefined the presalt structural units of the Santos basin and the distribution of palaeo-uplifts. The basin was divided into five first-order tectonic units, in which the outer uplift zone is developed from the abandoned Ocean Ridge after the transition during breakup of the Atlantic, which is very conducive to the development of microbial reefs. Based on drilling and seismic data, this paper carried out the series research about the core facieslogging facies-seismic facies-sedimentary facies. Then combined with the structural characteristics during rift period and the paleogeography during sag period, the pre-salt sedimentary facies distribution of sag period was determined, and four sedimentary models of the highquality carbonate reservoir was established, including the large gentle slope sedimentary model, the isolated platform sedimentary model, the inner highland sedimentary model and the steep slope sedimentary model. The large gentle slope and the steep slope sedimentary model are controlled by monoclinal fault blocks, and the inner highland sedimentary model is controlled by fault-uplift structures, which are mainly distributed in the outer uplift zone. The isolated platform sedimentary model is controlled by horsts, which are mainly distributed in the central depression belt and the outer depression belt.

The second member of the Lucaogou Formation in the Tiaohu and Malang Sags of the Santanghu Basin was primarily sourced from fallout volcanic ash and endogenous carbonates during its depositional period. This unique setting has resulted in a highly complex formation mechanism for high-quality fine-grained rock reservoirs. Based on petrographic and geochemical data, a systematic study was conducted on the sedimentary characteristics and diagenetic processes of fine-grained rocks in the second member of the Lucaogou Formation.The results indicate that lithology has a minimal control over the petrophysical properties, pore structure, and fluid mobility of the finegrained rocks. Regardless of lithology, high-quality reservoirs can form during diagenesis. Except for dolomite, other fine-grained lithologies are generally rich in organic matter. Cyanobacteria predominantly develop in tuff and dolomitic tuff, while green algae are observed in tuff, dolomitic tuff, and tuffaceous dolomite. The widespread organic matter underwent significant hydrocarbon generation during the Middle Diagenetic Stage A, which not only altered the diagenetic environment but also effectively and extensively dissolved soluble minerals within the fine-grained rock reservoirs. Compaction is identified as the primary factor leading to the densification of fine-grained rocks in the second member of the Lucaogou Formation, whereas cementation has a relatively minor impact on reservoir quality. Dissolution is the key mechanism for forming high-quality tuff reservoirs, while dolomitization and its multiple phases have significantly enhanced the storage capacity of dolomite reservoirs. Based on the intensity of dissolution and dolomitization, the diagenetic phases of fine-grained rocks in the second member of the Lucaogou Formation were classified into five types. Among them, the strongly dissolved-weakly dolomitized phase and the moderately dissolved-moderately dolomitized phase are the most favorable. Using the random forest method in matlab, single-well predictions of diagenetic phases were conducted to determine their distribution. The findings not only provide valuable insights into identifying favorable facies zones for shale oil exploration in the second member of the Lucaogou Formation but also contribute to understanding the formation mechanisms of high-quality fine-grained rock reservoirs under this unique sedimentary background.

The carbonate reservoirs in the 4^th member of Penglai gas field in the Sichuan Basin represent one of the key targets of China’s onshore oil reserve expansion and production enhancement during China’s 14^th Five-Year Plan period. Characterized by ancient age, deep burial, and strong heterogeneity, their spatial distribution remains challenging to predict. Focusing on the geological, drilling, logging and seismic characteristics of db1 block within the gas field, this study establishes a well-seismic integrated classification and prediction technology for deep carbonate reservoirs. The approach aims to (1) analyze reservoir formation characteristics and distribution patterns, (2) implement inversion and prediction of heterogeneous reservoir distribution, and (3) delineate the spatial heterogeneity of reservoirs. The results indicate:(1) Reservoirs in the Penglai Gas Field are concentrated in the upper sub-member of 4th Member of the Dengying Formation, exhibiting three architectural models: (i) dual upper and lower reservoirs, (ii) locally distributed upper reservoirs with well-developed lower reservoirs, and (iii) a single developed reservoir. (2) “Good” and “Medium” reservoirs in the study area are thin and sporadically distributed, while “Bad” reservoirs exhibit greater thickness and better vertical-lateral continuity, primarily distributed near wells ps106, db1, ps11, and adjacent regions. (3) The successful classification and distribution prediction of deep carbonate reservoirs in this area, not only validate the applicability and reliability of the proposed technology, but also provide valuable references for reservoir prediction in the Penglai Gas Field and analogous fields.

The Huagang Formation is a shallow-water delta depositional system in the middle and south of Xihu sag, East China Sea shelf basin. It is difficult to predict the reservoir because of the large buried depth of the main exploration target layer, the similar impedance of sandstone and mudstone, complex relationship between channel stages and overlaying. To solve this problem, through detailed dissection of the Shuey approximate gradient term of Zoeppritz equation, combined with seismic forward analysis, it is clear that AVO gradient is related to Poisson’s ratio, and it is the most sensitive and stable to reservoir response. Using AVO gradient to finely delineate channel boundary, a total of four distributary channels are identified in H5 layer. Channel 1 and 4 are NW-SE trending, with the average width, width-to-thickness ratio and curvature are 0.7km and 0.8km, 29 and 28, 1.04 and 1.06, respectively. Channel 2 and 3 are NE-SW trending, with average width, widthto- thickness ratio and curvature are 0.85km and 3.1km, 26 and 70, 1.40 and 1.09, respectively. The channel stages are divided into channel 1, channel 2, channel 3 and channel 4 from early to late by the sequence stratigraphy and relative isochronous surface flattening method. It is considered that the four channels of H5 layer are not connected and have the conditions for independent hydrocarbon accumulation according to cross-validation analysis of seismic response characteristics of different channels and possible gas bearing flat points and other multi information. Establish a “fault-sand coupling” hydrocarbon accumulation mode for anticlinal wings lithologic traps. It is considered that the anticlinal wings have better hydrocarbon accumulation conditions than the core. Based on the above understanding, exploration wells were drilled in the channel 4 of structure A and the channel 3 of structure B, both obtained good lithology exploration results for the first time in the study area, which proved the practicability and reliability of the research technique and method, and pointed out the next favorable exploration area.

Currently, there are numerous methods for evaluating rock brittleness index, mainly based on mineral composition or rock mechanical properties evaluation, but most of these evaluation indicators are costly to obtain and time-consuming. By utilizing machine learning techniques, a rock brittleness index prediction method based on the Stacking ensemble learning concept is proposed. This method involves parallel training of Gradient Boosting Decision Tree model (GBDT), Random Forest model (RF), Naive Decision Tree model (DT),Support Vector Regression model (SVR), and LightGBM model. After hyperparameter tuning using a tree-structured Parzen estimator for each model, the XGBoost model is sequentially used to merge the training results of the base models to achieve rapid parameter optimization and prediction of rock brittleness index. The results indicate that the two-layer Stacking model optimized with the tree-structured Parzen estimator shows significant advantages compared to the predictions of the base models. The explained variance score (EVS) reaches up to 0.97, and the coefficient of determination (R²) reaches a maximum of 0.967. In the same dataset performance comparison, this model exhibits the lowest Mean Absolute Error (MAE) and Root Mean Square Error (RMSE), implying that this model can effectively capture the variation patterns of rock brittleness index under the supervised learning framework. This verifies its practical value in predicting rock brittleness index.

The Ordos Basin Qingcheng shale oil reservoir has strong lateral and vertical anisotropy, low natural fracture development, and large two-direction horizontal stress difference. The preliminary microseismic recognition indicates that the double-wing feature is obvious,and the fracture morphology is relatively simple. In order to further understand the post-fracturing fracture network morphology and spatial distribution, a coring study was conducted in the Qingcheng shale oil hydraulic fracturing test site using high inclination well between fracturing wells. Through CT scanning, manual observation, microscopic imaging, and well logging responses, the fine-grained description of fracture dip, fracture surface morphology, filling characteristics, etc. was carried out, and the fractures were classified and identified. At the same time, the dye proppant, mud tracer, and spatial distance and distribution law were combined to perform corresponding regression and comprehensive analysis on the hydraulic fractures. The research results show that there are differences in the characteristics of different types of fractures, with a low proportion of natural structural fractures and a high proportion of bedding fractures and hydraulic fractures.The hydraulic fractures are characterized by swarm features, with a much higher number than the corresponding stages of adjacent hydraulic fracturing well, and there are local differences in extension, but they still extend along the principal stress direction under the influence of stress difference and orientation. There is less obvious propped fractures, but the proppant is widely distributed in cuttings and the proportion of small particle size is higher. The tracer analysis shows that the number of hydraulic fractures corresponding to each stage is the key to oil production contribution. The fracture recognition, classification, and regression method obtained by integrating multiple methods can be referenced for other unconventional oil and gas reservoir post-fracturing coring analysis, and the fracture understanding obtained has certain guiding significance for the next step of fracturing optimization.

The deep coal seam reservoirs are characterized by ultra-low permeability, well-developed micropores, but poor connectivity, and
great difficulty in reservoir reconstruction. In order to deepen the understanding of reservoir stimulation mechanism of No.8+9 deep coal seams in the eastern margin of Ordos Basin and to provide guidance for the subsequent fracturing construction, a hybrid model with two-stage synergistic architecture has been proposed, and the characteristics of fracturing construction curves of No.8+9 deep coal seams and sand-coal stacked layers have systematically been analyzed, which reveals the influence mechanism of parameters such as sand addition amount, number of stages, and perforation technology on the fluctuation of construction pressure, and clarifies the production capacity of vertical and directional wells with various fracturing parameters. In addition, the targeted fracturing technology has been put forward and applied to field practice. The study results show that the “TSLANet–Kmeans++ (DTW)” hybrid model has the best performance under various classification conditions, and it has the best discrimination when classifying fracturing curve of deep coal seams into four types, i.e., pressure plateau after high pressure fracturing, steadily pressure rising, steady pressure decline, and difficult sand addition, with the accuracy of the model reaching up to 92.7%. The staged plugging technology and pre-pad fluid volume have a great influence on fracturing pressure. For wells with high rock breaking pressure peaks, multi-stage plugging, high pre-pad fluid ratio and low viscous fluid ratio can be used to reduce risks of fracturing complex caused by high fracturing pressure. The main controlling factors for well production capacity include liquid volume, sand addition amount, displacement, and sand ratio. It is beneficial for enhancing well production capacity by fracturing with less water, controlling liquid volume, increasing sand–liquid ratio, and increasing displacement. A composite fracturing and reconstruction technology for deep coal seams with the core idea of “repeatable low-damage fracturing fluid + multi-stage plugging + high displacement + temporary plugging at the fracture opening end” has been proposed and successfully been applied in wells A-18 and B-4H, with a steady single well gas rate exceeding 10×10⁴ m³/d, which provides theoretical basis and technical support for the high-efficiency development of deep CBM in Ordos Basin.

The comprehensive evaluation of sweet spots requires consideration of both geological and engineering factors in shale oil reservoirs. This paper proposes a fractal characteristic-based method using conventional logging curves to assess integrated sweet spots in fractured horizontal wells within shale oil reservoirs. Taking the Chaiping 2 and Chaiping 4 fractured horizontal wells within the sweet spot zones of the Yingxiongling shale oil reservoir in Qinghai Oilfield as case studies, we extracted fractal characteristic parameters from conventional well-logging data. By integrating post-fracturing production profile monitoring and employing gray relational analysis, weighted multifractal spectrum width (Δα') and weighted fractal dimension (D') were introduced to establish a tripartite productivity evaluation criterion based on fractal characterization. The results show that the comprehensive fractal evaluation index of the high-yield well section after Class I layering is 0.75<Δ α '<1, 0