Based on the post-frac core evaluation results for shale gas reservoirs in the Jiaoshiba block of the Fuling gas field, a simulation method for tensile-shear composite fracture networks and a multi-scale characterization method for residual gas were developed. The types and distribution characteristics of residual shale gas were clarified, and an efficient flow field with coordinated “artificial well pattern-induced fracture network-natural fracture network” was established. Strategies for residual gas recovery was proposed, and the expected technologies for efficient development of shale gas reservoirs were recommended. The induced fractures in shale exhibit features such as single overall morphology, clustered non-uniform distribution, branching dendritic extension, and limited propped area. Residual gas can be classified into four types: gas uncontrolled by well pattern, gas insufficiently swept by inter-well fractures, gas unevenly swept by inter-layer fractures, and gas unswept between clusters. For purpose of residual gas recovery and enhanced gas recovery, an efficient flow field with coordinated “artificial well pattern-induced fracture network-natural fracture network” can be constructed through drilling infill wells, sidetracking in old wells, differential trajectory design, and precision fracturing design. Future efficient development of shale gas is expected to be achieved by improving accurate reservoir characterization, advancing coordinated 3D development technologies, iteratively optimizing technologies for enhanced shale gas recovery, and deepening the synergy between conventional and unconventional development methods. These efforts are believed to drive high-quality advancement of China’s shale gas development technology.

The whole petroleum system (WPS) theory represents a significant innovation proposed to address the limitations of the classical petroleum system theory. The successful application of this theory has propelled China's oil and gas exploration toward a new paradigm characterized by “all stratigraphic sequences, all resource types, and all exploration domains.” Based on a review of the fundamental principles of this theory, this study provides a comprehensive analysis of 25 relevant cases from 12 basins in China. It is indicated that there exists an orderly distribution of three fluid dynamic fields in a whole petroleum system, i.e., free dynamic field, restricted dynamic field and confined dynamic field. Hydrocarbon accumulation in a restricted dynamic field primarily relies on capillary force and viscous force; however, long-term effectiveness still depends on sealing capacity and regional boundary conditions. The superposition of hydrocarbon generation from source rocks with different kerogen types or lithologies results in a broader hydrocarbon generation window, and earlier and longer hydrocarbon generation, than the traditional Tissot model, demonstrating a whole-process hydrocarbon generation across all kerogen types. The distribution and physical properties of reservoirs are generally controlled by sedimentary facies and diagensis. From basin margin to sag center, sediment grains generally present reservoir-forming features of all facies belts and all grain-size grades. A typical whole petroleum system generally follows a full-sequence, three-dimensional accumulation pattern described as “three zones laterally, three layers vertically”. Laterally, along the basin margin → slope area → sag center, conventional oil and gas reservoirs, tight oil and gas reservoirs, and shale oil and gas reservoirs develop sequentially corresponding to the intervals of major source rocks. Vertically, in addition to shale/coal-rock oil and gas reservoirs within these intervals, tight/conventional reservoirs are also found above and below the source beds. Within the accumulation framework of the whole petroleum system, underexplored areas that have not yet achieved breakthroughs represent important potential domains for future oil and gas discoveries.

Based on the molecular structure transitions, hydrocarbon composition, and reservoir characteristics changes during coal evolution, combined with the production characteristics of coalbed methane/coal-rock gas, the generation stages and accumulation types of coalbed methane/coal-rock gas are discussed. The generation of coalbed methane/coal-rock gas can be divided into five stages: low-coal-rank biogenic gas generation stage (R_o < 0.5%), mid-coal-rank transitional gas generation stage (0.5% ≤ R_o < 0.8%), mid-coal- rank mature gas generation stage (0.8% ≤ R_o < 1.3%), mid-coal-rank high-maturity gas generation stage (1.3% ≤ R_o < 2.0%), and high-coal-rank overmature gas generation stage (R_o ≥ 2.0%). Based on the burial depth and genesis, coalbed methane/coal-rock gas is divided into three types: shallow coalbed methane, deep coal-rock gas, and exogenous coal-rock gas. By the hydrocarbon generation evolution stage of coal rock, deep coal-rock gas is further classified into: mid-coal-rank low-maturity coal-rock gas, mid-coal-rank mature coal-rock gas, mid-coal-rank high-maturity coal-rock gas, and high-coal-rank overmature coal-rock gas. Coalbed methane→coal-rock gas represents a complete dynamic evolution sequence from shallow to deep. Coals reflect a hydrocarbon generation evolution sequence of “biogenic gas→transitional gas→wet gas→dry gas”, and reservoirs undergo a formation process of “primary pores→cleat development→peak organic matter pores→densification and fracturing + fracture opening”. The occurrence state gradually shifts from “absolute dominance of adsorbed gas” to “continuous increase in free gas proportion”, and the development modes also transform from “long-term drainage and depressurization for desorption” to “high gas production upon well opening”. In addition, exogenous coal-rock gas refers to the natural gas from external sources, especially in the underlying strata. This type of coal-rock gas corresponds to low-rank coals with reservoir properties, where gas was accumulated under the control of tectonics, and free gas takes a high proprotion. A high initial production has been observed.

Aiming at the problems of the poor understanding of enrichment factors, unclear exploration targets, and challenging selection of favorable areas for medium- and low-rank coal-rock gas (coalbed methane) resources in Xinjiang, this paper, based on the coal-measure whole petroleum system theory, examines the main controlling factors of coal rock gas (coalbed methane) enrichment and further discusses the exploration targets and favorable areas, through extensive coal petrology and coal quality analysis, gas content measurements, and well-seismic data interpretation. The study shows that the insufficient thermal evolution, with vitrinite reflectance (R_o) commonly below 0.8%, is the primary factor responsible for the marked discrepancy between actual gas content and hydrocarbon generation potential in basins such as the Junggar Basin. In addition, the coal-forming age and maceral composition characteristics also exert important controls on gas content. Accordingly, two exploration strategies are proposed: seeking relatively higher coal ranks and elevated geothermal gradients, and targeting older (especially Paleozoic) coal-measure strata. Further, five major exploration targets are identified: (1) post-coalification high geothermal gradient zone; (2) early deep burial and late uplift tectonic belt; (3) Upper Paleozoic coal measures with high thermal maturity; (4) coal seams with high vitrinite content; and (5) coordinated development area of the coal-measure whole petroleum system. Depending on the distribution of coal-measure strata, structural characteristics, and coal rock properties of various basins in Xinjiang, three practical exploration areas are defined: the southern piedmont structural belt and stable central region of the Junggar Basin, the Wenjisang structural belt and the Hongtai slope of the Tuha Basin, and the northern Kuqa structural belt of the Tarim Basin. Additionally, six peripheral strategic replacement areas are identified: Heshituoluogai, Yili, Yanqi, Santanghu, Kupu, and Fujin Basins. The study provides a scientific basis for selecting favorable zones to advance the effective exploration and large-scale development of coal-rock gas (coalbed methane) resources in Xinjiang.

This paper systematically reviews the development stages and status of key oil production engineering domains, including injection-production engineering, artificial lift, reservoir stimulation, and workover operations. On this basis, the major challenges for oil production engineering are identified in four aspects: intelligent endpoint devices and process integration, extreme-environment operations, and collaborative operational constraints; AI-driven data and modeling complexities, and advanced structural and functional material requirements; and the need for geoscience-engineering integration in reservoir characterization, operational efficiency, and green development. Centered on multidisciplinary integration, the concept of the Oil Production Engineering Agent is introduced as a miniaturized, intelligent, integrated hardware-software system designed for extreme downhole environments, incorporating power supply, communication, sensing, computation, and actuation modules to enable environmental perception, autonomous decision-making, and adaptive control. The characteristics of various agent types, including those for injection-production, lift, fracturing, and workover, are analyzed, with key research directions identified in miniaturized self-powered energy management, reliable communication in high-interference environments, highly integrated multi-parameter sensing with long-term drift self-calibration, and high-reliability microsystem integration manufacturing. AI-driven decision optimization remains the core feature, requiring advances in data acquisition, governance, and fusion architectures, alongside algorithmic improvements in model performance and deployment compatibility. Additionally, advanced structural and functional materials support agent construction and extreme-environment adaptability, while geoscience-engineering integration continues to expand the functional scope of oil production engineering.

The temperature-pressure history of the organic-rich shale in the Cretaceous Qingshankou Formation in the northern Songliao Basin was reconstructed through comprehensive analyses, including field tests, paleo-heat flow recovery, overpressure evolution, and geochemistry. The formation and evolution process of the Gulong shale oil was reproduced, and its enrichment patterns were clarified. Because of tectonic thermal events and movements at the end of the Cretaceous Mingshui Formation deposition, the evolution of organic matter thermal maturity in the first member of Qingshankou Formation (Qing-1 Member) exhibited distinct stages, which can be divided into the Cretaceous rapid evolution stage and the Paleogene-Neogene slow evolution and stabilization stage. High paleogeotemperature drove secondary cracking of retained oil in the Qing-1 Member, forming light shale oil in the Gulong Sag. This sag experienced three phases of overpressure during the late Nenjiang Formation and late Mingshui Formation of the Cretaceous, and the Neogene. The first two phases were related to the oil generation peak and secondary cracking in the sag, respectively, while the third phase resulted from the inheritance of earlier overpressure, as well as sustained hydrocarbon cracking and heat-induced fluid volume expansion. Crude oil is distributed orderly in the northern Songliao Basin. Conventional oil reservoirs such as Saertu and Putaohua contain high contents of non-hydrocarbon compound, and they are believed to have formed by hydrocarbon charging as a result of the first phase of overpressure. Tight oils in the Fuyu and Gaotaizi reservoirs, most similar to shale oil in the Qing-1 Member in terms of composition and physical properties, are characterized by high content of saturated hydrocarbons, with their hydrocarbon charging and accumulation related to the second phase of overpressure. Paleo-heat flow impacted by tectothermal events is determined to be the main driving factor for the staged hydrocarbon generation of organic matter in the Qingshankou Formation. The Qingshankou shale with high thermal conductivity and the Nenjiang shale with low thermal conductivity constitutes a thermal structure with lower conducting and upper sealing. This structure has prolonged secondary cracking of hydrocarbons, widened the liquid hydrocarbon window, and helped self-sealing enrichment of the Gulong light shale oil by virtue of the third phase of overpressure.

Considering the complex occurrence environment and significant compositional variation of continental shale oil, as well as the uncertainties in its mobility and producible amount, this study employs geochemical analysis and production monitoring to investigate the “component flow” behavior of shale oil during production from the Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin. It is clarified that the miscibility of different hydrocarbon components and non-hydrocarbon substances improves the flowability of multi-component hydrocarbons and non-hydrocarbons, thereby effectively enhancing the production of mobile hydrocarbons from shale oil. Research indicates that the “lower sweet spot” has a relatively high content of light and medium hydrocarbon components and strong formation energy, resulting in higher density and viscosity of the produced crude oil, which can be regarded as evidence of “component flow” of retained hydrocarbons. The “upper sweet spot” exhibits two scenarios. In areas far from faults with good preservation conditions, the high content of light and medium components in retained hydrocarbons and a high formation pressure coefficient make component flow more likely to occur. Consequently, the produced crude oil has a higher specific gravity, and the estimated ultimate recovery (EUR) per well is also higher. In areas near faults with poor preservation conditions, although the produced crude oil has a light specific gravity, the EUR per well is relatively low, indicating that the conditions for component flow of retained hydrocarbons underground have deteriorated. The study also demonstrates that preservation conditions (preventing light hydrocarbon escape and maintaining formation energy) and production strategies (controlling production pressure differential and maintaining stable operations) are important factors in regulating the occurrence and continuity of “component flow” to maximize EUR per well. These new insights can be applied to the evaluation of economically productive “sweet spots” and provide guidance for achieving optimal EUR per well in shale oil production.

Given the stringent requirements for friction reducers in terms of long-distance friction reduction, efficient proppant transport, temperature resistance and viscosity enhancement in deep oil and gas fracturing development, an aqueous two-phase high-viscosity friction reducer ANSD-PADA suitable for deep reservoir fracturing was prepared by introducing nanomaterial ANSD and through the aqueous two-phase polymerization. Its mechanisms of temperature resistance, viscosity enhancement, and friction reduction were explored by means of fluorescence spectroscopy, microscopic morphology observation, nanomechanical testing and other analytical methods, and field tests were also carried out. The introduction of hydrophobic monomer N-(3-dimethylaminopropyl)methacrylamide enables PADA (a self-synthesized hydrophobic terpolymer) molecules to entangle, associate and self-assemble into a honeycomb-like network structure under the action of supramolecular forces including van der Waals force, electrostatic repulsion and hydrophobic interaction. This structure further increases the hydrodynamic volume, thereby significantly improving the viscosity-enhancing performance of the product. ANSD fills the pores of the polymer network structure, effectively strengthening the network skeleton and association junctions, and remarkably improving the temperature resistance of the system. The friction reducer retains a friction reduction rate of 73.36% at 130 °C, with a temperature resistance up to 150 °C, and it has demonstrated encouraging results in the pilot site at Well XX-HF targeting deep shale oil reservoirs on the northern slope zone of the Gaoyou Sag, Subei Basin, China.

Through systematic comparison of the geological characteristics, resource distribution, and exploration & development status of global marine and lacustrine shale oil, this paper deeply analyzes the key theoretical and technical issues that restrict the development of lacustrine shale oil in China. It points out that the basic theoretical research areas, such as the enrichment and accumulation mechanisms of shale oil with different lithological combinations, and the multi-scale and multiphase flow mechanisms in nanoscale confined spaces, are relatively weak; the accuracy of sweet spot prediction cannot effectively guide the selection of target layers and the positioning of horizontal well trajectories, and there are fewer geology-engineering integration practices. All these factors severely restrict the large-scale utilization of shale oil resources. Focusing on the progress in the study of lacustrine shale oil in the Songliao Basin, Ordos Basin, Junggar Basin, and Bohai Bay Basin, this paper systematically analyzes six bottleneck issues (genetic models of fine-grained sedimentary rocks, types and distribution of hydrocarbon-generating organic matter, hydrocarbon generation-expulsion models and potential, types and performance of reservoir spaces, parameter selection and evaluation techniques for of sweet spots, and productivity laws and enhanced oil recovery), progress in theoretical and technological research, examples, and directions for tackling key issues. It identifies six major challenges confronting China’s shale oil revolution: hydrocarbon accumulation mechanisms, sweet spot identification, seepage law, fracturing modification, drainage and production technology, and recovery enhancement. To address these, the study proposes to establish a shale oil classification scheme based on source-reservoir configuration, to promote the refined development model of “geology-engineering-geology spiral integration”, and build an efficient shale oil development technology system tailored to China’s continental geological conditions, providing theoretical and technical support for achieving large-scale and beneficial development.

To address the challenges of connectivity characterization, dynamic prediction efficiency, and real-time optimization in complex reservoir injection-production systems, this study proposes a physics- and deep learning-integrated intelligent injection-production modeling framework based on the graph connection element method. The method adopts the connection element method as the physical foundation and constructs a non-Euclidean graph representation to describe interwell connectivity, enabling characterization of the physical topology and dynamic interactions within the well pattern system. By incorporating an adaptive attention mechanism into a graph convolutional network and embedding time-dependent node attributes, a physics-consistent reservoir performance prediction model is developed. Furthermore, a hybrid optimization strategy integrating differential evolution and particle swarm optimization is employed to establish an economically constrained intelligent optimization framework. Based on rapid prediction of injection and production behaviors, the proposed approach enables optimization of operational parameters and maximization of exploitation economics. Field applications demonstrate that the proposed intelligent injection-production model based on graph connection element accurately reproduces water-cut behavior of producers and provides quantitative uncertainty estimation. It achieves rapid history matching and dynamic response forecasting for complex reservoir injection-production systems, exhibiting high accuracy and stability. Moreover, it enables global optimization of production strategies under economic constraints, demonstrating strong engineering applicability and scalability.

Global deep Earth exploration and ultra-deep oil and gas exploration (below 6 000 m) have attracted increasing attention, with a growing number of major oil and gas discoveries. This article systematically reviews the discovery history of ultra-deep oil and gas exploration since 1937, dividing it into four major stages: onshore ultra-deep exploration and local breakthrough (1937-1982), shallow- water-dominated ultra-deep exploration and sporadic discoveries (1983-1997), onshore and offshore large-scale ultra-deep discoveries (1998-2018), and onshore extra-deep exploration and new breakthrough (since 2019). By the end of 2025, a total of 1 348 exploratory wells with a depth of more than 6 000 m have been drilled worldwide. A total of 305 ultra-deep oil and gas fields have been discovered in 29 basins across 20 countries, with recoverable reserves equivalent to 63.21×10⁸ t, accounting for only 0.9% of the global total reserves and indicating enormous exploration potential. The discovered resources are highly concentrated in the Tethys and South Gondwana petroleum domains, dominated by passive continental margin basins with a proportion of 71.25%. Reservoirs are mainly composed of Meso-Cenozoic carbonate rocks and clastic rocks. Studies show that three types of advantageous basins, including cratonic basins, passive continental margin basins and foreland basins, have their own characteristics in terms of basin formation, hydrocarbon generation, reservoir formation and hydrocarbon accumulation. The global ultra-deep oil and gas exploration degree is extremely low, and there may exist another “golden zone” for hydrocarbon accumulation with huge resource potential. In the future, it is necessary to strengthen research on the mechanisms of hydrocarbon generation and accumulation as well as resource assessment in ultra-deep strata, and carry out integrated evaluation combining geology, engineering and intelligent technology. Internationally, efforts should be focused on new ultra-deep project evaluation and oil and gas cooperation in hydrocarbon-rich regions such as the two sides of the Atlantic, the Middle East, Central Asia-Russia and Australia. With the accelerated exploration of extra-deep oil and gas in China, a new peak of reserve growth is forthcoming.

Based on China’s latest exploration and development achievements, production performance data of over 7 000 horizontal wells, and the Unconventional Oil & Gas Digital-Intelligent Platform (UOG), and by integrating statistical analysis and machine learning prediction techniques, this study systematically compares four types of unconventional natural gas (tight gas, shale gas, shallow coalbed methane, and medium-deep coal-rock gas) in the country, from the aspects of resource characteristics, key technologies, development indicators, and prospects. The results show that China holds a substantial quantity of unconventional natural gas, especially shale gas and medium-deep coal-rock gas which boast prominent resource advantages and present a large-scale “continuous” spatial distribution. More than 75% of high-quality resources are concentrated in the Ordos and Sichuan Basins. A type-adaptive key technical system has been established, incoprating extensive recovery of tight gas by virtue of “well pattern optimization + low-cost fracturing”, commercial development of shale gas relying on “geological-engineering dual sweet spot evaluation + super fracture network fracturing”, stable production of shallow-medium coalbed methane through “precision drainage and depressurization”, and breakthroughs in pilot technologies such as pressure-controlled development and energy-gathered fracturing for horizontal wells of medium-deep coal-rock gas. The four types of unconventional natural gas vary significantly in development indicators. Tight gas, shale gas and medium-deep coal-rock gas reach peak production 10-30 days after gas breakthrough, showing the characteristics of high initial production followed by rapid decline (with a first-year decline rate of 30%-51%). Specfically, shale gas horizontal wells have the highest average daily production in the first year (7.28×10⁴ m³/d) and single-well EUR (8 255×10⁴ m³). Shallow coalbed methane reaches peak production about 240 days after gas breakthrough, presenting a trend of slow rise-gentle decline, with the lowest single-well indicators. At present, the development of unconventional natural gas is faced with four major constraints including complex geology, technical bottlenecks, environmental restrictions and imperfect policies. Thus, it is necessary to address the predicament through multi-dimensional coordination in terms of resources, technology, environmental protection, and policies.

To accurately evaluate the storage capacity of shale oil reservoirs under in-situ temperature and pressure conditions, we constructed a new model for determining the porosity under formation conditions, developed a HTHP shale porosity measurement system capable of operating at an overburden pressure of 70 MPa, a pore-fluid pressure of 40 MPa, and a temperature of 120°C, and established an integrated workflow for restoring in-situ porosity in clay-rich lacustrine shale oil reservoirs. This technology system was applied to the Upper Cretaceous Gulong shales in the Songliao Basin. The results show that the in-situ porosity in shale oil reservoirs is consistently higher than that measured at normal pressure on surface. The restored porosity increases by 3.17-4.00 percentage points for ordinary shale, 1.58-1.60 percentage points for silty shale, and 1.12-1.58 percentage points for carbonates. The restored porosity increase grows regularly with burial depth, temperature, pore pressure, and pressure coefficient, reflecting the elastic dilation of clay- and organic-associated nanopores and the widening of overpressure-supported microfractures in the Gulong shales. Core depressurization was found to collapse these pressure-supported pores, causing conventional helium and surface NMR measurements to systematically underestimate storage capacity, particularly in deep, clay-rich, overpressured intervals. For reserve estimation, use of ambient-condition porosity may introduce significant underestimation of original oil in place (OOIP). For clay-rich Gulong shales, it is recommended to apply a correction factor of 3-4 percentage points to the surface-measured porosity (or surface porosity) for ordinary shale, and about 1.6 percentage points for silty shale, while only a minor correction is needed for carbonates. In-situ porosity should thus be incorporated into OOIP calculations and parameterized using clay content, TOC, pressure coefficient, and burial depth. Operationally, production from clay-rich, overpressured intervals should be implemented under controlled pressure, in order to avoid elastic closure of native microfractures and preserve reservoir deliverability.

Based on the core, cast thin section, CT, loggings, test and seismic data, the sedimentary-diagenetic characteristics and controls on favorable reservoirs in semi-restricted carbonate ramp setting were elucidated, through a case study of the Lower Cretaceous Yamama Formation in Oilfield A of the Central Arabian Basin. During the Early Cretaceous, the study area was a carbonate ramp in semi-restricted environment, where low- to medium-energy shallow-water lithofacies were common, and the depositional facies were dominated by large-scale lagoon, locally with grain shoal, point reef, back shoal and tidal flat. Bioclastics were diverse, with algae, benthic foraminifera, bivalve, bacinella, and peloids being the most abundant. The Yamama Formation in the study area underwent intense diagenesis during the penecontemporaneous stage, with cementation and dissolution coupled to control the formation and preservation of secondary pores. The reservoirs in the Yamama Formation are composed of packstone, wackstone and bindstone, indicative of frequently varying lithology with poor lateral correlatability. The reservoirs are porous, dominated by micropores, moldic pores, and skeletal pores, with a low abundance of primary intergranular pores, and the pore throats dominated by medium- and micro-throats. The physical properties generally exhibit low to medium porosity, and low to ultra-low permeability. The medium-high permeability reservoirs are underdeveloped. Favorable reservoirs in the Yamama Formation are controlled by local high-energy sedimentation, soluble bioclastic enrichment, intense dissolution, and abnormal-high pressure. Local high-energy grain shoals contain well-preserved primary intergranular pores with no intense cementation, forming small-scale favorable reservoirs. In contrast, low- to medium-energy facies such as lagoon and back shoal are locally rich in soluble bioclastics such as algae and bacinella. The bioclastics were intensely dissolved, forming a large number of moldic or skeletal pores, which effectively improved the reservoir physical properties, thus facilitating the formation of large-scale favorable reservoirs. The favorable reservoirs of Yamama Formation are mainly discovered in YA and YB sections, and large-scale reservoirs thereof are located in the central-northern part of the study area. These represent key targets for subsequent exploration and development.