Based on seismic data, well log data, and analyses of hydrocarbon accumulation elements in typical oil and gas fields, this study systematically investigates the tectonic differentiation and its control on hydrocarbon accumulation in four major Cenozoic petroliferous basins (Beibuwan, Pearl River Mouth, Qiongdongnan and Yinggehai) of the northern South China Sea. The results show that the tectonic evolution in the study area exhibits a significant differentiation characterized by “east-west staging and north-south zonation”, with major subsidence events occurred progressively later from west to east and from north to south, allowing the basins to be classified into two types: passive continental margin basins and transform continental margin basins. This tectonic differentiation governs hydrocarbon accumulation through a “triple-control” mechanism: subsidence-thermal evolution divergence controls source rock type and maturation; tectonic-depositional cycle coupling controls reservoir/trap type and reservoir-caprock assemblage; and structural configurations control hydrocarbon accumulation, preservation and enrichment patterns. Moderate heat flow on the northern shelf favors oil generation from the Paleogene lacustrine source rocks, while high geothermal gradients in the southern deep-water area promote late-stage rapid gas generation from coal measures, forming the resource distribution framework with “oil in the north and gas in the south”; Tectonic-depositional coupling regulates reservoir distribution and reservoir-caprock assemblage effectiveness, with the rift-stage faulting inducing isolated lacustrine delta reservoirs, the southward shift of subsidence during the rift-drift transition giving rise to extensive marine delta sandstones, the detachment faults in deep-water areas governing the development of canyon channels, and regional transgressive mudstones and overpressure mudstones serving as key caprocks; Structural styles dictate accumulation models, including primary oil reservoirs characterized by the association of weakly reworked traps and regional seals, deep-water gas reservoirs characterized by shelf-break controlled sand and high heat flow-driven gas migration, composite gas reservoirs characterized by transfer zone controlled reservoirs and overpressure mudstone sealing, and late-stage rapid hydrocarbon accumulation characterized by strike-slip stress transition and diapir conduit. Analysis of hydrocarbon accumulation in typical oil and gas fields validates these cognitions, revealing the comprehensive control of tectonic evolution on source rock maturation, reservoir distribution, trap types and preservation conditions. Based on these findings, it is recommended to differentiate exploration strategies by areas and layers, with focus on structural-lithological traps under high heat flow setting in deep-water areas and primary oil reservoirs with weak reworking in shallow-water areas.

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. 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 on average) and single-well estimated ultimate recovery (EUR) (8 255×10⁴ m³ on average). 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. It is necessary to address the predicament through multi-dimensional coordination in terms of resources, technology, environmental protection and policies.

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 the year of 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 over-8 000-m 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 reserves are highly concentrated in the Tethyan and South Gondwana petroleum realms, 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 over-8 000-m oil and gas in China, a new peak of reserve growth is forthcoming.

This paper proposes a multi-agent system centered on large language models to address the issues that traditional well log interpretation relies on expert experience and poses great difficulty in multi-disciplinary collaboration and constructs a digital twin architecture across three dimension of agents, tools and environment. At the agent level, a role-based architecture is established to decompose the complex log interpretation workflow into independent subtasks, enabling structured transfer of expert knowledge. At the tool level, petrophysical formulas and machine learning algorithms are encapsulated to form a physics-data dual-path hybrid reasoning mechanism; at the environment level, a standardized digital twin space is established based on the Model Context Protocol to achieve closed-loop control of the entire workflow. Engineers can drive the system through natural language commands to complete the full log interpretation process from data loading and parameter calculation to reservoir classification, realizing end-to-end automation from raw data to interpretation conclusions. In tests on 100 field wells, the system generates key interpretation parameters that are highly consistent with expert results, exhibiting stable recognition capability for complex reservoir types. This study demonstrates that this human-machine collaborative working mode significantly enhances the standardization and efficiency of well log interpretation, providing technical reference for intelligent transformation of highly specialized industrial processes.

Coal-measure whole petroleum system is generally featured by dual-source multi-reservoir coupling, coexistence of three dynamic fields controlling hydrocarbon accumulation, and sequential accumulation of deep coal-rock gas (shale gas), proximal tight sandstone gas (fractured tight gas), distal tight gas/conventional natural gas, and shallow coalbed methane. To reveal the common geological characteristics of coal-measure WPS in the Jurassic coal-bearing basins in Northwest China, this paper analyzes the geological characteristics of coal-measure WPSs in Kuqa Depression of Tarim Basin and Thrust Belt of Southern Junggar Basin, such as structure and hydrocarbon accumulation. It is pointed out that the Jurassic whole petroleum system of coal measures in northwestern China is significantly different from that of the Carboniferous-Permian in North China. Four types of source-reservoir coupling accumulation models are mainly developed in the Jurassic of Northwest China, including structural-type shallow to deep conventional gas outside the source, structural-type deep to ultra-deep tight gas outside the source, near-source/in-source tight gas, and self-generating and self-preserving coal-rock gas. It is indicated that the Jurassic strata in Northwest China belong to the giant continental sedimentary region on the passive continental margin of Neo-Tethys Ocean, including six subsidence zones, and containing coal measures and coal rocks that are consistent in the region but distinct from basin to basin. Thus, this region stands as the largest Mesozoic coal-measure area and a giant natural gas accumulation area in China. Resource assessment demonstrates that the Jurassic coal-measure WPS in Northwest China holds natural gas resources up to 30×10¹² m³, in which merely 11% has been proved, and coal-rock gas accounts for 17×10¹² m³, possessing a tremendous exploration potential. Deep and ultra-deep tight gas and coal-rock gas in Kuqa Depression and Southwestern Depression of Tarim Basin, southern margin of Junggar Basin, northern margin of Qaidam Basin, and Taipei Sag of Turpan-Hami Basin will serve as key natural gas exploration targets in the future.

Based on test data, production performance data, logging data and seismic data of shale samples from the Cretaceous Lower Eagle Ford Formation in the Gulf Coast Basin, USA, methods for determining organic matrix porosity and inorganic matrix porosity were established, and a method for reconstructing the original total organic carbon was developed. Systematic research was conducted by analyzing values across varying intervals of original total organic carbon content, vitrinite reflectance, and clay mineral content. The study shows that shale matrix porosity is primarily controlled by original total organic carbon content and vitrinite reflectance, with organic pores contributing up to 68% to total matrix porosity. A parameter quantifying the organic matrix porosity contribution per unit original total organic carbon is proposed, which can effectively characterize its evolution. As vitrinite reflectance increases, both matrix porosity and effective matrix porosity exhibit a pattern of initial increase, subsequent decrease, and secondary increase before ultimately stabilizing. The ratio of effective-to-total matrix porosity increases from approximately 53% in low-maturity stage to 79% in high-maturity stage. Inorganic matrix porosity remains relatively stable, with clay mineral transformation causing a maximum reduction of approximately 0.62 percentage points. Strong positive correlations are observed between matrix permeability and matrix porosity, as well as between vertical and horizontal permeability, with horizontal permeability being approximately 20 times that of vertical permeability. Fracture porosity is predominantly controlled by the intensity of tectonic activity, and estimated ultimate recovery is jointly governed by hydrocarbon-filled matrix porosity and fracture porosity. The dynamic evolution mechanisms of reservoir properties throughout the entire thermal evolution of shale are revealed, characterized by pore generation and permeability enhancement via organic hydrocarbon generation, porosity-permeability enhancement through tectonic fracturing, porosity reduction due to oil cracking and subsequent pore-filling by pyrobitumen/bitumen, and porosity reduction driven by clay mineral transformation. The established quantitative evaluation models for shale matrix porosity, fracture porosity, and permeability can provide methodological reference for shale reservoir property evaluation.

In 2023, the China National Petroleum Corporation (CNPC) has successfully drilled a 10 000-m ultra-deep well - TK-1 in the Tarim Basin. This pioneering project has achieved dual breakthroughs in ten-thousand-meter ultra-deep earth science research and hydrocarbon exploration while driving technological advancements in ultra-deep well drilling engineering. The successful completion of TK-1 has yielded transformative geological discoveries. For the first time in exploration history, comprehensive data including cores, well logs, fluids, temperature and pressure were obtained from 10 000-meter depths. These findings conclusively demonstrate the existence of effective source rocks, carbonate reservoirs, and producible conventional hydrocarbons at such extreme depths - fundamentally challenging established petroleum geology paradigms. The results not only confirm the enormous hydrocarbon potential of ultra-deep formations in the Tarim Basin but also identify the most promising exploration targets. From an engineering perspective, the project has established four groundbreaking technological systems: safe drilling in complex pressure systems of ultra-deep wells, optimized and fast drilling in complex and difficult-to-drill formations of ultra-deep wells, wellbore quality control under harsh conditions in ultra-deep wells, and data acquisition in ultra-deep, ultra-high-temperature complex formations. Additionally, ten key tools for ultra-deep well drilling and completion engineering were developed, enabling the successful completion of Asia's first and the world's second-deepest vertical well. This achievement has significantly advanced the understanding of geological conditions at depths exceeding 10 000 m and positioned China as one of the few countries with core technologies for ultra-deep well drilling.

Based on the molecular structure transitions, hydrocarbon composition, and reservoir characteristics changes during coal evolution, combined with the production characteristics of coal-rock gas, the generation stages and genetic types of coal-rock gas in China are investigated. The generation of 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 gas origin, the gas reservoirs are divided into three types: shallow coalbed methane, deep coal-rock gas and exogenous coal-rock gas. According to the hydrocarbon generation stage of coal rock, deep coal-rock gas is further classified into: mid-coal-rank transitional 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. During the dynamic evolution of coal rock from shallow to deep depths, the coal rock has experienced a hydrocarbon generation evolution sequence of “biogenic gas→transitional gas→wet gas→dry gas”, and a process of “primary pores→cleat development→peak organic matter pores→densification and fracturing + fracture opening” of reservoirs formation. The occurrence state gradually shifts from “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, there is another type of coal-rock gas which is externally sourced, with the natural gas originating from underlying strata. This type of coal-rock gas corresponds to low-rank coals with reservoir development, where gas was accumulated under the control of tectonics, with high-proportion free gas and high initial production.

Through systematic comparison of the geological characteristics, resource distribution, and exploration and development status of global marine and continental shale oil, this paper deeply analyzes the key theoretical and technical issues that restrict the development of continental 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 underdeveloped; 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 continental shale oil in the Songliao Basin, Ordos Basin, Junggar Basin and Bohai Bay Basin of China, 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 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 on geological theory and engineering technology confronting the shale oil revolution in China: 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 the continental geological conditions in China, providing theoretical and technical support for achieving large-scale and beneficial development.

This paper systematically reviews the development history and generational characteristics of multi-stage fracturing technology in horizontal wells, and defines the connotation and essence of the new-generation volume stimulation technology which is represented by extreme limited entry (XLE). The research indicates that classical fracturing theory remains the cornerstone for optimizing stimulation designs. Optimization based on fracture units is fundamental for achieving “perfect fracturing”, while “proppant loading intensity” serves merely as a statistical parameter and therefore cannot be used to evaluate fracturing effectiveness. Consequently, expanding the stimulated volume is identified as the key to achieving optimal stimulation results. Regarding limited entry perforation strategies, the study clarifies that all clusters initiation can be achieved when total perforation friction exceeds the horizontal in-situ stress difference among clusters. Furthermore, XLE requires a total perforation friction greater than 10 MPa, superimposed on the treating pressure at wellhead after all clusters initiation, to ensure even fluid distribution across all fractures. Based on the characteristics of “fracture swarms” observed in cores from hydraulic fracturing test sites (HFTS), it is revealed that creating a single principal fracture is critical for effective fracture propagation. Drawing on the rheological characteristics of proppant settling in slickwater and learnings from North American HFTSs, three novel viewpoints on modern fracturing are proposed: Slickwater fracturing relies on velocity for proppant transport, and subsequently injected proppant travels the furthest, suggesting that “CounterProp” is the future direction of fracturing technology; High-viscosity slickwater struggles to achieve effective proppant transport; The proppant settling mode determines that the dynamic fracture width during the treatment is effectively equal to the propped fracture width. Finally, the technical connotation and implementation pathway for “whole-domain propped” treatment are presented, and a future development vision for Autonomous Intelligent Fracturing (AIF) is proposed.

Taking the Cambrian Qiongzhusi Formation in the Ziyang-Jingyan area of the southwestern Sichuan Basin as the research object, this study investigates the reservoir characteristics, enrichment mechanism and accumulation model of new-type shale gas by comprehensively using core and thin section observation, geochemical testing, and production dynamic analysis. Two types of shales, organic-rich shale and organic-lean shale, are developed in the study area. The organic-lean shale can receive gas supply from source rock cracking in adjacent areas, possessing the foundation of multi-source hydrocarbon generation and gas supply. Multiple sets of tuffaceous shale were developed in the Qiongzhusi Formation of southern Sichuan Basin. Multi-stage volcanic-hydrothermal activities promoted the development of inorganic pores, microfractures and reservoir space. The reservoirs are characterized by high inorganic pore content, high brittle mineral content and high free gas proportion, and the ultra-deep shale presents favorable reservoir fracturing property and gas-bearing potential. Breaking the traditional understanding that shale gas only migrates over a short distance and accumulates in-situ merely in organic-rich shale, a new mixed-source enrichment model of in-situ generation + external migration charging for organic-lean shale is established. It is clarified that natural gas in the central Sichuan Basin follows a composite accumulation evolution path of “source rock cracking - in-situ generation - migration replenishment”. Three types of gas reservoirs are formed successively, including the early in-situ cracked conventional gas in the Cambrian Longwangmiao Formation of the Gaoshiti - Moxi area, the middle-stage in-situ enriched shale gas in the Qiongzhusi Formation of the Ziyang area, and the mixed-source shale gas formed by in-situ generation superimposed with late migration replenishment in the Qiongzhusi Formation of the Jingyan area.

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 shale oil reservoirs in the Songliao Basin, China. The in-situ porosity in shale oil reservoirs is generally 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 close these pressure-supported pores, causing conventional helium and surface nuclear magnetic resonance (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 the 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, total organic carbon content, 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.

The Paleogene Liushagang Formation in the Wushi Sag of the Beibuwan Basin is characterized by dispersed hydrocarbon distribution, small-scale residual exploration targets and large burial depth. Based on data from drilling, laboratory experiments, and geophysic analysis, this study systematically investigates the hydrocarbon accumulation conditions and enrichment patterns in the Liushagang Formation. The key findings are obtained in five aspects. First, the structural evolution of the sag involved three distinct stages: early faulting, mid-stage detachment deformation and late adjustment, governed by an “extension-detachment-strike-slip” composite fault system that controlled basin subsidence, depocenter migration and sedimentary environment evolution. Second, three principal source rock intervals in the Eocene Liushagang Formation, concentrated in the southern East Sub-sag under the control of the No. 7 Fault Zone, are characterized by considerable thickness and high quality, with the oil shale in the lower part of the second member of Liushagang Formation (lower Liu-2 Member) being the most prolific, providing a robust resource foundation in the sag. Third, four reservoir-seal assemblages are identified, corresponding to three hydrocarbon migration systems: direct source-reservoir contact, fault-sandbody coupling, and fault-structural ridge-sandbody stepwise composite networks. Fourth, three accumulation models are established: “young source-old reservoir” with lateral stepwise migration, “self-sourced and self-stored” intra-source enrichment, and “lower source-upper reservoir” with vertical migration. Fifth, exploration priorities are further delineated, highlighting deep fault-block traps in the central zone of the eastern subsag, intrasag lithologic traps, and bedrock buried-hill targets with direct source-reservoir connectivity, all demonstrating significant resource potential.

Traditional wellbore detection technologies face limitations such as low detection efficiency, poor accuracy, unsuitability for unconventional oil/gas well fracturing operations, and incomplete coverage of wellbore damage as well as integrity assessment. This paper introduces a phased array electromagnetic wellbore detection technology. The theoretical principles, instrument design, and technical connotation of this technology are systematically elaborated. Field applications, including casing damage and corrosion detection in old wells in Xinjiang Oilfield, China, and fracturing-induced casing deformation detection in platform wells targeting deep shale gas in Southwest Oil & Gas Field and deep shale oil in Dagang Oilfield, China, are analyzed to evaluate the proposed technology’s performance in inspecting metal casing strings. Results demonstrate that the phased array electromagnetic wellbore detection technology provides high measurement accuracy, broad applicability, ease of operation and high scalability. The technology achieves a resolution of 10 mm for non-penetrating damage detection, 0.5 mm for inner diameter measurement of oil casing, and 0.3 mm for wall thickness assessment. It maintains stable performance in high-temperature (no more than 175 °C) and high-pressure (no more than 140 MPa) environments, and effectively addresses current exploration and production requirements by providing comprehensive and accurate wellbore integrity data for downhole operations.

This study investigates the strong heterogeneity and complex internal architecture of carbonate reservoirs, using the Cretaceous Main Mishrif Formation in the Middle East as an example. A multi-scale characterization of sedimentary architecture is conducted based on reservoir genetic analysis. Quantitative calibration of well logs with core thin sections enables semi-quantitative evaluation of dissolution intensity in non-cored intervals. Within a coupled depositional-diagenetic framework, reservoir classification is established using depositional-diagenetic facies, allowing delineation of their spatial distribution and connectivity. The results show that three types of architectural units are developed in the Main Mishrif Formation, including tidal channels, bioclastic shoals, and tidal bioclastic deltas, which exhibit fining-upward, coarsening-upward, and coarsening-upward-fining-upward successions, respectively. These units form composite stacking patterns characterized by compensational stacking and aggradational stacking. A dissolution intensity index is defined based on thin-section analysis, and a log-based prediction model is developed using principal component analysis and multivariate regression. Dissolution in the MB2 sub-member is controlled by third-order sequence boundaries, with strong dissolution occurring from MC1-1 to MB2-1, forming high-permeability zones across architectural units. In contrast, dissolution in the MB1 sub-member is controlled by high-frequency sequences, with stronger dissolution in the upper intervals, favoring the development of high-permeability zones. By combining depositional and dissolution characteristics, a total of 21 depositional-diagenetic facies are identified, and the distributions of high-permeability zones, high-quality, moderate, and poor reservoirs, as well as interlayers are systematically characterized. These findings provide a geological basis for stratified reservoir development, well pattern optimization, and remaining oil recovery in carbonate reservoirs, and are promising for the characterization of giant thick carbonate reservoirs in the Middle East and Central Asia.

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. 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 geology-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 and complex conditions, 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 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 the oil and gas exploration in China 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 from coarse to fine. 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 area, 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.

This paper systematically investigates the numerical simulation model construction and methods for hot dry rock geothermal resource development. It highlights the influence law and characterization differences of multi-physics field coupling mechanism across various stages of development and utilization. The technical features and applicable scenarios of typical numerical simulation methods, as well as the application potential and advantages of emerging technologies such as intelligent algorithms in numerical simulation for hot dry rock geothermal development, are comprehensively reviewed. In addition, the functional characteristics and engineering application cases of mainstream geothermal numerical simulation software in China and abroad are summarized. On this basis, the core challenges for existing techniques are identified, and future development directions are proposed. At present, numerical simulation for hot dry rock geothermal resource development still faces several challenges, including insufficient accuracy in characterizing complex reservoir structures, incomplete representation of multi-physics field coupling mechanisms, limited cross-scale simulation capability, inadequate adaptability of software to diverse scenarios, and insufficient support from field monitoring and fundamental data. In the future, numerical simulation technologies for hot dry rock geothermal resource development should advance theoretical and technical research in full-chain integrated modeling, refined characterization of multi-physics field coupling, deep integration of intelligent algorithms with numerical simulation, and establishment of an independent and controllable software ecosystem, thereby providing theoretical and technical support for the sustainable and efficient development of hot dry rock geothermal resources in China.

Two types of ultra-high-temperature resistant water-based drilling fluid additives were designed and developed: an ultra-high- temperature resistant salt-tolerant polymer fluid loss reducer, and an ultra-high-temperature resistant micro-nano plugging agent. An ultra-high-temperature resistant water-based drilling fluid system meeting the requirements of ultra-deep well drilling was established. Laboratory test and field application were employed for performance evaluation. The ultra-high-temperature and high-salt resistant polymer fluid loss reducer exhibits a mesh-like membrane structure with numerous cross-linking points, and its high-temperature and high-pressure (HTHP) loss was 28.2 mL after aging at 220 °C under saturated salt conditions. The ultra-high-temperature resistant micro-nano plugging agent adaptively filled mud cake pores/fractures through deformation, thus reducing the fluid loss. At elevated temperatures, it transitioned to a viscoelastic state to effectively cement the rock on wellbore wall and enhanced wall stability. The ultra-high-temperature resistant water-based drilling fluid system with a density of 1.6 g/cm³ exhibits excellent rheological properties at high temperature and high pressure. Its HTHP fluid loss at 220 °C was only 9.6 mL. It maintains a stable performance under high-temperature and high-salt conditions, with a sedimentation factor below 0.52 after holding at high temperature for 7 d, and generates no H₂S gas after aging, demonstrating good lubricity and safety. This drilling fluid system has been successfully applied in the 10 000-meter ultra-deep well of China, Shenditake 1, in Tarim Oilfield, ensuring the well's successful drilling to a depth of 10 910 m.

Against the bottleneck issues in the Ordovician subsalt marine gas-bearing system of the Ordos Basin, including doubtful quantity of gas generated by low-abundance source rocks, and unclear gas accumulation and preservation patterns, this study investigates the reservoir-forming conditions and near-source exploration practices of the gas-bearing system. First, the argillaceous dolomite and argillaceous gypsum dolomite of the third member of the Ordovician Majiagou Formation (Ma-3 Member) are the main subsalt marine source rocks, and the Dingbian sub-depression and its periphery are the most favorable gas-generating centers, hosting source rocks of 10-80 m thick cumulatively, dominated by Type I kerogen with total organic carbon (TOC) content of 0.58%-1.39% and vitrinite reflectance of 1.62%-2.16%. Second, reservoirs are controlled by paleogeomorphology and penecontemporaneous dissolution, with anhydrite nodule dissolution mold pores, intergranular pores, and intercrystalline pores. Regional and direct caprocks of gypsum-salt rocks are widely developed. The dense NNE-trending strike-slip faults in the east and sparse X-type strike-slip faults in the central area effectively connect source rocks and reservoirs. Third, the south-north fault-uplift and east-west nose-uplift structural setting, combined with the gypsum-bearing dolomitic flat-salt sag facies transition zone, control natural gas accumulation and preservation. Based on these findings, a new accumulation model characterized by near-source gas supply, facies transition sealing, and structural convergence is established for the Ma-3 Member, and favorable exploration zones with multi-type trap groups in low-relief structures are identified. The carbonate-gypsum-salt rock strata in the Ordos Basin exhibit distinct characteristics of low-abundance source rocks coupled with strong gypsum-salt rock sealing. Near-source exploration offers a new pathway for the exploration in the Ordovician subsalt marine gas-bearing system.

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 intelligent optimization framework taking the economic net present value as the objective. Based on rapid prediction of injection and production behaviors, the proposed approach enables optimization of injection-production 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 injection-production systems, exhibiting high accuracy and stability. It enables global optimization of production strategies under economic constraints, demonstrating strong engineering applicability and scalability.

Starting from the first principle thinking, this study systematically reviews the development mechanisms of gas reservoirs and proposes the development concept of “full lifecycle enhanced gas recovery (EGR)”. Following the principles of scientificity, practicality and comparability, a generational classification system for EGR technologies is established. The research indicates that the properties of natural gas dictate a development mechanism primarily driven by pressure depletion to release the elastic expansion energy of gas. This leads to a development model centered on primary depletion, supplemented by limited adjustments in late stages. Early development essentially lies in well pattern optimization and risk pre-control, while late development focuses on targeted local adjustments and integrated collaborative control. Primary gas recovery, relying on natural energy depletion, achieves a recovery factor of 25%-55%. Secondary gas recovery, through active regulation of the reservoir pressure field via techniques like blockage removal, and injection-production optimization, can enhance the recovery factor by 10-15 percentage points. Tertiary gas recovery, employing multiple mechanisms to alter the reservoir’s physical and chemical fields synergistically, offers a potential further increase of 5-10 percentage points. Currently, primary recovery technologies are mature and well-established. Synergistic optimization of well patterns and fracture networks enables effective production from gas-drive reservoirs, while optimized development strategies facilitate orderly production from water-drive gas reservoirs. Secondary recovery technologies, in the field pilot stage currently, adopt active measures like enhanced water drainage, water shutoff, and gas injection to effectively control water influx and release trapped gas. Tertiary recovery remains largely in the laboratory or pilot test stage. Future efforts should focus on cross-generational technologies, such as “primary + secondary” and “primary + tertiary” combinations, to continuously improve recovery factors throughout the full lifecycle of gas reservoirs.

This study reviews the recent progress and trends of carbon capture, utilization and storage (CCUS) technologies, with a particular focus on related policy orientations, technological status, and representative projects across North America, Europe, the Middle East, and China. The technical connotations of CCUS are elucidated, and the existing issues and challenges are identified from the perspectives of technology, economics, safety and system integration. The CO₂ capture technologies are relatively mature; the emergence of novel processes such as direct air capture (DAC) and advanced materials such as metal-organic frameworks (MOFs) offer new choices for efficient capture, but issues related to high energy consumption and operational costs remain unresolved. The CO₂ geological utilization has developed earlier, where breakthroughs rely on effective source matching, enhanced miscibility and increased swept volume. The CO₂ chemical utilization exhibits broad market potential for producing high value-added products, and the development of catalytic systems with high conversion efficiency and low cost is identified as the core challenge. For CO₂ storage, diverse geological bodies provide vast theoretical capacities on both land and offshore worldwide, but subsidy policies and carbon market regulation are required to offset the limited economic returns of storage technologies. This study highlights several frontier technologies, including low-concentration CO₂ capture, CO₂-enhanced oil recovery (EOR), CO₂-based green fuel synthesis, microbial CO₂ conversion, CO₂ mineralization and hydrogen production, and CO₂ cushion gas replacement in underground gas storage (UGS). Through cost-effective innovation, regional pipeline network development, flexible technology integration, coordinated macro-policy regulation, and cross-disciplinary collaboration, CCUS can achieve a transformative scale-up from million-ton and ten-million-ton capacities to the hundred-million-ton level, contributing to the achievement of the carbon neutrality goals of China.

Based on the data of regional geology, seismic, drilling, logging and production performance obtained from 94 major petroliferous basins worldwide, the global coal resources were screened and statistically analyzed. Then, using established definition methods and evaluation criteria for coal-rock gas in China, and by analogy with the tectono-sedimentary and burial-thermal evolution conditions of coal rocks in sedimentary basins within China, the geological resource potential of global coal-rock gas was estimated mainly by the volume method, partly by the volumetric method in selected regions. According to the evaluation indicator system comprising 14 parameters under 5 categories and the associated scoring criteria, the target basins were ranked, and the future research targets for these basins were proposed. The results reveal that, globally, coal rocks are primarily formed in four types of swamp environments within four categories of prototype basins, and distributed across five major coal-forming periods and eight coal-accumulation belts. The total geological coal resources are estimated at approximately 42×10¹² t, including 22×10¹² t in the strata deeper than 1 500 m. The global geological coal-rock gas resources in deep strata are roughly 232×10¹² m³, of which over 90% are endowed in Russia, Canada, the United States, China and Australia, with China contributing 24%. The top 10 basins by coal-rock gas resource endowment, i.e. Alberta, Kuznetsk, Ordos, East Siberian, Bowen, West Siberian, Sichuan, South Turgay, Lena-Vilyuy and Tarim, collectively hold 75% of the global total. The Permian, Cretaceous, Carboniferous, Jurassic, and Paleogene-Neogene account for 32%, 30%, 18%, 10%, and 7% of total coal-rock gas resources, respectively. The 10 most practical basins for future coal-rock gas exploration and development are identified as Alberta, Ordos, Kuznetsk, San Juan, Sichuan, East Siberian, Rocky Mountain, Bowen, Junggar and Qinshui. Propelled by successful development practices in China, coal-rock gas is now entering a phase of theoretical breakthrough, technological innovation, and rapid production growth, positioning it to spearhead the next wave of the global unconventional oil and gas revolution.

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” phenomenon 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 shale oil. Research indicates that the “lower sweet spot” has a relatively high content of light and medium hydrocarbon components and strong formation energy compared to the “upper sweet spot” of Lucaogou Formation, 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.

To solve 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 low thermal maturity, with vitrinite reflectance (R_o) commonly below 0.8%, is the primary reason why the actual gas content is significantly lower than the hydrocarbon generation capacity in basins such as the Junggar Basin. In addition, the coal-forming age and maceral composition characteristics also exert important controls on gas content and storage capacity. 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 large-scale exploration and effective development of coal-rock gas (coalbed methane) resources in Xinjiang.

Under the guidance of the whole petroleum system (WPS) concept, the Jurassic coal-measure source rocks, source-reservoir- caprock conditions, and configurations of various hydrocarbon accumulations in the Junggar Basin were systematically investigated to reveal the hydrocarbon accumulation characteristics and exploration targets of the Jurassic coal-measure WPS. The following research insights are obtained. First, the coal rocks of the Jurassic Badaowan and Xishanyao formations, together with the mudstones of the Sangonghe Formation, constitute a unified source kitchen characterized by large thickness, high thermal evolution degree and sustained gas-generation capability. This kitchen provides an ample source for the orderly accumulation of conventional oil and gas, coal-rock gas and tight sandstone gas. Second, multi-phase fluvial-deltaic sedimentation has developed thick conventional sandstones, tight sandstones, and coal rocks as diverse types of reservoirs in the basin, offering various storage spaces for hydrocarbon accumulation, while regionally extensive thick mudstones ensure effective sealing of deep gas reservoirs. Third, within the unified petroleum accumulation system, multi-phase detachment and superimposed structures control hydrocarbon migration pathways and accumulation units, resulting in a orderly distribution of reservoirs from structural highs to deep sags. Specifically, at the southern margin, deep conventional natural gas and deep coal-rock gas are endowed in the central segment, while oil and gas coexist in the eastern and western segments; in the basin hinterland, coal-rock gas generated from old strata and stored in young strata is confirmed in the Dinan-Baijiahai area, while coal-rock gas generated and stored in the same set of strata is discovered in the Qigu area; in the slope and structurally complex zones, tight sandstone gas of the Badaowan Formation is found.

Through systematic investigation of deep coal-rock gas in the Ordos Basin, NW China, this work analysed the thickness distribution of the entire Upper Paleozoic coal-rock intervals, quantified the resource potential of representative areas (a 12 000 km² rectangular block in the eastern Ordos Basin roughly centered on Yulin City), clarified the occurrence characteristics of coal-rock gas, and identified key development indicators for gas wells, thereby defining the direction for iterative optimization of key technologies. (1) The total coal-rock gas in-place of the Upper Paleozoic coal seams 1^#-10^# in the reserve evaluation region is assessed at 5.66×10¹² m³, of which coal seam 8^#, currently the main target interval, contains about 3.08×10¹² m³, accounting for roughly 54% of the total. (2) Deep coal-rock gas is characterized by a high ratio of free gas. Under the conditions of 2 000 m burial depth, 6.35% porosity, 95% free gas saturation, and 22.13 m³/t total gas content, the free gas content of the reservoir is estimated to be ca. 40% of the total gas. (3) Three productivity evaluation models (triangular, convex, concave) are developed for horizontal wells, of which the triangular model can serve as the reference model for predicting the estimated ultimate recovery (EUR) throughout the lifecycle of coal-rock gas wells. Using the triangular model with a 7 m coal thickness, 1 500 m effective lateral length and 400 m well spacing, the average single-well EUR is determined to be 4 621.28×10⁴ m³. (4) Development of the coal seam 8^# should employ horizontal wells with pressure-controlled production. Meanwhile, it can be further optimized by adopting the cost-effective strategies of the Sulige Gas Field in the Ordos Basin, China. (5) To achieve cost-effective development and increase primary recovery factor, key technologies must undergo continuous iteration and upgrading, focusing on accelerating drilling, extending effective lateral lengths, high-intensity reservoir stimulation, and well-pattern optimization.

To reveal the complex crude oil-CO₂ interaction mechanism and oil mobilization behavior during CO₂ huff-n-puff in shale-type shale oil reservoirs, CO₂ huff-n-puff experiments with on-line nuclear magnetic resonance monitoring were conducted on Gulong shale cores, combined with the prediction model of CO₂ dynamic diffusion coefficient, the flow mechanism and factors influencing oil mobilization during CO₂ huff-n-puff in Gulong shale oil reservoirs are studied, and the diffusion and mass transfer behavior of CO₂ in shale is investigated. The results show that at the injection stage, CO₂ invades into macropores near the injection end, and drives part of the crude oil to micropores in the deep part of the core. At the shut-in stage, the crude oil gradually reflows to macropores near the injection end and is redistributed in the core. At the production stage, the oil mobilization zone is gradually expanded from the production end (injection end) to the deep part of the core. The contribution ratio of produced oil from macropores and micropores is about 8︰3 after production. The diffusion coefficient of CO₂ in shale porous media gradually decreases with the advance of diffusion front at shut-in stage. The better the porosity and permeability of core samples, the higher the CO₂ concentration at diffusion front, the greater the CO₂ diffusion coefficient, and the slower the diffusion decline rate is. Increasing the huff and puff cycles could effectively enhance oil displacement efficiency, though its impact on the crude oil mobilization zone remains insignificant. The crude oil in small pores of the small layer with undeveloped laminae is difficult to be produced during CO₂ huff-n-puff, and the oil recovery is only 12.72 %. The crude oil in macropores and micropores of the small layer with developed laminae can be effectively mobilized during CO₂ huff-n-puff, and the oil recovery can reach 39.11%.

In-situ heating conversion is the most practical recovery method for lacustrine low-to-medium maturity shale oil. However, the energy output-input ratio must exceed the economic threshold to achieve commercial development. This paper systematically investigates the mechanism of super-rich accumulation of organic matter in continental shale, sweet spot evaluation, optimal heating windows, and appropriate well types and patterns from the perspectives of enhancing energy output and reducing energy input. (1) The super-rich accumulation of organic matter in lacustrine shale is primarily controlled by the intensity, frequency, and preservation of external material inputs, and is related to moderate volcanic and hydrothermal activities, marine transgressions, with total organic carbon content greater than or equal to 6%. (2) The quality of organic-rich intervals is related to the type of source material and hydrocarbon generation potential. The in-situ conversion-derived hydrocarbon quality index (HQI) is established, and the zones exhibiting HQI ˃450 are defined as sweet spots. (3) Considering the characteristics of the organic matter conversion material field and seepage field, the temperature interval 300-370 °C is recommended as the optimal heating window for the Chang 7₃ sub-member of the Triassic Yanchang Formation in the Ordos Basin. Based on the advantages of thermal conductivity, permeability, and hydrocarbon expulsion efficiency along the bedding direction during in-situ heating, the “horizontal well heating + vertical well development” scheme is proposed, which has demonstrated significant enhancement in both recovery factor and energy output-input ratio, making it the optimal in-situ conversion process. The research findings provide a theoretical and technical foundation for the economical and efficient development of low- to medium-maturity shale oil.

Based on the investigation of sedimentary filling characteristics and pool-forming factors of the Mesozoic in the Ordos Basin, the whole petroleum system in the Mesozoic is divided, the migration & accumulation characteristics and main controlling factors of conventional-unconventional hydrocarbons are analyzed, and the whole petroleum system model is established. First, the Mesozoic develops the whole petroleum system dominated by source rocks of the 7^th member of Triassic Yanchang Formation and low-permeability oil reservoirs to unconventional oil and gas. It can be divided into four hydrocarbon accumulation domains, including intra-source retained hydrocarbon accumulation domain, near-source tight hydrocarbon accumulation domain, far-source conventional hydrocarbon accumulation domain and transitional hydrocarbon accumulation domain. Second, the core area of sedimentary filling is the oil-rich core of the whole petroleum system. From the core to the periphery, the reservoir type evolves as shale oil → tight oil → conventional oil, the accumulation power is dominated by overpressure → buoyancy or overpressure and capillary force, the accumulation scale changes from extensive hundreds of millions of tons to a dispersed hundreds of thousands-million of tons, and the gas-oil ratio and methane content decrease. Third, the sedimentary filling system provides the material basis and spatial framework for the whole petroleum system, the superimposed sand body, fault and unconformity constitute the dominant migration pathway of hydrocarbons in the far-source conventional hydrocarbon accumulation domain and the transitional hydrocarbon accumulation domain, the high-quality source rocks provide a solid resource basis for shale oil, and the micro-nano pore throat-fracture network constitute unconventional accumulation space. The hydrocarbon migration and accumulation process is mainly controlled by intense expulsion of hydrocarbon under overpressure in the pool-forming stage and the in-situ re-enrichment controlled by underpressure in post-pool-forming stage. The oil-gas enrichment and long-term preservation depends on the coordination among three factors (stable geological structure, multi-cycle sedimentation, and dual self-sealing). Fourth, the whole petroleum system model is defined as four domains, overpressure + underpressure drive, and dual self-sealing.

This paper systematically reviews the advances in shale oil and gas drilling fluid technology, provides an in-depth analysis of the critical bottlenecks in each technology and explores their future development directions. Several technologies have been developed for shale oil and gas: water-based drilling fluids with a core emphasis on sealing, inhibition and lubrication; oil-based drilling fluids centered around wellbore strengthening, low-oil-water-ratio emulsions, and synthetic-based systems; drilling fluids for reservoir protection based on clay-free, under-balanced, and interfacial modification; as well as lost circulation control technologies founded on bridging, gelling, responsive, and composite mechanisms. A comprehensive analysis indicates that existing technologies are still plagued by several bottlenecks, including inadequate high-temperature and contamination resistance, prohibitive costs, and poor formation adaptability. Drilling operations still face severe challenges such as wellbore instability, reservoir damage and severe fluid losses. Accordingly, the following prospects for future shale oil and gas drilling fluid technology are proposed: (1) Water-based drilling fluids require a focus on the synergistic effects of nanoscale plugging and chemical inhibition, the development of smart responsive lubricants, and enhanced resistance to high temperatures and acid gas contamination. (2) Oil-based drilling fluids should achieve breakthroughs in novel emulsifiers for cost-effectiveness and high-temperature resistance, alongside intensified research efforts in environmentally friendly technologies. (3) Reservoir protective drilling fluids necessitate the development of a real-time prediction and diagnosis expert system for formation damage, coupled with the advancement and application of high-temperature resistant additives and intelligent integrated pressure control equipment. (4) Lost circulation control technologies should be dedicated to developing smart responsive plugging materials and strengthening their compatibility with fracture networks.

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 reconstruction, overpressure evolution and geochemistry. The formation and evolution process of the Gulong shale oil was reproduced, and its enrichment patterns were clarified. Influenced by tectothermal events and tectonic 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 depositional stage of the Nenjiang Formation and late depositional stage of the 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 compounds, 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. High paleo-heat flow generated by tectothermal events is determined to be the main driving factor for the staged hydrocarbon generation of organic matter in the Qingshankou Formation. The shale of Qing-1 Member with high thermal conductivity and the Cretaceous Nenjiang shale with low thermal conductivity constitute 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.

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 in shale 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 seepage 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 seepage field with coordinated “artificial well pattern - induced fracture network - natural fracture network” can be constructed through drilling infill wells with small well-spacing, sidetracking in old wells, differential trajectory design, and precise 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 the shale gas development technology in China.

Centering on the critical bottlenecks in the development of shale oil in the Jiyang Depression of Shengli Oilfield, key scientific and engineering issues are proposed in aspects such as the storage space and occurrence state of shale oil, the formation mechanisms of multi-scale flow spaces, the mobilization mechanisms of crude oil in pores and fractures, and the enhanced oil recovery (EOR) mechanisms during the late stage of elastic development. The research progress and mechanistic insights in recent years are reviewed with respect to experimental techniques, characteristics of pore-fracture structure and fluid occurrence, fracture evolution mechanisms, shale oil flow mechanisms and EOR techniques. Through improving the experimental methods, optimizing the testing conditions, and developing new technologies, we deeply understand the occurrence state, storage space and flow pattern of shale oil, and reveal the distribution pattern of “oil-bearing in all pore sizes and oil-rich in large pores” and the differences in fluid phase states under the confinement effect of nano-scale pores in the shales of the Jiyang Depression; depict the characteristics of “restricted vertical expansion and complex fracture networks” of induced fractures and the dynamic evolution of fracture networks during the fracturing-soaking- production process; establish a “easy flow - slow flow - stagnant flow” three-zone model and the elastic drive + imbibition drive synergistic energy replenishment mechanism; and carry out high-pressure injection to further enhance the mass transfer and diffusion capacity of CO₂ within the shale pore-fracture system, and compete for the desorption of alkanes to improve the mobilization degree of shale oil. The research achievements provide crucial support for the formation of the theory of continental shale oil development and the construction of the technical system. The future research efforts will focus on mine-scale multi-field coupling physical simulation equipment, microscopic to macroscopic cross-scale experimental methods, pore/fracture fine characterization and post-fracturing core fracture description technologies, multi-media fluid-solid coupling numerical simulation algorithms, and low-cost EOR and low-quality shale oil in-situ upgrading technologies, in order to promote the large-scale and profitable development of shale oil in the Jiyang Depression.

This paper systematically analyzes the reservoir-forming characteristics and cretaceous shale oil types in four major hydrocarbon-generating sags (Qingxi, Ying’er, Huahai, and Shida) of the Jiuquan Basin, based on the data of experiments for microscopic and geochemical analysis of reservoirs. The hydrothermal alteration-induced reservoir-forming model and its reservoir-controlling effect in the Qingxi Sag are discussed, and the exploration potential of shale oil in these four sags are evaluated. (1) The Qingxi Sag is widely developed with mud shale, dolomitic shale, and laminated argillaceous dolomite in the Cretaceous, which can be defined as mixed shale as a whole. The source rocks in this area are of good quality and high maturity, formed in a saline water sedimentary environment, and rich in dolomite, with a strong hydrocarbon generation capacity and excellent oil generation conditions. The reservoir space has been significantly modified by hydrothermal process, with well-developed dissolution pores and microfractures, recording favorable reservoir conditions for shale oil enrichment. Overall, this sag has large reservoir thickness and large resource volume, making it the most realistic shale oil exploration target in the Jiuquan Basin. However, it faces challenges such as great burial depth (deeper than 4 500 m) and strong tectonic stress. (2) The Ying’er, Huahai, and Shida sags all feature sand-mud interbeds consisting of fan delta front thin sandbodies and lacustrine mud shale in the Cretaceous, having good source rock quality and favorable conditions for interbedded-type shale oil accumulation. The source rocks are insufficient in thermal evolution degree and unevenly distributed, and favorable shale oil resources are mainly endowed near the center of the sags. Reservoirs are primarily composed of siltstone to fine sandstone, suggesting relatively good reservoir conditions, generally with small burial depth (3 000-4 000 m) and the possibility of local sweet spots. It is noted that the Ying’er Sag has already produced low-mature to mature oil, qualifying it as a near-term realistic shale oil exploration area.

Through a systematic analysis of the physical properties of coal and gangue, including microscopic pore structure, surface wettability and mechanical strength, the mechanism of borehole wall collapse in deep coal formations was revealed. Based on this understanding, a wellbore-stabilizing drilling fluid concept was proposed, featuring high-efficiency plugging of medium and large pores and fractures + cementation and film-formation in micro and small pores and fractures + overall surface hydrophobic inhibition. An adaptive plugging agent and a cementing film-forming hydrophobic inhibitor were developed, and a cementing, wall-strengthening, film-forming, and hydrophobic drilling fluid system was established. The adaptive plugging agent consists of organic-inorganic hybrid polymer microspheres, which enables self-adaptive plugging of pores and micro-fractures in coal rock through flexible deformation, effectively preventing direct contact between the drilling fluid and medium-to-large pore-fracture systems in the formation. The cementing film-forming hydrophobic inhibitor contains strong adsorption groups and hydrophobic groups, which provides both cementing reinforcement and dense film-forming functions, significantly enhancing the overall structural strength of coal rock, greatly reducing surface hydrophilicity, and inhibiting hydration swelling of clay minerals. The developed drilling fluid system exhibits favorable rheological behavior, filtration-control performance and lubricity. It can substantially improve the compressive strength of rock samples and markedly reduce their linear expansion rate. Field application results demonstrate that the system delivers excellent anti-collapse, cuttings-carrying and lubrication performance, with outstanding wellbore stabilization effectiveness.

Shock-tube core experiments have provided an important finding, that is, the low frequency acoustic field generated by planar shock waves can induce pure Stoneley waves in a borehole, with their amplitude attenuations demonstrating a definite correlation with fracture width and permeability. Accordingly, a method was proposed to transmit low frequency planar shock waves in a borehole through axially polarized axial vibration, thereby continuously inducing pure Stoneley waves. Equations were also derived for calculating fracture width and permeability from Stoneley wave amplitude attenuation. Moreover, the permeability logging prototype was successfully developed, together with acquisition and processing software incorporating amplitude-attenuation extraction and permeability calculation. The operability, stability, and measurement performance of the logging tool were tested and verified in two standard wells, R91 in the Bohai Bay Basin and LS2 in the Tarim Basin. In the 10 000-meter-deep well SDTK1 in the Tarim Basin, matrix and fracture permeability curves of extra-deep Cambrian carbonate formations were obtained in a single downhole logging. The results were immediately calibrated with the data of quasi-in-situ nuclear magnetic resonance (NMR) permeability measurement on full-diameter drilling cores taken from the same interval of the well. The results show that the proposed method performs well in quantitative permeability evaluation of extra-deep carbonate reservoirs and provides a new technical approach for permeability logging evaluation in other types of reservoirs. This theoretical and technological breakthrough provides an innovative means for quantitative permeability evaluation in reservoir logging.

In response to the problems such as complex near-wellbore fractures, difficult far-wellbore fracture propagation, and limited stimulated reservoir volume (SRV) caused by the “thousand-layer thin pancakes” configuration of the Guolong shale oil reservoir in the Songliao Basin, China, triaxial mechanical and fracture visualization experiments were conducted on shale samples. Combined with digital image correlation technology and laser pulse ultrafast resolution technology, the micro-scale deformation and supersonic-scale fracture expansion characteristics of the Guolong shale were captured in real time. A constitutive model reflecting the flexible deformation and anisotropy of the Guolong shale and a mechanical model considering competitive fracture initiation-propagation from multiple perforation holes under the coupling of stress interference and flow distribution were established to reveal the control mechanisms of pore density, pore number, and pore distribution on fracture propagation. The results show that by reducing the number of holes and increasing the perforation density, the stress interference between multiple perforation holes can be effectively mitigated, and combined with the extreme limited entry (ELE), the fracturing fluid can be evenly distributed. Compared with the high-density perforation (8 holes per cluster), the low-density perforation (6 holes per cluster) yields an increased opening rate by approximately 45 percentage points. Compared with spiral perforation, the 30° phase angle conjugate directional perforation enables both stress interference reduction and longitudinal/ transverse reservoir connectivity, and it can easily form vertical energy concentration, as indicated by stress field, to drive fracture expansion across layers. The directional perforation + ELE fracturing mode has been verified through field practice. After changing the perforation method from 60°-180° phase angle spiral perforation to 30° phase angle conjugate directional perforation, and reducing the number of perforations from 12-16 holes per cluster to 5-7 holes per cluster, the SRV increased by 17.4% and 48.9%, respectively.

Low-salinity fracturing fluids tend to induce ion migration, alter wettability, and cause fluctuations in gas desorption efficiency when penetrating deep coal seams. Taking the No. 8 coal from the Daning-Jixian block in the Ordos Basin, NW China, as a representative example, this study employs physical simulation experiments to reveal the coupled control mechanism of salinity gradient on the ion-coal matrix-gas/water interfacial system and its key role in the imbibition-desorption process. The increasing ionic concentration enhances the hydrophobicity of coal, with multivalent ions exhibiting particularly significant effects. The imbibition and ion diffusion occur in opposite directions, with imbibition equilibrium being achieved earlier than ionic equilibrium. Water-coal interactions induce both mineral dissolution and secondary precipitation. When a low-salinity fracturing fluid is injected into a high-salinity reservoir, the osmotic-pressure difference drives imbibition, promotes CH₄ desorption, but results in higher fluid loss. Conversely, injecting high-salinity fracturing fluid into a low-salinity reservoir creates a reverse osmotic gradient that suppresses leak-off while improving flowback efficiency. Based on these findings, a high-low salinity sequential injection strategy is proposed for deep coal seams: high-salinity fluid is first injected to form stable fracture networks, followed by low-salinity fluid to enlarge the imbibition zone and enhance CH₄ desorption and diffusion. Moderate well soaking is recommended to increase the imbibition volume, thereby achieving multiple positive effects such as maintaining reservoir pressure, preserving formation energy, and promoting imbibition-driven displacement.