Based on the latest high-precision gravity, magnetic and three-dimensional seismic exploration results in the western margin of the Ordos Basin, the fine analysis of Paleozoic tectonic system and the re-understanding of hydrocarbon accumulation conditions are carried out. The research shows that, by redefining the classification of faults, four types of structural styles are identified, including back thrust belt, hanging wall syncline, footwall in-situ rock mass uplift belt, and strike-slip-thrust imbricate belt. According to the characteristics of source-reservoir configuration, five hydrocarbon accumulation models are established, including the Hengshanbao structural trap gas reservoir group in the northern zone, the tight gas accumulation within syncline source in the hanging wall and concealed uplift structure controlled accumulation in the footwallof of the thrust belt in the central zone, the low-mature shale self-generation and self-storage in the southern zone, and the grain beach + dual-source hydrocarbon supply in the platform margin. Combined with the analysis of exploration results, five favorable exploration areas are delineated: the Hengshanbao complex structural area in the northern zone, covering 410 km², which belongs to the realistic and efficient exploration target area; the concealed uplift belt in the central zone, covering 1 800 km², which is the first breakthrough in the 8^th member of Lower Shihezi Formation; the Carboniferous Yanghugou Formation in the central zone, which has been revealed with the potential for coal-rock gas and tight sandstone gas accumulation within the source; the marine shale oil in the Wulalike Formation in the southern zone, covering 275 km², with Well YT3 achieving an industrial breakthrough; and the western platform margin, covering about 5 300 km². These findings have guiding significance for further breakthrough, expansion, and reserves addition in subsequent oil and gas exploration activities in the western margin of the basin.

Based on microscopic observations, total organic carbon (TOC) content measurements, and major, trace, and rare earth element analyses of core samples from the Cambrian Qiongzhusi Formation shale at different structural positions within the Deyang-Anyue rift trough, this study employs a combined geochemical and random forest machine learning approach to qualitatively and quantitatively identify the controlling factors of organic matter enrichment in black shales, and to elucidate the patterns of organic matter enrichment under the influence of tectono-sedimentary differentiation within the rift trough. The results are obtained in four aspects. First, the Qiongzhusi shales were deposited under a warm and humid climate with intense chemical weathering. From the extra-trough to the intra-trough settings, paleoproductivity and environmental restriction gradually increased, whereas terrigenous detrital input and redox potential progressively decreased. Moreover, hydrothermal activity intensity diminished from the trough margin toward the extra-trough and intra-trough areas. Second, vertically, layers 1 and 3, which remained under persistently high productivity and reducing conditions, exhibit the highest organic matter enrichment; layer 5 shows moderate enrichment due to a relatively short highstand period; layer 7, characterized by limited marine transgression, exhibits the lowest enrichment, attributed to reduced productivity, weakened reducing conditions, and enhanced dilution by terrigenous detritus and hydrothermal inputs. Third, the random forest model demonstrates a satisfactory performance in fitting the organic matter enrichment in black shales, revealing that it is primarily governed by paleoproductivity, secondarily by redox conditions, and to a lesser extent influenced by terrigenous detrital input and hydrothermal activity. Fourth, for organic-rich shale gas exploration, vertically, layers 1 and 3 hold greater exploration potential than layer 5; laterally, priority should be given to the central intra-trough area north of the middle segment of the trough. These findings contribute to a better understanding of the organic matter enrichment mechanisms in the Qiongzhusi Formation shales of the Sichuan Basin, and provide a geological theoretical basis for shale gas exploration and source rock evaluation.

To address the problem of high-precision microstructure identification in the deep No. 8 coal seam of the Ordos Basin, “elemental fingerprints” of the deep coal seam and its roof and floor strata were constructed, and measurement points along the horizontal well were mapped to their corresponding reference positions in the vertical profile of the pilot well, thereby enabling the identification of microstructural features along the horizontal section of deep coalbed methane horizontal wells. First, based on elemental logging data and constrained by the lithological framework, candidate elements were determined for distinguishing the coal seam from its roof and floor strata and for identifying different coal lithotypes. Then, the candidate elements were screened using the coefficient of variation to obtain the characteristic elements for microstructure identification. The concentrations of the characteristic elements were adjusted using Z-score normalization, and the combination of characteristic-element concentrations at the same measurement point was expressed as a vector, termed an “elemental fingerprint”. Subsequently, the elemental fingerprints of the pilot well were matched with those of the horizontal section to determine the vertical-profile positions and distributional variations of the horizontal section. Finally, horizontal-well drilling information was integrated to determine the locations and types of microstructures developed along the horizontal section, thereby guiding adjustments to the drilling direction of the bit. Field drilling and hydraulic-fracturing practices demonstrate that the elemental fingerprint-based microstructure identification method can accurately identify microstructural features (e.g. small-scale folds, superimposed faults, and tectonically disturbed zones) along the horizontal section, and provide technical support for the optimized design of drilling and hydraulic fracturing in deep coalbed methane horizontal wells.

Based on the geological characteristics of the JD reservoir-based underground gas storage (UGS) facility, two-dimensional visual plate physical models representing vertical and areal heterogeneity were constructed. UGS operation was experimentally simulated under two injection-production schemes. An experimental-scale compositional reservoir model was also developed to characterize the sweep patterns under different heterogeneity configurations and injection-production modes. The results show that the vertically heterogeneous model generally achieves higher oil displacement efficiency than the areally heterogeneous model. The relative sweep efficiencies of the two models depend on the injection-production scheme. Their difference is small after a single depressurization cycle, whereas the vertically heterogeneous model exhibits higher sweep efficiency after repeated depressurization cycles. Compared with a single cycle, repeated depressurization cycles increase the injection-production pressure difference and intensify cyclic flow perturbations. These effects weaken the persistent dominance of preferential flow pathways, promote fluid mobilization in medium- and low-permeability zones, and markedly improve sweep efficiency during UGS operation. Given vertical heterogeneity, increasing heterogeneity intensifies gravity segregation and interlayer channeling, suppresses the sweep into low-permeability zones, and reduces sweep efficiency. Given areal heterogeneity, by contrast, increasing heterogeneity enhances the flow conductivity of high-permeability zones and improves displacement effectiveness within the swept volumes, thereby increasing the overall sweep efficiency. Accordingly, stratified injection-production combined with graded pressure drawdown is recommended for vertically heterogeneous reservoirs to suppress channeling through high-permeability zones and improve the mobilization of low-permeability zones. For areally heterogeneous reservoirs, optimized well placement and zonal injection-production should be combined with multistage depressurization cycles to improve storage-capacity utilization efficiency and operational stability.

Taking the Fengshun hydrothermal geothermal field in the Cathaysian orogenic system as an example, this study incorporates orogenic belt background elements into geothermal system and geothermal prediction research, and establishes a genetic model for the Fengshun geothermal field. The results show that the Fengshun hydrothermal geothermal system exhibits favorable conditions in terms of heat source, water source, thermal reservoir, heat conduction channels, cap rock, and thermal preservation. The heat source and water source are well-matched, and the fault system aligns with the water circulation, resulting in orderly variations in the geochemical indicators of the hot springs. Granites are widely developed in the Fengshun area, and the heat source is buried at a relatively shallow depth, providing a stable heat supply for the formation of the geothermal field. Abundant water recharge, combined with a topographic relief of nearly 1 km between northwest (high) and southeast (low) and NW water-converging faults, contribute conducive conditions to an efficient groundwater recharge and long-distance deep circulation. Steeply dipping conjugate deep shear fault systems serve as high-efficiency pathways for vertical migration of geothermal fluids. Fractured granites developed along the fault zones, together with the Indosinian clastic rocks and volcaniclastic rocks, constitute the main geothermal reservoirs. The Jurassic mud-shales and tuffs, and the Quaternary clay layers provide excellent regional cap rocks. The Lianhuashan Fault zone, acting in concert with continuously distributed granite bodies, effectively impedes geothermal water flow, forming a “water-impounding structure”. This structural configuration promotes large-scale convergence of deep hydrothermal fluids and is the key to the sustained, constant-temperature, and high-yield production of the Dengwu geothermal field. The Fengshun hydrothermal geothermal enrichment model is characterized by heat generation/supply from deep granites, long-distance deep circulation of groundwater, heat and water conduction via shear faults, heat storage in fractures and sand bodies, insulation by fine-grained sedimentary cap rocks, and lateral shield by faults and granites. This model elucidates the genesis of medium- to high-temperature geothermal anomalies in orogenic belts and provides a theoretical reference for the prediction and exploration of geothermal resources in analogous regions.

This work addresses the challenge of fluid identification in complex low-porosity buried-hill reservoirs in the Bohai Sea by developing a fluid identification method based on the coupled responses of energy spectra and time spectra. First, a regularized spectral decomposition algorithm is employed to analyze pulsed neutron gamma-ray spectra and obtain the carbon-to-oxygen (C/O) yield ratio, enhancing the capability of quantitatively characterizing differences in oil and water responses under low-porosity conditions. Second, an oil-water identification method is established by integrating energy-spectrum and time-spectrum parameters, improving the accuracy of oil-water discrimination in complex lithological environments. Finally, a gas identification parameter is introduced to distinguish gas-bearing zones and fluid-bearing zones, which is then combined with the oil and water identification results to form a three-phase fluid identification workflow. Field applications in drilled wells penetrating buried-hill reservoirs in the Bohai Sea demonstrate that the proposed method significantly enhances the response contrast between oil-bearing zone and water-bearing zone under low-porosity conditions, substantially reduces the uncertainty of single-parameter interpretation, and enables accurate discrimination among oil, gas, and water. The method provides an effective solution for fluid identification in complex low-porosity buried-hill reservoirs in the Bohai Sea.

Considering that pressure wave wireless communication technology for water injection wells is limited in transmission success and efficiency, this study leverages the propagation characteristics of flow-rate disturbances throughout the entire pressurized pipeline system. Based on the fact that a pressured long-distance pipe flow system has “no loss” of flow rate, the transmission characteristics of flow waves within water injection pipelines were revealed through numerical analysis and experiments. Based on these characteristics, corresponding signal generation devices, high-precision flowmeters, and a hybrid signal encoding system for flow wave communication were developed. This led to the successful creation of a surface flow wave communication terminal and a downhole water distributor. Depending on field conditions, a signal transmission strategy adapted to the characteristics of flow waves was formulated. Integrated with surface 4G mobile communication technology, a bidirectional wireless communication system from the surface terminal to the downhole water distributor was constructed. Ultimately, a complete set of efficient, low-cost downhole wireless communication technology based on flow wave control and a corresponding flow wave-controlled layered water injection technology were formed. These technologies have been tested and applied in 17 wells in the Jilin Oilfield, verifying their technical feasibility, accuracy, and reliability, but also successfully addressing long-standing technical challenges hindering industry development, such as precise flow rate measurement for multiple downhole zones and simultaneous multi-layer measurement and regulation. This study provides a low-cost systematic solution for the digital transformation of layered water injection development.

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 and LS2. In the 10,000-meter-deep well SDTK1 in the Tarim Basin, matrix and fracture permeability curves of ultra-deep carbonate formations were obtained in a single downhole run. The results were immediately calibrated with the data of quasi-in-situ 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 ultra-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.

The hydrocarbon accumulation patterns of ultra-deep, marine shale in the northeastern Sichuan Basin remain unclear. Taking the Permian Dalong Formation in Well Tiebei 1 L-HF in the Puguang area, northeastern Sichuan Basin, as an example, this study integrated petrological, geochemical, and micro-scale characterization techniques to systematically reveal the enrichment mechanisms of primary organic matter and the reservoir-forming conditions of shale and establish the hydrocarbon micro-migration and accumulation model. The main findings are obtained in three aspects. First, three core lithofacies, i.e. siliceous, calcareous, and mixed shales, are identified vertically in the Dalong Formation. Siliceous shale, dominated by sapropelinite, possesses the optimal primary hydrocarbon-generating potential. Mixed shale exhibits the TOC (average 9.31%) exceeding that of the source siliceous shale (average 6.85%), indicating that the current organic matter distribution is controlled by late-stage hydrocarbon redistribution rather than solely by primary deposition. Second, a multi-scale cross-lithofacies composite pore-fracture system is identified. Siliceous shale provides basic storage space and horizontal transport; calcareous shale contains fractures in calcite veins, which act as migration “transfer stations”; and mixed shale develops tectonic tensile fractures and dissolution pores. Together, these elements support fluid conduction in ultra-deep settings. Third, the mechanism of “in-source enrichment and lithofacies-controlled migration” is confirmed for ultra-deep shale gas. Within an overpressure compartment, driven by hydrocarbon generation-induced overpressure, hydrocarbons undergo stepwise micro-migration along the siliceous shale (source) → calcareous shale (conduit) → mixed shale (sink) path, inducing short-distance fractionation and redistribution of components.

Intraplate small-displacement strike-slip faults cannot be accurately identified and analyzed by conventional techniques. To clarify the tectonic characteristics and deformation process of intraplate small-displacement strike-slip faults, structural physical simulation experiments were designed based on the geological conditions of the study area. Taking the Aman relay zone in the northern Tarim Basin as an example, laser scanning was adopted to elaborately and quantitatively analyze the deformation features and differences at each evolutionary stage. This study indicates that the deformation of the F_I17 fault zone in the Fuman Oilfield evolves in four stages: diffuse deformation, R-fracture, branched fault interconnection, and principal displacement zone (PDZ) connection. During the evolution of the fault zone, en echelon anticlines recorded a diagnostic marker for R-fracture, and their relief amplitude represents a vital parameter to classify evolutionary stages. A formation “Net Deformation Magnitude” method is proposed, which can effectively remove post-tectonic stratigraphic deformations irrelevant to strike-slip-related folds and extract fold geometries and relief amplitudes solely generated by syn-kinematic strike-slip faulting. This method further enables quantitative characterization of along-strike heterogeneities in deformation intensity and connectivity of strike-slip fault zones, thereby realizing integrated seismic-geological interpretation. Case study of the Aman relay zone demonstrates that the F_I17 fault zone is currently in the branched fault interconnection stage, characterized by alternating connected and disconnected segments along its strike. The findings establish a geological model for the refined interpretation of intraplate small-displacement strike-slip faults. Furthermore, the newly recognized fault-karst traps associated with R-fractures are expected to become promising new targets for hydrocarbon exploration.

Based on core samples, thin sections, well logging and seismic data of the Permian strata in western Sichuan Basin, China, this study investigates the controls of two stages of volcanism (Middle and Late Permian) on paleostructure and sedimentation, and further recognizes a long-neglected geomorphologic unit termed the Chengdu-Santai volcanic paleouplift. The results indicate that two sets of volcanic rocks are developed in the Permian succession in western Sichuan Basin. The lower set, the Maokou volcanic rocks, is dominated by basalt and volcanic breccia, and laterally onlapped by carbonate rocks ranging from the upper submember of the second member to the fourth member of the Maokou Formation. The upper set, the Longtan volcanic rocks, mainly consists of basalt and volcaniclastic rocks, which overlie either the Maokou volcanic rocks or the carbonate rocks of the fourth member of the Maokou Formation, and are laterally onlapped by the Longtan and Changxing Formations. Constrained by stratigraphic contact relationships, paleontological evidence and geochronological data, the eruption ages of the two volcanic sequences are determined to be the middle depositional stage of the Maokou Formation (263-265 Ma) and the early depositional stage of the Longtan Formation (259±1 Ma), respectively. Paleogeomorphological reconstruction indicates that volcanism during the middle Maokou period initiated the embryonic development of the paleouplift on the carbonate platform in western Sichuan Basin. Continuous vertical accumulation and lateral propagation of volcanic materials during the early Longtan period eventually formed a roughly elliptical paleouplift plunging toward the northeast. This paleouplift has a major axis of approximately 200 km extending northeastward and a minor axis ranging from 70 km to 110 km in the east-west direction. Its highest point is located in the area between Wells YS1 and YT1, with a maximum relative relief of 300 m. Affected by subsequent tectonic activities and sustained depositional filling, the paleouplift was completely eliminated during the depositional stage of the third member of the Feixianguan Formation. Generated jointly by the clockwise northward rotational drift of the South China Plate and mantle hotspot activity in the Permian, this volcanic paleouplift governed the paleogeographic framework across the central and western Sichuan Basin during its entire evolutionary history. It not only gave rise to the alternating distribution of multiple rows of shoal and depression belts in the middle-late deposition stages of the Maokou Formation, but also facilitated the development of high-energy facies belts surrounding the volcanic paleouplift during the sedimentary period of the Changxing Formation. This insight provides a brand-new perspective for Permian petroleum exploration in the Sichuan Basin, and further identifies the volcanic paleouplift and its adjacent areas as critical target zones for hydrocarbon exploration of the Maokou and Changxing Formations in the Sichuan Basin.

To understand the occurrence and migration mechanisms of helium in coal-measure gas, this study investigated anthracite from No. 3 coal seam of Lower Permian Shanxi Formation in the Jincheng mining area of the southern Qinshui Basin, China, through experiment analysis and molecular simulation. Firstly, low-temperature CO₂ and N₂ adsorption experiments were performed to characterize the multi-scale pore structure of anthracite, and accordingly, a 1-10 nm slit pore model of anthracite was constructed. Using grand canonical Monte Carlo, molecular dynamics and non-equilibrium molecular dynamics simulation methods, the effects of pore size, temperature, pressure, pore water, and associated gases (CO₂, CH₄, N₂, H₂) on helium adsorption, diffusion, and pressure-driven flow were systematically examined. The results show that helium exhibits weak enrichment near wall in nano-scale slit pores and coexistence of free gas at the pore center. Its interaction with coal wall is significantly weaker than those of CO₂, CH₄ and N₂, and is relatively close to that of H₂. Pore size, temperature and pressure all affect helium diffusion and flow behaviors. Smaller pores reduce helium diffusion coefficient and increase its viscosity, whereas larger pores facilitate helium migration. Pore water weakens continuous gas-phase pathways through film formation, permeation and interfacial friction, causing a sudden drop in helium diffusion coefficient at high water content stage. Strong adsorption of associated gases (CH₄ and CO₂) will further suppress helium diffusion, while H₂ as a lightweight carrier can enhance the diffusion ability of helium and H₂ itself to a certain extent. The research results provide theoretical references for understanding the microscopic occurrence and migration characteristics of helium in coal-measure gas.

To address the computational challenges of 3D non-planar fracture propagation near the wellbore during hydraulic fracturing, a hybrid numerical model based on the Displacement Discontinuity/Fictitious Stress Method (DDM/FSM) and Finite Volume/Finite Element Method (FVM/FEM) was developed, incorporating a dynamic mesh tracking technique for the fracture front. This 3D non-planar model, constrained by wellbore boundary conditions, was validated for accuracy and reliability, and subsequently used to analyze fracture morphology under stress shadow effects and its key controlling factors. The results indicate that fracture propagation is jointly governed by far-field stress and wellbore-fracture induced stress. Specifically, wellbore-induced stress dominates initiation and reorientation of fractures within three times the wellbore radius, while far-field stress dictates the direction beyond this range. Furthermore, initial fracture dip and fracture number significantly influence morphology: a larger angle between the fracture and the minimum principal stress increases the reorientation distance, whereas a higher number of initial fractures intensify differential propagation and localized reorientation behavior.

Based on data from cores, well logs, seismic profiles, and carbon isotopic compositions, this study constrains the chronostratigraphic framework using carbon isotopic excursion events and applies cyclostratigraphic methods to establish a high-resolution isochronous stratigraphic framework for the Permian Longtan Formation-Triassic Feixianguan Formation in the Sichuan Basin. Through single-well sedimentary evolution analysis and well-seismic integration, the sedimentary characteristics and the patterns and petroleum geologic significance of carbonate platform evolution during the deposition of the Longtan Formation-Feixianguan Formation are systematically revealed. The results show that the Longtan Formation-Feixianguan Formation exhibits 19 to 22 long eccentricity cycles across the entire basin. The difference in cycle counts is attributed to the significant local absence of the top part of the Permian Changxing Formation. Sedimentation rates gradually increase from the southwest to the northeast of the basin. The sedimentary system is overall controlled by a “high productivity, high supply” background, and jointly influenced by sea-level changes and terrigenous input. The Changxing Formation shows progradational ramp characteristics locally, while the Longtan Formation- Feixianguan Formation presents a carbonate ramp sedimentary model. The “tectonics-climate-astronomy” multi-level synergistic driving mechanism governed carbonate platform development, the regional tectonic setting established the macro-paleogeographic framework and accommodation space configuration for carbonate platform development, while the rhythmic sedimentary infilling and the production intensity of carbonate factories were significantly modulated by paleoclimate and astronomical signals. The three factors exhibited stage-wise synergistic evolution in time and space, collectively driving the formation, development, and demise of carbonate platforms. This study provides a new sedimentary model and basis for an in-depth understanding of sedimentary characteristics and carbonate platform evolution patterns during the Permian-Triassic transition in the Sichuan Basin.

Reservoirs of the 4^th member of the Sinian Dengying Formation (Deng-4 Member) around the Deyang-Anyue intraplatform rift in the Sichuan Basin are highly heterogeneous, alongside with unclear genesis and distribution of high-quality reservoirs. This study investigates the reservoirs of the Deng-4 Member in the Ningqiang area in the northern segment of the rift, and compares them with those in the Penglai area in the central segment and the Central Sichuan paleouplift in the southern segment. Three key insights are obtained. First, the Deng-4 reservoirs are facies-controlled, with stromatolite, framework, and thrombolite dolomites serving as the main carriers of reservoir space. The preservation of pores was mainly controlled by early dolomitization, acid generation from microbial organic matter, a burial history characterized by prolonged shallow burial followed by late-stage accelerated deep burial, and early hydrocarbon charging. Second, the reservoirs show a differential pattern of development. The rimmed platform-margin reservoirs in the southern and northern parts of the rift have better potential than the extensional fault-step platform-margin reservoirs in the central part of the rift. The mode of prolonged shallow burial followed by late-stage accelerated deep burial in the northern part of the rift is more conducive to the preservation of pores compared to the mode of continuous and uniform burial in the central and southern areas. Third, during the deposition of the lower-upper Deng-4 Member, the platform-margin microbial mound-shoal complex prograded from east to west perpendicularly to the facies belt, and migrated from south to north parallelly to the facies belt. The lower Deng-4 reservoirs are mainly distributed in the central and southern parts, the middle Deng-4 reservoirs in the central part, and the upper Deng-4 reservoirs in the Langzhong-Wangcang area the central and northern parts. These insights reveal that the Langzhong-Wangcang area in the northern part of the rift, like the Central Sichuan paleouplift in the southern part and the Penglai area in the central part, has great potential of reservoir development in the Deng-4 Member.

Based on data including seismic interpretation, well logs and core slice, analyses were conducted on seismic reflection patterns, stages and distribution of faults, planar distribution of sedimentary facies, types of reservoir spaces, and genesis of reservoirs. This study identified the types of Ordovician platforms in the Manxi area of the Tarim Basin, analysed the controlling factors for high-quality reservoirs and hydrocarbon accumulation, established an accumulation model, and proposed potential exploration targets. The research indicates that the Ordovician in the Manxi area is characterized by a rimmed platform depositional system, where the platform-margin reef-shoal complexes cover an area of approximately 5 091 km². These complexes, superimposed with multi-stage karstification and reticulated fractures, form high-quality fracture-cavity reservoirs, which exhibit a north-south orientation, large-scale distribution, and excellent storage capacity. The Ordovician platform-margin reef-shoal zone is situated within the hydrocarbon-generation center comprising the source rocks in the Precambrian Yuman rift trough, the Yuertusi Formation, and the Cambrian to Ordovician platform-margin foreslope facies. Large-scale hydrocarbon-enriched zones are densely distributed in a north-south trend within the interval from the Penglaiba Formation to the third member of the Yingshan Formation, while exhibiting a linear distribution pattern from the second member of the Yingshan Formation to the Yijianfang Formation. Guided by these insights, Well Qingyu 2 was drilled, and it achieved a high flow rate of 105.6×10⁴ m³/d gas from the second member of the Yingshan Formation during test, with a stable tubing pressure of 107 MPa. This records a significant breakthrough in the Ordovician platform-margin zones in the Manxi area, and reveals a new domain for reserve growth. The research results provide valuable guidance for exploring ultra-deep carbonate reservoirs in the Tarim Basin.

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.

Centering on the critical bottlenecks in the development of shale oil in the Jiyang Depression, Shengli Oilfield, key scientific and engineering issues are proposed in aspects such as the storage space and occurrence state of shale oil, the formation mechanism of multi-scale flow spaces, the mobilization mechanism of crude oil in pores and fractures, and 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, optimize the testing conditions, and develop 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 shales of the Jiyang Depression; depict the characteristics of “restricted vertical expansion and complex fracture network” 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.

To address the challenges of complex fluvial sandbody distribution and difficult remaining oil recovery in mature continental oilfields, this study focuses on key issues such as ambiguous narrow-channel boundaries and subdivision of multi-stage superimposed sandbodies. Taking the Upper Cretaceous continental sandstone in the Sazhong Oilfield of the Daqing Placanticline as an example, a technical system integrating azimuth-preserved high-resolution processing, multi-attribute fusion, and variable-scale inversion was developed to establish a complete workflow from seismic processing to reservoir prediction and remaining oil recovery. The following results are obtained. First, the OVT seismic processing technology is extended, for the first time, from fracture imaging to sandbody prediction, in order to address the weak seismic responses from boundaries of narrow and thin sandbodies. A geology-oriented OVT partitioning method is developed to significantly improve the imaging accuracy, enabling identification of channel sandbodies as narrow as 50 m. Second, an amplitude-coherence dual-attribute fusion method is proposed for predicting narrow channel boundaries between wells. Constrained by a sedimentary unit-level sequence chronostratigraphic framework, this method accurately delineates 800-2 000 m long subaqueous distributary channels with bifurcation-convergence features. Third, considering the superimposition of multi-stage channels, a three-level variable-scale stratigraphic model (sandstone groups: 8-10 m; sublayers: 4-5 m; sedimentary units: 2-5 m) is constructed to overcome single-scale modeling limitations, successfully characterizing key sedimentary features like meandering river “cut-offs” through 3D inversion. Based on these advances, a direct link between seismic prediction and remaining oil recovery is established. Horizontal wells deployed using narrow-channel predictions encountered oil-bearing sandstones in the horizontal section by 97%, and achieved initial daily production of 12.5 t per well. Precise identification of individual channel boundaries within 17 composite sandbodies guided recovery processes in 135 wells, yielding an average daily increase of 2.8 t per well and a cumulative increase of 136 000 tons.

The forward model of optical fiber strain induced by fractures, together with the associated model resolution matrix, is used to demonstrate the interpretability of fracture parameters once the fracture intersects the fiber. A regularized inversion framework for fracture parameters is established to evaluate the influence of measured data quality on the accuracy of iterative regularized inversion. An interpretation approach for both fracture width and height is proposed, and the synthetic forward data with measurement error and field examples are employed to validate the accuracy of the simultaneous inversion of fracture width and height. The results indicate that, after the fracture contacts the fiber, the strain response is strongly sensitive only to the fracture parameters at the intersection location, whereas the interpretability of parameters at other locations remains limited. The iterative regularized inversion method effectively suppresses the impact of measurement error and exhibits high computational efficiency, showing clear advantages for inversion applications. When incorporating the first-order regularization with a Neumann boundary constraint on the tip width, the inverted fracture-width distribution becomes highly sensitive to fracture height; thus, combined with a bisection strategy, simultaneous inversion of fracture width and height can be achieved. Examination using the model resolution matrix, noisy synthetic data, and field data confirms that the iterative regularized inversion model for fracture width and height provides high interpretive accuracy and can be applied to the calculation and analysis of fracture width, fracture height, net pressure and other parameters.

Based on the survey of saline lacustrine shales in the Permian Lucaogou Formation and Fengcheng Formation in the Junggar Basin, it is found that the sweet intervals of these shale oil strata are enriched with lithium—an underexplored resource with significant potential. The sedimentary environment, depositional process, and geochemical characteristics of these intervals were analyzed, indicating that lithium enrichment in saline lacustrine shale is controlled by multiple factors during deposition and diagenesis. The salinity of lake water during sedimentation plays a key role in lithium accumulation, while clastic input reduces its concentration, and diagenesis further affects its distribution. To assess the potential for lithium co-production in shale oil development, future research should focus on the distribution of lithium and hydrocarbons in lacustrine shales and the economic feasibility of an “oil-lithium integrated sweet spot”. Furthermore, efficient lithium extraction and environmental protection technologies need to be explored to optimize resource development. Saline lacustrine shale oil development not only ensures stable oil and gas supplies but also, if lithium co-production is realized, could enhance China’s lithium security, contributing significantly to the country’s energy transformation.

The well deployment under the guidance of the ramp model in the Ordovician Yingshan Formation in the Gucheng area of the Tarim Basin focuses on the inner ramp in the western part of the study area, which results in a low drilling success rate and an exploration predicament. To address these issues, this study focused on reconstructing sedimentary models and the adjustment strategies for oil and gas exploration. The carbonate sedimentary model of the Yingshan Formation was re-evaluated using the data of seismic interpretation, core observations, thin-section analyses, carbon isotope composition, well logging, detrital zircon U-Pb dating, and carbonate mineral U-Pb dating. Then, the favorable sedimentary facies belts were delineated, and updated prospective exploration targets were proposed. The results demonstrate that the sedimentary model of the Yingshan Formation in the Gucheng area is characterized as a rimmed platform system, exhibiting an orderly west-to-east sedimentary sequence transition from restricted/open platform environments through the platform margin and slope settings, ultimately grading into basinal deposits. The platform margin, distinguished by thick successions of grain shoals overlain by interlayered karst zones. It is the most favorable distribution area for large-scale reservoirs. Guided by this revised sedimentary model, Well Gutan-1 was successful drilled within the outer platform margin, encountering over 90% high-energy grain shoal facies with well-developed porous and fractured-vuggy reservoirs. Through oil testing, it has successfully obtained industrial oil and gas flow. It is confirmed that the platform margin is the priority area for oil and gas exploration in the Ordovician System of the Gucheng area, thereby effectively ending the prolonged exploration stagnation in the Yingshan Formation of the Gucheng area.

The faults and associated fracture zones in the tight sandstone reservoirs of the fifth member of the Triassic Xujiahe Formation (Xu-5 Member) in the Wubaochang area, northeastern Sichuan Basin, play a critical role in controlling gas well productivity. To delineate the distribution patterns of faults and associated fracture zones in this area, a transfer-trained convolutional neural network (CNN) model and an XGBoost-based intelligent seismic attribute fusion method were employed to identify faults and fracture zones, respectively, enabling precise characterization of their spatial distribution. The faults in the Wubaochang area are classified into first- to fourth-order structures, with the average fracture zone width on the hanging wall exceeding that of the footwall, demonstrating a strong positive correlation between fracture zone width and fault displacement. The study area is subdivided into three distinct deformation regions (southern, central, and northern regions) featuring five fault structural styles (imbricate thrust, imbricate-backthrust, duplex, composite syncline imbricate-backthrust, and composite anticline imbricate-backthrust) and four corresponding fracture zone development patterns (imbricate thrust, imbricate-backthrust, composite syncline imbricate-backthrust, and composite anticline imbricate-backthrust). Based on the controlling effects of faults on gas enrichment, the dual-source hydrocarbon-generating zones are interpreted to be predominantly distributed in the northern and central regions, while the southwestern and southeastern sectors are identified as fault-induced gas-escape zones. By integrating the distribution of favorable reservoir development areas and fracture zones, two classes of gas enrichment zones (ClassⅠand Ⅱ) are delineated. ClassⅠzones are primarily distributed in the northern region and the transitional zone from the southern to central regions, whereas Class Ⅱ zones are concentrated in the central region. ClassⅠzones exhibit dual-source hydrocarbon-generation conditions, larger-scale fracture zone development, and higher favorability compared to Class Ⅱ zones. Analysis of local stress fields and drilling fluid loss data indicates that within ClassⅠzones, fault-controlled fold-related fracture zones demonstrate higher effectiveness, whereas fault-controlled fracture zones dominate in Class Ⅱ zones. A high-productivity gas well model for the Wubaochang area is proposed, emphasizing “dual-source faults controlling enrichment, effective fracture zones controlling high production, and high matrix porosity ensuring sustained production”. Targeted drilling directions for different favorable zones are further optimized based on this model.

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 whole petroleum system specialized by continuous and orderly accumulations, with more unconventional resources than conventional resources, in which high-quality source rocks of Chang 7 member serve as the core and low-permeability unconventional oil reservoirs are dominant. 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 sedimentary filling core 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 drive → buoyancy or overpressure and capillary force, the reservoir scale changes from extensive billions of tons to a dispersed hundreds thousands-million tons, and the gas-oil ratio and methane content decrease. Third, the sedimentary structure provides the material basis and spatial framework for the whole petroleum system, the superimposed sand body, fault and unconformity control the dominant migration pathway of hydrocarbons in the far-source conventional hydrocarbon accumulation domain and the transitional hydrocarbon accumulation domain, the quality of source rocks and the micro-nano pore throat-fracture network play the key roles in the intra-source accumulation of shale oil, and 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 under negative pressure in post-pool-forming stage. The long-term preservation of the system depends on the coordination among three factors (stable geological structure, multi-cycle sedimentary textures, and dual self-sealing). Fourth, the whole petroleum system model is defined as four domains, overpressure + negative pressure drive, and dual self-sealing.

Particle image velocimetry technology was employed to investigate the planar three-dimensional velocity field and the mechanisms of proppant entry into branch fractures in a 90° intersecting fracture configuration of “vertical main fracture-vertical branch fracture”. This study analyzed the effects of pumping rate, fracturing fluid viscosity, proppant particle size, and fracture width on the transport behavior of proppant into branch fractures. Based on the deflection behavior of proppant, the main fractures can be divided into five regions: pre-entry transition, pre-entry stabilization, deflection entry at the fracture mouth, rear absorption entry, and movement away from the fracture mouth. Proppant primarily deflects into the branch fracture at the fracture mouth, with a small portion drawn in from the rear of the intersection. Increasing the pumping rate, reducing the proppant particle size, and widening the branch fracture are conducive to promoting proppant deflection into the branch. With increasing fracturing fluid viscosity, the ability of proppant to enter the branch fracture first improves and then declines, indicating that excessively high viscosity is unfavorable for proppant entry into the branch. During field operations, a high pumping rate and micro- to small-sized proppant can be used in the early stage to ensure effective placement in the branch fractures, followed by medium- to large-sized proppant to ensure adequate placement in the main fracture and enhance the overall conductivity of the fracture network.

Based on the Low Frequency Distributed Acoustic Sensing (LF-DAS) fiber optic monitoring and downhole hawk-eye imaging results, the fluid and proppant distribution and perforation erosion of all clusters during hydraulic fracturing were evaluated, and then a fully coupled wellbore-perforation-fracture numerical model was established to simulate the whole process of slurry migration and analyze key influencing factors. The results show that the proppant and fracturing fluid exhibit divergent flow pathways during multi-staged, multi-cluster fracturing in horizontal wells, resulting in significant heterogeneity in the fluid-proppant distribution among clusters. Perforation erosion is prevalent, and perforation erosion and proppant distribution have phase bias. Notably, the trajectory of proppant transport is controlled by the combined effects of inertia of particle migration and gravity settlement. The inertial effect is dominant at the wellbore heel, where the fluid flow rate is high, hindering particles turning into perforations and causing uneven proppant distribution among clusters. On the other hand, gravity settlement is more pronounced toward the wellbore toe, where the fluid flow rate is low, leading to enhanced phase-bias of slurry distribution and perforation distribution/erosion. Increasing the pumping rate reduces the influence of gravity settlement, mitigating the phase bias of proppant distribution and perforation erosion. However, the large pumping rate limits the proppant distribution efficiency near the heel clusters, and more proppants accumulate towards the toe clusters. High-viscosity fluids improve particle suspension, achieving more uniform proppant distribution within wellbore and fractures. Larger particle sizes exacerbate proppant distribution differences among clusters and perforations, limiting the proppant placement range within fractures.

In the ultra-deep strata of the Tarim Basin, the vertical growth process of strike-slip faults remains unclear, and the vertical distribution of fractured-cavity carbonate reservoirs is complex. This paper investigates the vertical growth process of strike-slip faults through field outcrop observations in the Keping area, interpretation of seismic data from the Fuman oilfield, and physical simulation experiments. The result are obtained mainly in four aspects. First, field outcrops and ultra-deep seismic profiles indicate a three-layer structure within the strike-slip fault, consisting of fault core, fracture zone, and primary rock. The fault core can be classified into three parts vertically: fracture-cavity unit, fault clay, and breccia zone. The distribution of fracture-cavity units demonstrates a distinct pattern of vertical stratification, owing to the structural characteristics and growth process of the slip-strike fault. Second, the ultra-deep seismic profiles show multiple fracture-vuy units in the strike-slip fault zone. These units can be classified into four types: top fractured, middle connected, deep terminated, and intra-layer fractured. Third, physical simulation experiments and ultra-deep seismic data interpretation reveal that the strike-slip faults have evolved vertically in three stages: segmental rupture, vertical growth, and connection and extension. The particle image velocimetry (PIV) detection demonstrates that the initial fracture of the fault zone occurred at the top or bottom and then evolved into cavities gradually along with the fault growth, accompanied by the emergence of new fractures in the middle part of the strata, which subsequently connected with the deep and shallow cavities to form a complete fault zone. Fourth, the ultra-deep carbonate strata primarily develop three types of fractured-cavity reservoirs: large and deep fault, flower-shaped fracture, and staggered overlap. The first two types are larger in size with better reservoir conditions, suggesting a significant exploration potential.

Lacustrine shale oil in China exhibits a huge resource potential but a highly heterogeneous distribution. Deciphering its intra-source micro-migration and enrichment mechanisms is crucial for accurately predicting geological sweet spots. Taking the Chang7₃ submember of the Yanchang Formation in the Ordos Basin as an example, we integrated high-resolution scanning electron microscopy (SEM), optical microscopy, laser Raman spectroscopy, rock pyrolysis, and organic solvent extraction experiments to identify solid bitumen of varying origins, obtain direct evidence of intra-source micro-migration of shale oil, and establish the coupling between the shale nano/micro-fabric and the oil generation, micro-migration and accumulation. The results show that the Chang7₃ shale with rich alginite in laminae has the highest hydrocarbon generation potential but a low thermal transformation ratio. Frequent alternations of micron-scale argillaceous-felsic laminae enhance expulsion efficiency, yielding consistent aromaticity between in-situ and migrated solid bitumen. Argillaceous laminae rich in terrestrial organic matter (OM) and clay minerals exhibit lower hydrocarbon generation threshold but stronger hydrocarbon retention capacity, with a certain amount of light oil/bitumen preserved to differentiate the chemical structure of in-situ versus migrated bitumen. Tuffaceous and sandy laminae contain abundant felsic minerals and migrated solid bitumen. Tuffaceous laminae develop high-angle microfractures under shale overpressure, facilitating oil charging into rigid mineral intergranular pores of sandy laminae. Fractionation during micro-migration progressively decreases the aromaticity of solid bitumen from shale, through tuffaceous and argillaceous, to sandy laminae, while increasing light hydrocarbon components and enhancing OM-hosted pore development. The intra-source micro-migration and enrichment of the Chang7₃ shale oil result from synergistic organic-inorganic diagenesis, with compositional fractionation being a key mechanism for forming laminated sweet spots.

Based on the coalbed methane (CBM)/coal-rock gas (CRG) geological, geophysical, and experimental testing data from the Daji block in the Ordos Basin, the coal-forming and hydrocarbon generation & accumulation characteristics across different zones were dissected, and the key factors controlling the differential CBM/CRG enrichment were identified. The No. 8 coal seam of the Carboniferous Benxi Formation in the Daji block is 8-10 m thick, typically overlain by limestone. The primary hydrocarbon generation phase occurred during the Early Cretaceous. Based on the differences in tectonic evolution and CRG occurrence, and with the maximum vitrinite reflectance of 2.0% and burial depth of 1 800 m as boundaries, the study area is divided into deeply buried and deeply preserved, deeply buried and shallowly preserved, and shallowly buried and shallowly preserved zones. The deeply buried and deeply preserved zone contains gas content of 22-35 m³/t, adsorbed gas saturation of 95%-100%, and formation water with total dissolved solid (TDS) ˃50 000 mg/L. This zone features structural stability and strong sealing capacity, with high gas production rates. The deeply buried and shallowly preserved zone contains gas content of 16-20 m³/t, adsorbed gas saturation of 80%-95%, and formation water with TDS of 5 000-50 000 mg/L. This zone exhibits localized structural modification and hydrodynamic sealing, with moderate gas production rate. The shallowly buried and shallowly preserved zone contains gas content of 8-16 m³/t, adsorbed gas saturation of 50%-70%, and formation water with TDS <5 000 mg/L. This zone experienced intense uplift, resulting in poor sealing and secondary alteration of the primary gas reservoir, with partial adsorbed gas loss, and low gas production rate. Based on these findings, a depositional unification and structural divergence model is proposed, that is, although coal seams across the basin experienced broadly similar depositional and tectonic histories, differences in tectonic intensity have led to spatial heterogeneity in the maximum burial depth (i.e., thermal maturity of coal) and current structural configuration (i.e., gas content and occurrence state). The research results provide valuable guidance for advancing the theoretical understanding of CBM/CRG enrichment and for improving exploration and development practices.

The Mid-Permian geomorphic transition in the Sichuan Basin is critical for understanding the development of large-scale reservoir facies belts in the Maokou Formation. This study reconstructed the paleo-uplift and depression differentiation patterns within the sequence stratigraphic framework of the Maokou Formation and investigated its tectono-sedimentary mechanisms based on analysis of outcrops, loggings and seismic data. The results show that the Maokou Formation comprises two third-order sequences (SQ1 and SQ2), six fourth-order sequences (SSQ1-SSQ6), and four distinct slope-break zones developing progressively from north to south. Slope-break zones I-III in the northern basin, controlled by synsedimentary normal faults, exhibited a NE-trending linear distribution and gradual southeastward migration. In contrast, slope-break zone IV in the southern basin displayed an arcuate distribution along the Emeishan Large Igneous Province (ELIP). The evolutions of these multistage slop-break zones governed the Middle Permian paleogeomorphic transformations from a giant, north-dipping gentle slope (higher in the southwest than in the northeast) in the early-stage (SSQ1-SSQ2) to a platform (south)-basin (north) pattern in the middle-stage (SSQ3-SSQ5), culminating a further depression zone in the southwestern basin to construct a paleo-uplift sandwiched by two depressions during the late-stage (SSQ6). The developments of paleogeomorphy reflected the combined control by the rapid subduction of the Paleo-Tethyan Mianlue Ocean and the episodic eruptions of the Emeishan mantle plume (or hot spots), which jointly facilitated the formation of extensive high-energy shoal facies belts along slope-break zones and around paleo-volcanic uplifts.

Based on previously published data from natural gas samples across spring water systems and sedimentary basins (e.g. Songliao, Bohai Bay, Sanshui, Sichuan, Ordos, Tarim, and Yingqiong), this paper systematically compares the geochemical and isotopic characteristics of abiogenic versus biogenic gases. Emphasis is placed on the diagnostic signatures of abiogenic alkane gases in terms of gas composition, and carbon, hydrogen and helium isotopes. The main findings are as follows. (1) In hydrothermal spring systems, abiogenic alkane gases are extremely scarce. Methane concentrations are typically less than 1%, with almost no detectable C₂₊ hydrocarbons. The gas is dominantly composed of CO₂, while N₂ is the major component in a few samples. (2) Abiogenic alkane gases display distinct isotopic signatures, including enriched methane carbon isotopes (δ¹³C₁>-25‰ generally), complete carbon isotopic reversal (δ¹³C₁>δ¹³C₂>δ¹³C₃>δ¹³C₄), and enriched helium isotope (R/R_a>0.5, CH₄/³He<10¹⁰ generally). (3) The hydrogen isotopic composition of abiogenic alkane gases may be characterized by a positive sequence (δD₁<δD₂<δD₃), or a complete reversal (δD₁>δD₂>δD₃), or a V-shaped distribution (δD₁>δD₂<δD₃). The hydrogen isotopic compositions of methane generally show limited variation (about 9‰), possibly due to isotopic exchange with formation water. (4) In identifying gas origin, CH₄/³He-R/R_a and δ¹³C_CO2-R/R_a charts are more effective than CO₂/³He-R/R_a chart. These new geological insights provide theoretical clues and diagnostic charts for genetic identification of natural gas and further research on abiogenic gases.

Currently, unconventional reservoirs are characterized by low single well-controlled reserves, high initial production, and fast production decline. This paper sorts out the problems of energy dispersion and limited length and height of main hydraulic fractures induced in staged multi-cluster fracturing, and proposes an innovative concept of “energy-focused fracturing (EFF)”. The technical connotation, theoretical model, and core techniques of EFF are systematically examined, and the implementation path of this technology is determined. The EFF technology incorporates the techniques such as geology-engineering integrated design, perforation optimization design, fracturing process design, and drainage engineering control. It transforms the numerous, short and dense artificial fractures to limited, long and sparse fractures. It focuses on fracturing energy, and aims to improve the fracture length, height and lateral width, and the proppant long-distance transportation capacity, thus enhancing the single well-controlled reserves and development effect. The EFF technology has been successfully applied in the carbonate reservoirs in the Yangshuiwu buried hill, shallow coalbed methane reservoirs, and coal-rock gas reservoirs in China, demonstrating the technology’s promising application. It is concluded that the EFF technology can significantly increase the single well production and estimated ultimate recovery (EUR), and will be helpful for efficiently developing low-permeability, unconventional and low-grade resources in China.

Guided by the fundamental principles of the whole petroleum system, the controls of tectonism, sedimentation, and diagenesis on hydrocarbon accumulation in a fault basin is studied using the data of petroleum geology and exploration of the second member of the Paleogene Kongdian Formation (Kong-2 Member) in the Cangdong Sag, Bohai Bay Basin, China. It is clarified that the circle structure and circle effects are the marked features of a continental fault petroleum basin, and they govern the orderly distribution of conventional and unconventional hydrocarbons in the whole petroleum systems of the fault basin. Tectonic circle zones control sedimentary circle zones, while sedimentary circle zones and diagenetic circle zones control the spatial distribution of favorable reservoirs, thereby determining the hydrocarbon accumulation orderly distribution of reservoir types in various circles. A model for the integrated, systematic aggregation of conventional and unconventional hydrocarbons under a multi-circle structure of the whole petroleum system of continental fault basin has been developed. It reveals that each sub-basin of the fault basin is an independent whole petroleum system and circle system, which encompasses multiple orderly circles of conventional and unconventional hydrocarbons controlled by the same source kitchen. From the outer circle to the middle circle and then to the inner circle, there is an orderly transition from structural and stratigraphic reservoirs, to lithological and structural-lithological reservoirs, and finally to tight oil/gas and shale oil/gas enrichment zones. The significant feature of the whole petroleum system is the orderly control of hydrocarbons by multi-circle stratigraphic coupling, with the integrated, orderly distribution of conventional and unconventional reserves being the inevitable result of the multi-layered interaction within the whole petroleum system. This concept of multi-circle stratigraphic coupling for the orderly, integrated accumulation of conventional and unconventional hydrocarbons has guided significant breakthroughs in the overall, three-dimensional exploration and shale oil exploration in the Cangdong Sag.

Accurate identification of natural gas origin is fundamental to exploration deployment and resource potential assessment. Since the 1970s, Academician Dai Jinxing has developed a comprehensive system for natural gas origin determination, grounded in geochemical theory and practice, and based on the integrated analysis of stable isotopes, molecular composition, light hydrocarbon fingerprints, and geological context. This paper systematically reviews the core framework established by him and his team, focusing on the conceptual design and technical pathways of key diagnostic diagrams such as δ¹³C₁-C₁/(C₂+C₃), δ¹³C₁-δ¹³C₂-δ¹³C₃, δ¹³C-CO₂ versus CO₂ content, and the C₇ light hydrocarbon triangular plot. We evaluate the applicability and innovation of these tools in distinguishing between oil-type gas, coal-derived gas, biogenic gas, and abiogenic gas, as well as in identifying mixed-source gases and multiphase charging systems. The findings suggest that this diagnostic system has significantly advanced natural gas geochemical interpretation in China, shifting from single-indicator analyses to multi-parameter integration and from qualitative assessments to systematic graphical identification, and has also exerted considerable influence on international research in natural gas geochemistry. This review aims to provide a structured overview of the development trajectory of natural gas origin discrimination methodologies and offer a scientific foundation for the academic evaluation and practical application of related achievements.

Taking the Wangfu Rift in the Songliao Basin as an example, on the basis of seismic interpretation and drilling data analysis, the distribution of the basement faults was clarified, the fault activity periods of the coal-bearing formations were determined, and the fault systems were divided. Combined with the coal seam thickness and actual gas indication in logging, the controls of fault systems in the rift basin on the spatial distribution of coal and the occurrence of coal-rock gas were identified. The results show that the Wangfu Rift is an asymmetrical graben formed under the control of basement reactivated strike-slip T-rupture, and contains coal-bearing formations and five sub-types of fault systems under three types. The horizontal extension strength, vertical activity strength and tectono-sedimentary filling difference of basement faults control vertical stratigraphic sequences, accumulation intensity, and accumulation frequency of coal seam in rift basin. The structural transfer zone formed during the segmented reactivation and growth of the basement faults control the injection location of steep slope exogenous clasts. The filling effect induced by igneous intrusion accelerates the sediment filling process in the rift lacustrine area. The structural transfer zone and igneous intrusion together determine the preferential accumulation location of coal seams in the plane. The faults reactivated at the basement and newly formed during the rifting phase serve as pathways connecting to the gas source, affecting the enrichment degree of coal-rock gas. The vertical sealing of the faults was evaluated by using shale smear factor (SSF), and the evaluation criteria was established. It is indicated that the SSF is below 1.1 in major coal areas, indicating favorable preservation conditions for coal-rock gas. Based on the influence factors such as fault activity, segmentation and sealing, the coal-rock gas accumulation model of rift basin was established.

In the late 1970s, the theory of coal-formed gas began to take root, sprout, develop, and improve in China. After decades of development, a complete theoretical system was finally formed. The theory of coal-formed gas points out that coal measures are good gas source rocks, with gas as the main hydrocarbon generated and oil as the auxiliary. It has opened up a new exploration idea using coal-bearing humic organic matter as the gas source, transforming the theoretical guidance for natural gas exploration in China from “monism” (i.e. oil-type gas) to “dualism” (i.e. coal-formed gas and oil-type gas) and uncovering a new field of natural gas exploration. Before the establishment of the coal-formed gas theory, China was a gas-poor country with low proven reserves (merely 2 264.33×10⁸ m³) and production (137.3×10⁸ m³/a), corresponding to a per capita annual consumption of only 14.37 m³. Guided by the theory of coal-formed gas, China’s natural gas industry has developed rapidly. By the end of 2023, China registered a cumulative proven gas geological reserves of 20.90×10¹² m³, an annual gas production of 2 343×10⁸ m³, and a per capita domestic gas consumption reaching 167.36 m³. The cumulative proven geological reserves and production of natural gas were dominated by coal-formed gas. Owing to this advancement, China has transformed from a gas-poor country to the fourth largest gas producer in the world. The coal-formed gas theory and the tremendous achievements made in natural gas exploration in China under its guidance have been highly praised by renowned scholars globally.

Based on the comprehensive analysis of data from petrology, well logging, seismic surveys, paleontology, and geochemistry, a detailed research was conducted on the tectonic-sedimentary setting, and paleoenvironmental and paleoclimatic conditions of the source rocks in the second member of the Eocene Wenchang Formation (Wen 2 Member) in the Shunde North Sag at the southwestern margin of the Pearl River Mouth Basin. The Wen 2 Member hosts excellent, thick lacustrine oil shales with strong longitudinal heterogeneity and an average total organic carbon (TOC) content of over 4.9%. The Wen 2 Member can be divided into three units (I, II, III) from bottom to top. Unit I features excellent source rocks with Type I organic matters (average TOC of 5.9%) primarily sourced from lake organic organisms; Unit II hosts source rocks dominated by Type II₂ organic matters (average TOC of 2.2%), which are originated from mixed sources dominated by terrestrial input. Unit III contains good to excellent source rocks dominated by Type II₁ organic matters (average TOC of 4.9%), which are mainly contributed by lake organisms and partially by terrestrial input. Under the background of rapid subsidence and limited source supply during strong fault depression, excellent source rocks were developed in Wen 2 Member in the Shunde North Sag under the coordinated control of warm and humid climate, volcanic activity, and deep-water reducing conditions. During the deposition of Unit I, the warm and humid climate and volcanic activity promoted the proliferation of lake algaes, primarily Granodiscus, resulting in high initial productivity, and deep-water reducing conditions enabled satisfactory preservation. These factors jointly controlled the development and occurrence of excellent source rocks. During the deposition of Unit II, a transition from warm to cool and semi-arid paleoclimatic conditions led to a decrease in lake algaes and initial productivity. Additionally, enhanced terrestrial input and shallow-water, weakly oxidizing water conditions caused a significant dilution and decomposition of organic matters, degrading the quality of source rocks. During the deposition of Unit III, when the paleoclimatic conditions are cool and humid, Pediastrum and Botryococcus began to thrive, leading to an increase in productivity. Meanwhile, the reducing environment of semi-deep water facilitated the preservation of excellent source rocks, albeit slightly inferior to those in Unit I. The study results clarify the differential origins and development models of various source rocks in the Shunde Sag, offering valuable guidance for evaluating source rocks and selecting petroleum exploration targets in similar marginal sags.

Based on the basic data of drilling, logging, testing and geological experiments, the geological characteristics of the Permian Dalong Formation marine shales in the Sichuan Basin and the factors controlling shale gas enrichment and high yield in these shales are studied. The results are obtained in four aspects. First, the high-quality shale of the Dalong Formation was formed after the deposition of the Wujiaping Formation, and it is mainly developed in the Kaijiang-Liangping trough in the northern part of Sichuan Basin, where deep-water continental shelf facies and deep-water reduction environment where siliceous organisms flourished have formed the black siliceous shale rich in organic matter. Second, the Dalong Formation shale contains both organic and inorganic pores, with stratification of alternating brittle and plastic minerals, which was stacked with severe compaction to enlarge the fractures, thereby improving the permeability. In addition to organic pores, a large number of inorganic pores are developed even in the ultra-deep (˃4 500 m) layers, contributing a total porosity of more than 5% and a permeability of 0.2×10^-3 μm², which significantly expands the accommodation space for shale gas. Third, the limestone at the roof and floor of the Dalong Formation acted as a seal in the early burial and hydrocarbon generation stage, providing favorable conditions for the continuous hydrocarbon generation and rich gas preservation in shale interval. In the later reservoir stimulation process, it was beneficial to the lateral extension of the fractures, so as to achieve the optimal stimulation performance and increase the well-controlled resources. Combining the geological, engineering and economic conditions, the favorable area with depth <5 500 m is determined to be 1 800 km², with resources of 5 400×10⁸ m³. Fourth, the shale reservoirs of the Dalong Formation are thin but rich in shale gas. The syncline zone far away from the main faults in the high and steep tectonic zone, eastern Sichuan Basin, with depth <5 500 m, is the most favorable target for producing the Permian shale gas under the current engineering and technical conditions. It mainly includes the Nanya syncline, Tanmuchang syncline, and Liangping syncline.

The Carter model is used to characterize the dynamic behaviors of fracture growth and fracturing fluid leakoff. A thermo-fluid coupling forward model is built considering the fluid flow and heat transfer in wellbore, fracture and reservoir. The influences of fracturing parameters and fracture parameters on the responses of distributed temperature sensing (DTS) are analyzed, and a diagnosis method of fracture parameters is presented based on the simulated annealing algorithm. A field case study is introduced to verify the model’s reliability. The results show that typical V-shaped characteristics can be observed from DTS responses in the multi-cluster fracturing process, with locations corresponding to the created hydraulic fractures. The V-shape depth is shallower for a higher injection rate and longer fracturing and shut-in time. Also, the V-shape is wider for a higher fracture-surface leakoff coefficient, longer fracturing time, and smaller fracture width. Additionally, the cooling effect near the wellbore continues to spread into the reservoir during the shut-in period, causing the DTS temperature to decrease instead of rise. Real-time monitoring and interpretation of DTS temperature data can help understand the fracture propagation during fracturing operation, so that immediate measures can be taken to improve the fracturing performance.

In order to identify the development characteristics of fracture network in tight conglomerate reservoir of Mahu after hydraulic fracturing, a hydraulic fracturing test site was set up in the second and third members of Triassic Baikouquan Formation (T₁b₂ and T₁b₃) in Ma-131 well area, which learned from the successful experience of hydraulic fracturing test sites in North America (HFTS-1). Twelve horizontal wells and a high-angle cored well MaJ02 were drilled. The occurrence, connection, propagation law and major controlling factors of hydraulic fractures were analyzed by comparing results of CT scans, imaging logs, direct observation of cores from Well MaJ02, and the tracer monitoring data. Results indicate that: (1) Two types of fractures have developed by hydraulic fracturing, i.e. tensile fractures and shear fractures. Tensile fractures are approximately parallel to the direction of the maximum horizontal principal stress, and propagate less than 50 m from the perforation cluster. Shear fractures are distributed among tensile fractures and mainly in the strike-slip mode due to the induced stress field among tensile fractures, and some of them are in conjugated pairs. Overall, tensile fractures alternate with shear fractures, with shear fractures dominated and activated after tensile ones. (2) Tracer monitoring results showed an obvious difference in fracturing and fluid production among different fracturing stages in horizontal wells. Some hydraulic fractures with length exceeding the well spacing gradually close during the fluid production process due to interwell communication. (3) Density of hydraulic fractures is mainly affected by the lithology and fracturing parameters, which is smaller in the mudstone than the conglomerate. Larger fracturing scale and smaller cluster spacing lead to a higher fracture density, which are important directions to improve the well productivity.