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 shifting progressively 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 typology and maturation; tectonic-depositional cycle coupling controls reservoir/trap type and reservoir-caprock assemblage; and structural configurations control hydrocarbon accumulation, preservation and enrichment patterns. This mechanism is specifically manifested in three aspects: (1) 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 core resource distribution framework with "oil in the north and gas in the south"; (2) 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; (3) 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, providing theoretical support for achieving exploration breakthroughs in the South China Sea.

Given the absence of a prediction method for proppant embedding depth in artificial fractures of hydrate reservoirs, this study employs a hypoplastic constitutive model to quantitatively evaluate the impact of hydrate saturation on the mechanical parameters of the sediments. By integrating the load distribution at the proppant-sediment interface with their respective deformation characteristics, a computational model is developed to determine the proppant embedment depth across three distinct stages: elastic, elastoplastic, and fully plastic. Based on the established model, the influences of hydrate saturation, proppant particle size, proppant arrangement pattern, and closure pressure on the proppant embedding depth are analyzed. The results demonstrate that the proppant embedding depth in fractures of hydrate reservoirs increases with greater closure pressure and larger proppant particle sizes, while it decreases with higher hydrate saturation and increased proppant areal packing density. At a constant closure pressure, the proppant embedding depth exhibits a nonlinear relationship with hydrate saturation, proppant particle size, and proppant areal packing density, with this nonlinearity becoming more pronounced at elevated closure pressures.

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 degree 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 bioclastic tidal 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 degree 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 boundary surfaces, with strong dissolution occurring from MC1-1 to MB2-1, forming laterally connected 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.

Traditional wellbore detection technologies face limitations such as low detection efficiency, poor accuracy, unsuitability for unconventional oil/gas reservoir 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 features of this technology are systematically elaborated. Field applications, including casing damage and corrosion detection in old wells in Xinjiang Oilfield, 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, 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. Furthermore, it maintains stable performance in high-temperature (≤175 °C) and high-pressure (≤140 MPa) environments, and effectively addresses current exploration and production requirements by providing comprehensive and accurate wellbore integrity data for downhole operations.

Focusing on the dolomites within the Permian Maokou Formation in eastern Sichuan Basin, this study integrates petrographic observation, geochemical analysis and in-situ U-Pb dating to constrain the timing of dolomitization and trace the sources of dolomitizing fluids. analyze the intrinsic links among geological events during the tectonic transition of the Paleo-Tethys to Neo-Tethys oceans, strike-slip faulting and dolomitization, so as to reveal the dolomitization mechanism of the Maokou Formation. Three types of matrix dolomites occur in the Maokou Formation in eastern Sichuan Basin, with U-Pb ages indicating three dolomitization phases at (260.6 ± 6.8)-(265.1 ± 2.4), (244.0 ± 11.0)-(247.7 ± 6.0), and (220.6 ± 8.5)-(221.4 ± 7.8) Ma, respectively. Geochemical data indicate distinct fluid origins for each phase of dolomitization. This study demonstrates that three geological events and the resulting three episodes of faulting during the tectonic transition from Paleo- to Neo-Tethys Ocean are key controlling factors of three phases of dolomitization. Specifically, the Middle Permian Emeishan magmatism activated the Houba-Peng’an-Fengdu strike-slip fault zone and induced thermal anomalies, promoting thermal convection between contemporaneous seawater and the Lower Silurian siltstone aquifer, and initiating the first phase of dolomitization. During the Middle Triassic, oblique closure of the Mianlue Ocean induced transtensional faulting, and density-driven downward migration of residual evaporitic seawater and brines in the Lower-Middle Triassic evaporites facilitated the second phase of dolomitization. The Late Triassic continental collision between the South China Block and North China Block produced transpressional faulting, driving the upward migration of brines within the Lower Siluria to mix with residual evaporitic seawater in the Lower-Middle Triassic evaporates, thus supplying the magnesium source for the third phase of dolomitization. This study establishes a strike-slip fault-controlled dolomitization model, providing new insights into the formation mechanisms of dolomite reservoirs in the Tethyan domain.

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, intrasag lithologic traps, and bedrock buried-hill targets with direct source-reservoir connectivity, all demonstrating significant resource potential.

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, 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 hole number and increasing the hole 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 placed. 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 community, 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 hold density from 12-16 holes per cluster to 5-7 holes per cluster, the SRV increased by 17.4% and 48.9%, respectively.

The marine gas-bearing system in the Ordovician carbonate-gypsum-salt rock strata represents a major frontier for future large-scale natural gas exploration in the Ordos Basin. 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. The following insights are obtained. 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 (R_o) 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 revitalizing domain-level exploration in the Ordovician subsalt marine gas-bearing system.

Based on 3D seismic, drilling, and core data from the Tahe Oilfield of the Tarim Basin, convolutional neural network (CNN) was employed for log-based identification of cave filling facies and quantitative calculation of filling degree of paleokarst conduits. The structural framework of paleokarst conduits was analyzed, and a BP neural network model incorporating the geological controls and degree of filling was constructed for quantitative prediction of filling degree across the planar conduit network. The results show that, based on differences in rock physical fabric, single-well cave fillings can be classified into host-rock facies within caves, sand-mud cemented breccia facies, transported sandstone facies, chemical precipitation facies, and unfilled cave facies. Using CNN algorithms, cave filling facies were identified and the filling degree was quantitatively calculated. Among 156 cave wells in the study area, wells with a filling degree greater than 80% account for 39.7%, whereas those with a filling degree less than 20% account for only 16.0%. According to the new scheme for structural classification of paleokarst conduits, the conduits are genetically classified into: tributary conduits, trunk conduits, outlet-type conduits, along-river underflow conduits, deflected conduits, and phreatic underflow conduits, while conduit styles are identified as sinkholes, chambers, phreatic loops, horizontal phreatic conduits, galleries, and moderately inclined conduits. Based on these results, a neutral network quantitative prediction method for conduit filling degree constrained by geological controls was developed. It is found that the phreatic loop sections and higher potential energy (PE) zones (e.g. moderately inclined conduit sections) exhibit high filling probability, whereas the upper spaces of chambers, the upper parts of moderately inclined connecting conduits, and areas near downstream conduit outlets reflect low filling probability, marking as potential targets for future refined development of conduit reservoirs.

Considering the complexities of gas-water relationships in the proven gas reservoirs, and insufficient research on hydrocarbon accumulation dynamic conditions and processes for the Sinian-Permian natural gas in the Penglai gas field of the central Sichuan Basin, this study investigates the gas source, charging processes and enrichment patterns of typical gas reservoirs based on reservoir characterization, natural gas geochemical analysis, reservoir testing, well logging-seismic data interpretation, as well as basin modeling and kinetic analysis. The results are obtained in three aspects. First, four sets of highly efficient source rocks are developed beneath the salt of the Triassic Jialingjiang Formation, dominated by the Cambrian source rocks. The reservoirs exhibit strong heterogeneity, with six sets of effective reservoirs being isolated yet dynamically connected. Multi-stage strike-slip fault-related fracture-cavity-unconformity systems constitute the hydrocarbon migration network. Second, high overpressure generated by hydrocarbon generation in the Cambrian source rocks drove bidirectional hydrocarbon expulsion from the source kitchen. Multiple sources, including cracked gas from paleo-oil reservoirs and residual hydrocarbons within source rocks, contributed to the hydrocarbon supply. The Sinian-Permian system underwent multiple dynamic hydrocarbon accumulation processes, resulting in the formation of extensive “sweet spots” within multi-layered heterogeneous reservoirs, which were subsequently modified by late-stage gas adjustments to their current form. Third, a three-dimensional accumulation model for deep marine natural gas is established, with multi-source hydrocarbon supply, three-dimensional migration, multi-stage accumulation, dynamic adjustment, and lithology-controlled distribution. Large-scale reservoirs within positive structural settings, late-stage structurally stable areas, and slope structures are identified as favorable plays and key targets for three-dimensional exploration.

Utilizing 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, this study analyzes average values across varying intervals of original total organic carbon, vitrinite reflectance, and clay mineral content to propose methods for determining organic and inorganic matrix porosity and reconstructing the original total organic carbon. The results demonstrate that shale matrix porosity is primarily controlled by the original total organic carbon and vitrinite reflectance, with organic pores contributing up to 68% to porosity evolution, while inorganic matrix porosity remains relatively stable, exhibiting a minor reduction of approximately 0.62 percentage points due to clay mineral transformation. As the vitrinite reflectance increases, matrix porosity exhibits a trend of initial increase, subsequent decrease, and a secondary increase before ultimately stabilizing; meanwhile, effective matrix porosity increases with thermal maturity, with the ratio of effective-to-total matrix porosity rising from approximately 53% in low-maturity stages to 79% in high-maturity stages. Additionally, a strong positive correlation is found between water-filled matrix porosity and clay mineral content, between matrix permeability and matrix porosity, and between vertical and horizontal permeability. Fracture porosity is predominantly controlled by the intensity of tectonic activity, and estimated ultimate recovery is primarily governed by hydrocarbon-filled matrix porosity and fracture porosity. By establishing evaluation models for matrix porosity, fracture porosity, and permeability, this study reveals the dynamic evolution mechanisms of reservoir properties throughout the entire thermal maturation of shale, 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.

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 “reverse-order proppant transport” 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.

In response to the unsatisfactory water injection performance in Qinghai Oilfield caused by complex reservoir geological conditions, the fourth-generation cable-controlled layered water injection technology was innovatively upgraded. A three-in-one refined water injection technology system was established, integrating fine reservoir characterization, intelligent layered water injection with precise monitoring, and remote dynamic regulation. Through the design of high-temperature-resistant measurement and control circuits and the development of low-rate downhole flow measurement technology, a small-diameter cable-controlled water distributor suitable for complex conditions characterized by high temperature, high pressure, and high salinity was developed. In addition, a remote monitoring and management system for layered water injection was established, enabling real-time monitoring of production parameters and dynamic regulation of injection rates throughout the entire layered water injection process. The technology system has been applied in the Huatugou and Yingdong demonstration areas. Field practice indicates that intelligent layered water injection can effectively improve the injection profile, enhance waterflood sweep efficiency, control the natural production decline of well groups, increase the qualification rate of layered water injection, and slow down the rise of water cut. Economic evaluation results show that, compared with conventional layered water injection technology, the proposed intelligent layered fine water injection method demonstrates significant advantages in reducing operational costs and improving development efficiency. The results indicate that the upgraded fourth-generation cable-controlled layered water injection technology can significantly improve waterflood performance and provides a replicable and scalable engineering paradigm for fine water injection and efficient, stable production in complex fault-block reservoirs.

Taking typical marginal heavy oil reservoirs as the research object, a multi-scale physical simulation experimental device for heavy oil thermal recovery and corresponding similarity criteria were established. The evolution characteristics of the temperature field and saturation field, as well as the variation patterns of development indices during cyclic steam stimulation, were clarified, and the steam channeling control capability of multi-component thermal system was evaluated. It is found that, during cyclic steam stimulation, steam channeling primarily occurs along the main flow line in the direction of the maximum pressure differential horizontally, while steam channeling appears in the upper part of the reservoir as a result of steam override vertically. High-temperature steam causes the separation of light and heavy components in the heavy oil, with the light components being preferentially produced. The interaction between high-temperature steam and the reservoir induces particle migration and mineral dissolution, accelerating the steam channeling and thus degrading the development performance in later cycles. As steam temperature increases, the heavy oil in large pores is continuously produced, and the oil displacement efficiency increases significantly. The multi-component thermal flooding systems including the nitrogen foam system, the high-temperature profile control and displacement system, and the thermosetting profile control system all effectively mitigate steam channeling and significantly enhance oil recovery. They rank as the thermosetting profile control system, the high-temperature profile control and displacement system, and the nitrogen foam system, in a descending order of the increase in pressure differential and the enhancement of oil recovery.

This study establishes a one-way finite element method-discrete element method (FEM-DEM) coupling numerical framework for dynamically simulating the thermal damage and crack evolution of heterogeneous granite under plasma jet, so as to identify the thermo-mechanical cracking mechanisms. The finite element method is used to build a Gaussian rotating conical heat source to compute the transient temperature field. The temperature is then mapped onto a heterogeneous DEM model reconstructed from real mineral grain boundaries. The model incorporates temperature-dependent bond strength degradation and temperature-threshold-triggered bond breakage mechanism to capture the crack evolution process. Validation against experiments shows errors of below 7% for temperature, 6% for pit morphology, and 11% for crack inclination, suggesting the model's reliability and accuracy. Simulation reveals the crack evolution in three stages: crack initiation, rapid propagation, and stable extension. The dominance of tensile failure and presence of significantly more cracks within grain than at grain boundary indicate that intragranular cracking driven by thermal strain mismatch is the primary pattern of plasma thermal cracking. When the plasma current exceeds 200 A, the damage factor increases sharply and nonlinearly, indicating the existence of a current threshold where the rate of thermal stress accumulation exceeds the rate of stress relaxation. Higher initial rock temperature intensifies thermal damage and shifts the failure mode from tensile-dominated to tensile-shear composite, while confining pressure suppresses axial crack propagation but exacerbates the near-surface thermal spalling effect.

Based on drilling core, thin section, physical property and logging data, taking the second member of the Ordovician Majiagou Formation (Ma 2 Member) in the Ordos Basin as an example, this paper discusses the reservoir types, distribution and forming mechanisms of the carbonate-evaporite paragenetic system. The results are obtained in three aspects. First, the Ma 2 Member was deposited in an onlapping pattern toward the Central Paleouplift and is in unconformable contact with the underlying Cambrian around the paleouplift. From the paleouplift to the eastern depression, sedimentary environments such as tidal flat, grain shoal and lagoon, as well as five types of carbonate-evaporite paragenetic sequences, developed in turn. Second, dolomicrite, silt-crystalline dolomite and grain dolomite reservoirs are developed in the Ma 2 Member. According to sedimentary and diagenetic differences, they are further subdivided into five types of reservoir rocks, including mottled silt-crystalline dolomite, grain dolomite, burrow-bearing micritic (silt-crystalline) dolomite, and gypsum-mold-pore-bearing dolomicrite. Among them, grain dolomite reservoirs have superior physical properties and high development frequency, representing the high-quality reservoirs in the study area. Vertically, reservoirs are mainly developed in the middle and upper parts of high-frequency cycles; laterally, they show a pattern of distribution along depressions and around highs, characterized by multi-stage superposition and lateral migration. Third, based on the understanding of the sedimentary geomorphic pattern and onlap sedimentary filling model, combined with the lithology, lithofacies distribution and evolution of reservoir rocks, and considering the penecontemporaneous dissolution and dolomitization under high-frequency periodic sea-level cycles, a “slope-shoal-dissolution-dolomitization” four-element reservoir-controlling differentiation model is established. The research results can provide a basis for evaluating the exploration potential of hydrocarbon replacement areas in the deep Ma 2 Member of the basin.

Taking the Middle-Upper Cambrian Xixiangchi Group in the central-southern Sichuan Basin as an example, this paper investigates the sedimentary characteristics and evolutionary history of tempestites using field outcrop, core, thin-section and logging data, and elucidates the patterns and processes by which storms have reworked grain shoal reservoirs in carbonate platforms, thereby identifying the zones with favorable reservoirs. The results indicate that: (1) The Xixiangchi Group exhibits six typical storm depositional sequences, with storm-related grain shoals developed in settings such as mixed tidal flats, intra-platform depressions, and margins of the intra-platform depressions. (2) During the deposition of the Xixiangchi Group , storm activities were frequent, mainly in the southeastern, central and southwestern parts of the Sichuan Basin. Overall, storm intensity showed an initial increase followed by a decrease. (3) The impact of storms on the rework of shoal-facies reservoirs varies across different facies zones. The intra-platform depression margins, influenced by storm centers, experienced strong reworking, leading to the vertical stacking of storm-related grain shoals and normal grains shoals, which expands the scale of the shoal complex. Furthermore, storms enhance penecontemporaneous dissolution, favoring the development of high-quality reservoirs. The intra-platform depressions and mixed tidal flats, controlled by the storm centers, were weakly modified, possibly inducing scattered storm-related grain shoals under low-energy conditions. The degree of karst modification is generally low, and local conditions are favorable for reservoir development. In contrast, within the intra-platform sags and on the mixed tidal flats controlled by the storm center, the deposits exhibit weak reworking. This process also leads to the formation of storm-generated grain shoals and an expansion of shoal scale. However, due to this weak reworking, the resulting storm grain shoals have poorly developed primary porosity and are less susceptible to subsequent karstification, resulting in relatively poor reservoir quality. (4) The Dazu-Hechuan-Guang’an area, strongly reworked by storm activities, exhibits a large scale of storm-related grain shoals, providing favorable conditions for the development of contiguous, high-quality grain shoal reservoirs, so it can be regarded as a key target for subsequent exploration of the Xixiangchi Group.

Starting from the first principle thinking, this study systematically reviews the development mechanisms of gas reservoirs and proposes the development concept of “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 physical properties of natural gas dictate a development mechanism primarily driven by pressure depletion to harness the gas elastic expansion energy. This leads to a development model centered on primary depletion, supplemented by limited adjustments in late stages. Early development essentially lies in optimizing well placement and proactive risk management, while late development focuses on targeted local interventions and integrated collaborative control. Primary gas recovery, relying on natural depletion, achieves a recovery factor of 25%-55%. Secondary gas recovery, through active regulation of the reservoir pressure field via techniques like blockage removal, water control, 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 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 lifecycle of gas reservoirs.

Based on the natural gas composition and stable carbon isotope data from the Upper Paleozoic tight sandstone gas reservoirs in the Daji gas field, the Ordos Basin, and through a comparative analysis of the geochemical characteristics of typical over-mature coal-derived gases in China and the world, this study clarified the geochemical features and the origins of stable carbon isotopic anomalies of over-mature coal-derived gas, and revealed the components of over-mature coal-derived gas and the mechanisms of stable carbon isotopic fractionation and their geological implications. The research shows that the natural gas in the Upper Paleozoic tight reservoirs in the Daji gas field is dominated by methane, and its stable carbon isotope exhibits a reversed sequence, suggesting that it was primarily originated from a mixture of kerogen, crude oil, and wet gas cracking gases during the over-mature stage of coal-measure source rocks. Vertically, with the thick limestone of the Taiyuan Formation as a boundary, two gas-bearing systems are delineated in the upper and lower sections with gas respectively supplied by the source rocks of the second member of Shanxi Formation and the Benxi Formation, which exhibit significant differences in migration and accumulation patterns and exploration directions. A three-stage evolution pathway for the stable carbon isotope sequence in over-mature coal-derived gas is proposed. This reversed sequence is not only controlled by the mixing of kerogen, crude oil, and wet gas cracking gases during the over-mature stage, but also influenced by the migration fractionation effects resulting from the preferential diffusion of natural gas generated at this stage. Both factors have, to some extent, enhanced the abundance of coal-derived gas resources in the area, although the enrichment effects of natural gas differ across the various gas-bearing systems.

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.

Based on data from drilling, logging, seismic surveys and tests, a systematic study was conducted on the petroleum geological characteristics and hydrocarbon accumulation features/models of the Triassic Jiucaiyuan Formation in the eastern Fukang Sag of the Junggar Basin. The favorable exploration targets were identified. First, the highly mature, high-quality saline lacustrine source rocks developed in the Permian Lucaogou Formation in the eastern Fukang Sag are characterized by continuous and efficient hydrocarbon expulsion over multiple stages, providing a critical material foundation for large-scale hydrocarbon accumulation in the Jiucaiyuan Formation. Second, the Jiucaiyuan Formation, a dual source/sink system, represents a distal, large-scale braided river delta sedimentary system originated from Karamaili, with well-preserved intergranular pores and fractures, providing good reservoir conditions. Third, the middle and upper parts of the Jiucaiyuan Formation contain thick, high-quality mudstone caprocks. Source-connected faults and associated fracture systems serve as effective pathways for hydrocarbon migration and accumulation. The continuous hydrocarbon generation and pressurization conditions are favorable for the formation of ultra-high-pressure oil and gas reservoirs. Fourth, the effective spatial configuration of various accumulation elements contributes a hydrocarbon accumulation model characterized by “lower generation, upper accumulation, fault transportation, sandbody-fracture storage, and overpressure-driven enrichment”, resulting in the current structural-lithologic reservoirs within the Jiucaiyuan Formation. Fifth, the most favorable exploration targets are areas adjacent to the hydrocarbon generation center of the Lucaogou Formation, with superior structural settings and well-developed faults and sandbodies, corresponding to the prospective trap area of 263 km² and the possible resources amounting to 1.68×10⁸ t. Sixth, the zones with efficient coupling of five elements (source, fault, sandbody, fracture, and pressure) are recommended as preferential targets for seeking additional large-scale petroleum discoveries in the Jiucaiyuan Formation. The renewed major breakthrough in the Triassic petroleum exploration in the Fukang Sag, represented by a high flow rate of 56.16 m³/d at Well Fukang-2 during test, has underscored its significant potential and promising prospects for large-scale exploration. The resulting study is expected to promote a stacked multi-layer exploration pattern in the eastern part of the Junggar Basin and have an important strategic significance for oil and gas exploration in the Triassic across the basin.

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.