Based on the analysis of surface geological survey, exploratory well, gravity-magnetic-electric and seismic data, and through mapping the sedimentary basin and its peripheral orogenic belts together, this paper explores systematically the boundary, distribution, geological structure, and tectonic attributes of the Ordos prototype basin in the geological historical periods. The results show that the Ordos block is bounded to the west by the Engorwusu Fault Zone, to the east by the Taihangshan Mountain Piedmont Fault Zone, to the north by the Solonker-Xilamuron Suture Zone, and to the south by the Shangnan-Danfeng Suture Zone. The Ordos Basin boundary was the plate tectonic boundary during the Middle Proterozoic to Paleozoic, and the intra-continental deformation boundary in the Meso-Cenozoic. The basin survived as a marine cratonic basin covering the entire Ordos block during the Middle Proterozoic to Ordovician, a marine-continental transitional depression basin enclosed by an island arc uplift belt at the plate margin during the Carboniferous to Permian, a unified intra-continental lacustrine depression basin in the Triassic, and an intra-continental cratonic basin circled by a rift system in the Cenozoic. The basin scope has been decreasing till the present. The large, widespread prototype basin controlled the exploration area far beyond the present-day sedimentary basin boundary, with multiple target plays vertically. The Ordos Basin has the characteristics of a whole petroleum (or deposition) system. The Middle Proterozoic wide-rift system as a typical basin under the overlying Phanerozoic basin and the Cambrian-Ordovician passive margin basin and intra-cratonic depression in the deep-sited basin will be the important successions for oil and gas exploration in the coming years.

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) higher than 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 lower than 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. 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 burial depth and occurrence of CRG (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.

Based on the analysis of typical lacustrine shale oil zones in China and their geological characteristics, this study elucidates the fundamental differences between the enrichment patterns of shale oil sweet spots and conventional oil and gas. The key parameters and evaluation methods for assessing the large-scale production potential of lacustrine shale oil are proposed. The results show that shale oil is a petroleum resource that exists in organic-rich shale formations, in other words, it is preserved in its source bed, following a different process of generation-accumulation-enrichment from conventional oil and gas. Thus, the concept of “reservoir” seems to be inapplicable to shale oil. In China, lacustrine shale oil is distributed widely, but the geological characteristics and sweet spots enrichment patterns of shale oil vary significantly in lacustrine basins where the water environment and the tectonic evolution and diagenetic transformation frameworks are distinct. The core of the evaluation of lacustrine shale oil is “sweet spot volume”. The key factors for evaluating the large-scale production of continental shale oil are the oil storage capacity, oil-bearing capacity and oil producing capacity. The key parameters for evaluating these capacities are total porosity, oil content, and free oil content, respectively. It is recommended to determine the total porosity of shale by combining helium porosity measurement with nuclear magnetic resonance (NMR) method, the oil content of key layers by using organic solvent extraction, NMR method and high pressure mercury intrusion methods, and the free oil content by using NMR fluid distribution secondary spectral stripping decomposition and logging. The research results contribute supplemental insights on continental shale oil deliverability in China, and provide a scientific basis for the rapid exploration and large-scale production of lacustrine shale oil.

There are various types of natural gas resources in coal measures, making them major targets for natural gas exploration and development in China. In view of the particularity of the whole petroleum system of coal measures and the reservoir-forming evolution of natural gas in coal, this study reveals the formation, enrichment characteristics and distribution laws of coal-rock gas by systematically reviewing the main types and geological characteristics of natural gas in the whole petroleum system of coal measures. First, natural gas in the whole petroleum system of coal measures is divided into two types, conventional gas and unconventional gas, according to its occurrence characteristics and accumulation mechanism, and into six types, distal detrital rock gas, special rock gas, distal/proximal tight sandstone gas, inner-source tight sandstone gas, shale gas, and coal-rock gas, according to its source and reservoir lithology. The natural gas present in coal-rock reservoirs is collectively referred to as coal-rock gas. Existing data indicate significant differences in the geological characteristics of coal-rock gas exploration and development between shallow and deep layers in the same area, with the transition depth boundary generally 1500-2 000 m. Based on the current understanding of coal-rock gas and respecting the historical usage conventions of coalbed methane terminology, coal-rock gas can be divided into deep coal-rock gas and shallow coalbed methane according to burial depth. Second, according to the research concept of “full-process reservoir formation” in the theory of the whole petroleum system of coal measures, based on the formation and evolution of typical coal-rock gas reservoirs, coal-rock gas is further divided into four types: primary coal-rock gas, regenerated coal-rock gas, residual coal-rock gas, and bio coal-rock gas. The first two belong to deep coal-rock gas, while the latter two belong to shallow coal-rock gas. Third, research on the coal-rock gas reservoir formation and evolution shows that shallow coal-rock gas is mainly residual coal-rock gas or bio coal-rock gas formed after geological transformation of primary coal-rock gas, with the reservoir characteristics such as low reservoir pressure, low gas saturation, adsorbed gas in dominance, and gas production by drainage and depressurization, while deep coal-rock gas is mainly primary coal-rock gas and regenerated coal-rock gas, with the reservoir characteristics such as high reservoir pressure, high gas saturation, abundant free gas, and no or little water. In particular, the primary coal-rock gas is wide in distribution, large in resource quantity, and good in reservoir quality, making it the most favorable type of coal-rock gas for exploration and development.

Taking the second member of the Xujiahe Formation of the Upper Triassic in the Xinchang structural belt as an example, based on data such as logging, production, seismic interpretation and test, a systematic analysis was conducted on the structural characteristics and evolution, reservoir diagenesis and densification processes, and types and stages of faults/fractures, and revealing the multi-stage and multi-factor dynamic coupled enrichment mechanisms of tight gas reservoirs. (1) In the early Yanshan period, the paleo-structural traps were formed with low-medium maturity hydrocarbons accumulating in structural highs driven by buoyancy since reservoirs were not fully densified in this stage, demonstrating paleo-structure control on traps and early hydrocarbon accumulation. (2) In the middle-late Yanshan period, the source rocks became mature to generate and expel a large quantity of hydrocarbons. Grain size and type of sandstone controlled the time of reservoir densification, which restricted the scale of hydrocarbon charging, allowing for only a small-scale migration through sand bodies near the fault/fracture or less-densified matrix reservoirs. (3) During the Himalayan period, the source rocks reached overmaturity, and the residual oil cracking gas was efficiently transported along the late-stage faults/fractures. Wells with high production capacity were mainly located in Type I and II fault/fracture zones comprising the late-stage north-south trending fourth-order faults and the late-stage fractures. The productivity of the wells was controlled by the transformation of the late-stage faults/fractures. (4) The Xinchang structural belt underwent three stages of tectonic evolution, two stages of reservoir formation, and three stages of fault/fractures development. Hydrocarbons mainly accumulated in the paleo-structure highs. After reservoir densification and late fault/fracture adjustment, a complex gas-water distribution pattern was formed. Thus, it is summarized as the model of “near-source and low-abundance hydrocarbon charging in the early stage, and differential enrichment of natural gas under the joint control of fault-fold-fracture complex, high-quality reservoirs and structural highs in the late stage”. Faults/fractures with well-coupled fault-fold-fracture-pore are favorable exploration targets with high exploration effectiveness.

Based on the achievements and research advances in oil and gas exploration in the Persian Gulf Basin, this study analyzes the orderliness of oil and gas distribution and main controlling factors of hydrocarbon accumulation with reservoir-forming assemblage as the unit. In the Persian Gulf Basin, the hydrocarbon-generating centers of source rocks of different geological ages and the hydrocarbon rich zones migrate in a clockwise direction around the Ghawar Oilfield in the Central Arabian Subbasin. Horizontally, the overall distribution pattern is orderly, showing “oil in the west and gas in the east”, and “large oil and gas fields dense in the basin center and sparse at the basin edges”. Vertically, the extents of petroleum system compounding and sources mixing increase from west to east, the pattern of tectonic strength (weak in the west and strong in the east) forming the distribution characteristics of “gas rich in the Paleozoic, oil rich in the Mesozoic, and both oil and gas rich in the Cenozoic”. The large scale accumulation and orderly distribution of oil and gas in the Persian Gulf Basin are controlled by three factors: (1) Multiple sets of giant hydrocarbon kitchens provide a resource base for near-source reservoir-forming assemblages. The short-distance lateral migration determines the oil and gas enrichment in and around the distribution area of effective source rocks. (2) The anhydrite caprocks in the platform area are thin but have experienced weak late-stage tectonic activities. Their good sealing performance makes it difficult for oil and gas to migrate vertically to shallow layers through them. The thrust faults and high-angle fractures formed by intense tectonic activities of the Zagros Orogenic Belt connect multiple source-reservoir assemblages. However, the Neogene Gachsaran Formation gypsum-salt rocks are thick and highly plastic, generally with good sealing performance, so large-scale oil and gas accumulations are still formed beneath the salt; (3) Each set of reservoir-forming assemblages is well matched in time and space in terms of the development of source rocks and reservoir-caprock assemblages, the maturation and hydrocarbon generation of source rocks, and the formation of traps, thus resulting in abundant multi layer hydrocarbon accumulations. At present, the Persian Gulf Basin is still in the stage of structural trap exploration. The pre-salt prospective traps in effective hydrocarbon kitchens remain the first choice. The areas with significant changes in Mesozoic sedimentary facies have the conditions to form large scale lithologic oil and gas reservoirs. The deep Paleozoic conventional oil and gas reservoirs and the Lower Silurian Qusaiba Member shale gas have great exploration potential and are expected to become important reserve growth areas in the future.

Based on a set of high-resolution 3D seismic data from the northern continental margin of the South China Sea, the lithospheric structure, thinning mechanisms and related syn-rift tectonic deformation response processes in the crustal necking zone in the deepwater area of the Pearl River Mouth Basin were systematically analyzed, and the petroleum geological significance was discussed. The necking zone investigated in the study is located in the Baiyun Sag and Kaiping Sag in the deepwater area of the Pearl River Mouth Basin. These areas show extreme crustal thinned geometries of central thinning and flank thickening, characterized by multi-level and multi-dipping detachment fault systems. The necking zone exhibits pronounced lateral heterogeneity in structural architectures, which can be classified into four types of thinned crustal architectures, i.e. the wedge-shaped extremely thinned crustal architecture in the Baiyun Main Sub-sag, dumbbell-shaped moderately thinned crustal architecture in the Baiyun West Sub-sag, box-shaped weakly thinned crustal architecture in eastern Baiyun Sag, and metamorphic core complex weakly thinned crustal architecture in the Kaiping Sag. This shows great variations in the degree and style of crustal thinning, types of detachment faults, distribution of syn-rift sedimentary sequences, and intensity of magmatism. The thinning of the necking zone is controlled by the heterogeneous rheological stratification of lithosphere, intensity of mantle-derived magmatism, and deformation modes of detachment faults. The syn-rift tectonic deformation of the necking zone evolved through three phases, i.e. uniform stretching during the early Wenchang Formation deposition period, necking during the late Wenchang Formation deposition period, and hyperextension during the Enping Formation deposition period. The crustal thinning extent and architectural differentiation in these phases were primarily controlled by three distinct mechanisms, i.e. the pure shear deformation activation of pre-existing thrust faults, the simple shear deformation of crust-mantle and inter-crust detachment faults, and differential coupling of lower crustal flow and ductile domes with main detachment faults. The hydrocarbon accumulation and enrichment in the necking zone exhibit marked spatial heterogeneity. Four distinct crustal thinned architecture-hydrocarbon accumulation models were identified in this study. The hydrocarbon accumulations in the shallow part exhibit significant correlations with their deep crustal thinned architectures. The unique lithospheric structure and deformation process predominantly control the favorable hydrocarbon accumulation zones with excellent source-fault-ridge-sand configurations, which is critical to reservoir-forming. The most promising exploration targets are mainly identified on the uplift zones and their seaward-dipping flanks associated with the middle and lower crustal domes. This research provides additional insights into lithospheric thinning-breakup process at intermediate continental margins of marine sedimentary basins, being significant for guiding the deepwater petroleum exploration in the Pearl River Mouth Basin.

This study reconstructed the paleo-uplift and depression pattern within the sequence stratigraphic framework of the Mid-Permian Maokou Formation, Sichuan Basin, investigated its tectono-sedimentary mechanisms and its control on paleogeomorphology and large-sale shoals based on analysis of outcrops, loggings and seismic data. The results show that the Maokou Formation comprises two third-order sequences, 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 extensional faults, exhibited a NE-trending linear distribution with 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 slope-break zones governed the Mid-Permian paleogeomorphy in the Sichuan Basin 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). Ultimately, a further depression zone developed in the southwestern basin during the late-stage (SSQ6), forming a paleo-uplift bounded by two depressions. The developments of the Mid-Permian paleogeomorphic configuration reflected the combined control by the rapid subduction of the Mianlüe 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 geochemical data from natural gas samples across spring water systems and sedimentary basins, including Songliao, Bohai Bay, Sanshui, Sichuan, Ordos, Tarim and Ying-Qiong, this paper systematically compares the geochemical compositions of abiogenic versus biogenic gases. Emphasis is placed on the diagnostic signatures of abiogenic 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 isotopic compositions (δ¹³C₁>-25‰ generally), complete carbon isotopic reversal (δ¹³C₁>δ¹³C₂>δ¹³C₃>δ¹³C₄), and enriched helium isotope (R/R_a>0.5, CH₄/³He£10⁶ 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, δD₂<δD₃). The hydrogen isotopic compositions of methane generally show limited variation (about 9‰), possibly due to hydrogen isotopic exchange with connate water. (4) In terms of 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 the genetic identification of natural gas and further research on abiogenic gases.

By integrating core observations, logging data and seismic interpretation, this study takes the massive Cretaceous carbonates in the M block of the Santos Basin, Brazil, as an example to establish the sequence filling pattern of fault-bounded isolated platforms in rift lake basins, reveal the control mechanisms of shoal-body development and reservoir formation, and reconstruct the evolutionary history of lithofacies paleogeography. The following results are obtained. (1) Three tertiary sequences (SQ1-SQ3) are identified in the Lower Cretaceous Itapema-Barra Velha of the M block. During the depositional period of SQ1, the rift basement faults controlled the stratigraphic distribution pattern of thick on both sides and thin in the middle. The strata overlapped to uplift in the early stage. During the depositional period of SQ2-SQ3, the synsedimentary faults controlled the paleogeomorphic reworking process with subsidence in the northwest and uplifting in the northeast, accompanied with the relative fall of lake level. (2) The Lower Cretaceous in the M block was deposited in a littoral-shallow lake, with the lithofacies paleogeographic pattern transiting from the inner clastic shoals and outer shelly shoals in SQ1 to the alternation of mounds and shoals in SQ2-SQ3. (3) Under the joint control of relative lake-level fluctuation, synsedimentary faults and volcanic activity, the shelly shoals in SQ1 tend to accumulated vertically in the raised area, and the mound-shoal complex in SQ2-SQ3 tends to migrate laterally towards the slope-break belt due to the reduction of accommodation space. (4) The evolution pattern of high-energy mounds and shoals, which were vertically accumulated in the early stage and laterally migrated in the later stage, controlled the transformation of high-quality reservoirs from “centralized” to “ring shaped” distribution. The research findings clarify the sedimentary patterns of mounds and shoals and the distribution of favorable reservoirs in the fault-controlled lacustrine isolated platform, providing support for the deepwater hydrocarbon exploration in the subsalt carbonate rocks in the Santos Basin.

Based on two-dimensional/three-dimensional seismic and logging data, combined with the analysis of low-temperature thermochronology data, the unconformity surface characteristics and the patterns and dynamic mechanisms of inverted structures in the Doseo Basin in the Central and West African rift systems are systematically analyzed. Seismic profiles reveal two key inversion unconformable surfaces in the basin, i.e. the T₅ interface within the Upper Cretaceous and the T₄ interface at the top of the Cretaceous, which control the development of inverted structures in the basin. Four types of inverted structures, i.e. fault-associated, thrust, fold, and back-shaped negative flower, are identified. Spatially, they form six inverted structural belts trending in NE-NEE direction. The thermal history simulation of apatite fission track reveals two rapid cooling events in the late Late Cretaceous (85-80 Ma, cooling by 15 °C) and the Eocene-Oligocene (30-40 Ma, cooling by 35 °C), corresponding respectively to the formation periods of the T₅ and T₄ interface. The dynamics analysis of structural inversion indicates that the structural inversion in the Late Cretaceous was controlled by the subduction and long-range compression within the Tethys Ocean in the north of African Plate, while the structural inversion in the Eocene-Oligocene was drived by the stress transmission from the African-Eurasian collision. The two events were all controlled by the continuous tectonic regulation of the intracratonic basin by the evolution of the Tethys tectonic domain. The two periods of structural inversion enhanced the efficiency of oil and gas migration by controlling the types of traps (anticline and fault-related traps) and fault activation, precisely matching the hydrocarbon generation peaks of the Lower Cretaceous source rocks in the Late Cretaceous and Eocene, thereby controlling the formation of large-scale oil and gas reservoirs in the Doseo Basin. This geological insight provides a critical basis for the theoretical research on the evolution and hydrocarbon accumulation of inverted structures in discrete strike-slip rift systems.

Based on continuum-discontinuum element method, the numerical simulation of fracture propagation during deflagration-hydraulic composite fracturing was constructed by considering deflagration stress impact induced fracture creation, deflagrating gas driven fracture propagation, and hydraulic fracture propagation, exploring the effects of in-situ stress difference, deflagration peak pressure, deflagration pressurization rate, hydraulic fracturing displacement and hydraulic fracturing fluid viscosity on fracture propagation in deflagration-hydraulic composite fracturing. The deflagration-hydraulic composite fracturing combines the advantages of deflagration fracturing in creating complex fractures near wells and the deep penetration of hydraulic fracturing at the far-field region, which can form multiple deep penetrating long fractures with better stimulation effects. With the increase of in-situ stress difference, the stimulated area of deflagration-hydraulic composite fracturing is reduced, and the deflagration-hydraulic composite fracturing is more suitable for reservoirs with small in-situ stress difference. Higher peak pressure and pressurization rate are conducive to increasing the maximum fracture length and burst degree of the deflagration fractures, which in turn increases the stimulated area of deflagration-hydraulic composite fracturing and improves the stimulation effect. Increasing the displacement and viscosity of hydraulic fracturing fluid can enhance the net pressure within the fractures, activate the deflagration fractures, increase the turning radius of the fractures, generate more long fractures, and effectively increase the stimulated reservoir area. The stimulated reservoir area is not completely positively correlated with the hydraulic fracturing displacement and fracturing fluid viscosity, and there is a critical value. When the critical value is exceeded, the stimulated area decreases.

This study introduces a novel methodology and makes case studies for anomaly detection in multivariate oil production time-series data, utilizing a supervised Transformer algorithm to identify spurious events related to interval control valves (ICVs) in intelligent well completions (IWC). Transformer algorithms present significant advantages in time-series anomaly detection, primarily due to their ability to handle data drift and capture complex patterns effectively. Their self-attention mechanism allows these models to adapt to shifts in data distribution over time, ensuring resilience against changes that can occur in time-series data. Additionally, Transformers excel at identifying intricate temporal dependencies and long-range interactions, which are often challenging for traditional models. Field tests conducted in the ultradeep water subsea wells of the Santos Basin further validate the model’s capability for early anomaly identification of ICVs, minimizing non-productive time and safeguarding well integrity. The model achieved an accuracy of 0.954 4, a balanced accuracy of 0.969 4 and an F1-Score of 0.957 4, representing significant improvements over previous literature models.

To elucidate the mechanism by which supercritical CO₂ (SCCO₂)-water-shale interactions during CO₂ energized fracturing influence proppant embedment in lacustrine shale, shale samples from the Bohai Bay Basin were selected for SCCO₂-water-shale interaction experiments. X-ray diffraction (XRD), SEM large-area high-resolution imaging, automated mineral identification and characterization system (AMICS), and nanoindentation tests were employed to examine the micro-mechanical damage mechanisms of fracture surfaces and the evolving patterns of proppant embedment characteristics. The results reveal that: Prolonged interaction time reduces the contents of dolomite, feldspar, and clay minerals, while quartz content increases, with dolomite showing the most pronounced dissolution effect. As interaction time increases, the hardness and elasticity modulus of shale follow a power-law decay pattern, with the peak degradation rate occurring at 1 d, followed by a gradual decline of degradation velocity. Increasing interaction time results in growth in both the number and depth of embedment pits on the sample surface. After more than 3 d of interaction, clustered proppant embedment is observed, accompanied by the formation of deep embedment pits on the surface.

Based on the finite-discrete element method, a three-dimensional numerical model for axial impact rock breaking was established and validated. A computational method for energy conversion during impact rock breaking was proposed, and the effects of conical tooth forward rake angle, rock temperature, and impact velocity on rock breaking characteristics and energy transfer laws were analyzed. The results show that during single impact rock breaking with conical tooth bits, merely 7.52% to 12.51% of the energy is utilized for rock breaking, while a significant 57.26% to 78.10% is dissipated as frictional loss. An insufficient forward rake angle increases tooth penetration depth and frictional loss, whereas an excessive forward rake angle reduces penetration capability, causing bit rebound and greater energy absorption by the drill rod. Thus, an optimal forward rake angle exists. Regarding environmental factors, high temperatures significantly enhance impact-induced rock breaking. Thermal damage from high temperatures reduces rock strength and inhibits its energy absorption. Finally, higher impact velocities intensify rock damage, yet excessively high velocities increase frictional loss and reduce the proportion of energy absorbed by the rock, thereby failing to substantially improve rock breaking efficiency. An optimal impact velocity exists.

Based on the finite element-discrete element numerical method, a numerical model of fracture propagation in deflagration fracturing was established by considering the impact of stress wave, quasi-static pressure of explosive gas, and reflection of stress wave. The model was validated against the results of physical experiments. Taking the shale reservoirs of Silurian Longmaxi Formation in Luzhou area of the Sichuan Basin as an example, the effects of in-situ stress difference, natural fracture parameters, branch wellbore spacing, delay detonation time, and angle between branch wellbore and main wellbore on fracture propagation were identified. The results show that the fracture propagation morphology in deflagration fracturing is less affected by the in-situ stress difference when it is 5-15 MPa, and the tendency of fracture intersection between branch wellbores is significantly weakened when the in-situ stress difference reaches 20 MPa. The increase of natural fracture length promotes the fracture propagation along the natural fracture direction, while the increase of volumetric natural fracture density and angle limits the fracture propagation area and reduces the probability of fracture intersection between branch wells. The larger the branch wellbore spacing, the less probability of the fracture intersection between branch wells, allowing for the fracture propagation in multiple directions. Increasing the delay detonation time decreases the fracture spacing between branch wellbores. When the angle between the branch wellbore and the main wellbore is 45° and 90°, there is a tendency of fracture intersection between branch wellbores.

By integrating laboratory physical modeling experiments with machine learning-based analysis of dominant factors, this study explored the feasibility of pulse hydraulic fracturing (PHF) in deep coal rocks and revealed the fracture propagation patterns and the mechanisms of pulsating loading in the process. The results show that PHF induces fatigue damage in coal matrix, significantly reducing breakdown pressure and increasing fracture network volume. Lower vertical stress differential coefficient (less than 0.31), lower peak pressure ratio (less than 0.9), higher horizontal stress differential coefficient (greater than 0.13), higher pulse amplitude ratio (greater than or equal to 0.5) and higher pulse frequency (greater than or equal to 3 Hz) effectively decrease the breakdown pressure. Conversely, higher vertical stress differential coefficient (greater than or equal to 0.31), higher pulse amplitude ratio (greater than or equal to 0.5), lower horizontal stress differential coefficient (less than or equal to 0.13), lower peak pressure ratio (less than 0.9), and lower pulse frequency (less than 3 Hz) promote the formation of a complex fracture network. Vertical stress and peak pressure are the most critical geological and engineering parameters affecting the stimulation effectiveness of PHF. The dominant mechanism varies with coal rank due to differences in geomechanical characteristics and natural fracture development. Low-rank coal primarily exhibits matrix strength degradation. High-rank coal mainly involves the activation of natural fractures and bedding planes. Medium-rank coal shows a coexistence of matrix strength degradation and micro-fracture connectivity. The PHF forms complex fracture networks through the dual mechanism of matrix strength degradation and fracture network connectivity enhancement.

Based on the technological demands for significantly enhancing oil recovery and long-term CO₂ sequestration in the lacustrine oil reservoirs of China, this study systematically reviews the progress and practices of CO₂ flooding and storage technologies in recent years. It addresses the key technological needs and challenges faced in scaling up the application of CO₂ flooding and storage to mature, developed oil fields, and analyzes future development directions. During the pilot test phase (2006-2019), continuous development and application practices led to the establishment of the first-generation CO₂ flooding and storage technology system for lacustrine reservoirs. In the industrialization phase (since 2020), significant advances and insights have been achieved in terms of confined phase behavior, storage mechanisms, reservoir engineering, sweep control, engineering process and storage monitoring, enabling the maturation of the second-generation CO₂ flooding and storage theories and technologies to effectively support the demonstration projects of Carbon Capture, Utilization and Storage (CCUS). To overcome key technical issues such as low miscibility, difficulty in gas channeling control, high process requirements, limited application scenarios, and coordination challenges in CO₂ flooding and storage, and to support the large-scale application of CCUS, it is necessary to strengthen research on key technologies for establishing the third-generation CO₂ flooding and storage technological system incorporating miscibility enhancement and transformation, comprehensive regulation for sweep enhancement, whole-process engineering techniques and equipment, long-term storage monitoring safety, and synergistic optimization of flooding and storage.

A coupled PHREEQC-MATLAB simulation approach is proposed to investigate the dynamic changes in rock porosity, gas storage capacity, formation water salinity, and reservoir temperature driven by biogeochemical interactions during cyclic underground bio-methanation (UBM) of CO₂ and H₂, and to quantitatively examine how the evolution of these parameters influences CH₄ production efficiency. The results indicate that during the cyclic UBM of CO₂-H₂, the formation water undergoes a dynamic acid-base alternation, leading to periodic mineral dissolution and precipitation with limited impact on rock porosity. Across different mineral systems, the maximum CH₄ production rate remains consistently around 3.6×10⁻³ mol/(L·d) in each cycle. With an increasing number of cycles, under high initial salinity conditions, the metabolic water produced by methanogens can significantly reduce the formation water salinity, gradually enhancing the CH₄ production rate to levels comparable with those under low initial salinity. Additionally, the increased volume of produced water reduces the gas storage capacity of the reservoir. This reduction becomes more pronounced at higher initial CO₂-H₂ pressures, accompanied by a more significant increase in CH₄ production rate increment. Furthermore, the heat generated by methanogen metabolism leads to an increase in reservoir temperature, with the extent of temperature rise significantly influenced by heat loss. If the heat loss is neglected, the reservoir temperature can increase by up to 17.1 °C after five cycles (10 years). When the reservoir has a higher initial temperature, the elevated thermal conditions may reduce CH₄ production efficiency.