To elucidate the mechanism by which supercritical CO₂ (SCCO₂)-water-shale interactions during CO₂ pre-pad energized fracturing influence proppant embedment in continental shale, shale samples from the Bohai Bay Basin were selected to SCCO₂-water-shale interaction experiments. X-ray diffraction (XRD), microstructure analysis package system (MAPS), 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 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 results show that: 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. Larger 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.

By integrating core observations, logging data and seismic interpretation, this study takes the massive Cretaceous carbonates in the Santos Basin, Brazil as an example to establish the sequence filling pattern of fault-bounded isolated platforms in rift lake basins, reveal the genetic mechanisms of shoal-body development and reservoir quality control, and reconstruct the evolutionary history of lithofacies palaeogeography. The following results are obtained. (1) Three tertiary sequences (SQ1-SQ3) are identified in the Cretaceous Itapema-Barra Velha, the M block. During the depositional period of SQ1, the rift basement faults controlled a paleogeomorphic pattern of internal uplift and peripheral depression. 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 fall of lake level, and the uplift expansion. (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 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” 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.

The deep tight sandstone gas resources in the Sichuan Basin are considerable, but the tight reservoirs have strong heterogeneity and significant differences in well productivity, making it difficult to utilize the tight gas. Taking the second member of the Xujiahe Formation of the Upper Triassic in the Xinchang structural belt as an example, based on new data such as logging, production, and seismic interpretation, a systematic analysis was conducted on the structural characteristics and evolution, reservoir diagenesis and densification processes, and types and stages of faults/fractures. The following results are obtained. (1) In the early Yanshan period, the paleo-structural traps were formed earlier than initial hydrocarbon charging, with low-medium maturity hydrocarbons accumulating in structural highs since reservoirs were not fully densified in this stage, demonstrating structure control on early hydrocarbon entrapment. (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 decided 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 were 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 development. Hydrocarbons mainly accumulated in the paleo-structure highs. After reservoir densification and late fault/fracture adjustment, a complex gas-water distribution was formed. Thus, it is summarized as the model of “near-source and low-abundance hydrocarbon charging at structural highs in the early stage, and adjustment and enrichment under the joint control of fault-fold-fracture complex, high-quality reservoirs and structural highs in the late stage”.

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.

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 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.

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

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

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

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

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

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

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

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

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

Based on the test and experimental data from exploration well cores in the central-eastern Ordos Basin, combined with structural, depth and fluid geochemistry analyses, this study reveals the fluid characteristics, gas accumulation control factors and accumulation modes in coal reservoirs. The study indicates findings in two aspects. First, the 1 500-1 800 m interval represents the critical transition zone between shallow-medium open fluid system and deep closed fluid system. Reservoirs below 1 500 m reflect intense water invasion, with discrete pressure gradient distribution, and the presence of methane mixed with varying degrees of secondary biogenic gas, and they generally exhibit high water saturation and adsorbed gas undersaturation. Reservoirs deeper than 1 800 m, with extremely low permeability, are self-sealed, and contains closed fluid systems formed jointly by the hydrodynamic lateral blocking and tight caprock confinement. Within these systems, surface runoff infiltration is weak, the degree of secondary fluid transformation is minimal, and the pressure gradient is relatively uniform. The adsorbed gas saturation exceeds 100% in most seams, and the free gas content primarily ranges from 1 to 8 m³/t (˃10 m³/t in some seams). Second, the gas enrichment in deep coals is primarily controlled by coal quality, reservoir-caprock assemblage, and structural position governed storage, wettability and sealing properties, under the constraints of the underground temperature and pressure conditions. High-rank, low-ash yield coals with limestone and mudstone caprocks show superior gas accumulation potential. Positive structural highs and negative structural lows are favorable sites for gas enrichment, while slope belts of fold limbs exhibit relatively lower gas content. This research enhances understanding of gas accumulation mechanisms in coal reservoirs and provides effective guidance for precise zone evaluation and innovation of adaptive stimulation technologies for deep resources.

Static adsorption and dynamic damage experiments were carried out on typical No.8 deep coal rock in the Ordos Basin to evaluate the adsorption capacity of hydroxypropyl guar gum and polyacrylamide as fracturing fluid thickeners on deep coal rock surface and the permeability damage caused by adsorption. The adsorption morphology of the thickener was quantitatively characterized by atomic force microscopy, and the main controlling factors of the thickener adsorption were analyzed. Meanwhile, the adsorption mechanism of the thickener was revealed by Zeta potential, Fourier infrared spectroscopy and X-ray photoelectron spectroscopy. The results show that the adsorption capacity of hydroxypropyl guar gum on deep coal surface is 3.86 mg/g, and the permeability of coal rock after adsorption decreases by 35.24%-37.01%. The adsorption capacity of polyacrylamide is 3.29 mg/g, and the permeability of coal rock after adsorption decreases by 14.31%-21.93%. The thickness of the thickener adsorption layer is positively correlated with the mass fraction of thickener and negatively correlated with temperature, and a decrease in pH will reduce the thickness of the hydroxypropyl guar gum adsorption layer and make the distribution frequency of the thickness of the polyacrylamide adsorption layer more concentrated. Functional group condensation and intermolecular force are the chemical and physical forces for adsorbing fracturing fluid thickener in deep coal rock. Optimization of thickener mass fraction, chemical modification of thickener molecular, oxidative thermal degradation of polymer and addition of desorption agent can reduce the potential damages on micro-nano pores and cracks in coal rock.

Based on recent advancements in shale oil exploration within the Ordos Basin, this study presents a comprehensive investigation of the paleoenvironment, lithofacies assemblages and distribution, depositional mechanisms, and reservoir characteristics of shale oil in continental freshwater lacustrine basins, with a focus on the Chang 7₃ sub-member of Triassic Yanchang Formation. The research integrates a variety of exploration data, including field outcrops, drilling, logging, core samples, geochemical analyses, and flume simulation experiment. The study indicates that: (1) The paleoenvironment of the Chang 7₃ deposition is characterized by a warm and humid climate, frequent monsoon events, and a large water depth of freshwater lacustrine basin. The paleogeomorphology exhibits an asymmetrical pattern, with steep slopes in the southwest and gentle slopes in the northeast. This can be further subdivided into microgeomorphological units, including depressions and ridges in lakebed, as well as ancient channels; (2) The Chang 7₃ sub-member is characterized by a diverse array of fine-grained sediments, including very fine sandstone, siltstone, mudstone, and tuff. These sediments are primarily distributed in thin interbedded and laminated arrangements vertically. The overall grain size of the sandstone predominantly falls below 0.062 5 μm, with individual layer thicknesses of 0.05-0.64 m. The deposits contain intact plant fragments and display various sedimentary structure, such as wavy bedding, inverse-to-normal grading sequence, and climbing ripple bedding, which indicating a depositional origin associated with density flows; (3) Flume simulation experiments have successfully replicated the transport processes and sedimentary characteristics associated with density flows. The initial phase is characterized by a density-velocity differential, resulting in a thicker, coarser sediment layer at the flow front, while the upper layers are thinner and finer in grain size. During the mid-phase, sliding water effects cause the fluid front to rise and facilitate rapid forward transport. This process generates multiple “new fronts”, enabling the long-distance transport of fine-grained sandstones, such as siltstone and argillaceous siltstone, into the center of the lake basin; (4) A sedimentary model primarily controlled by the density flows was established for the southwestern part of the basin, highlighting that the frequent occurrence of flood events and the steep topography in this area are the primary controlling factors for the development of density flows; (5) Sandstone and mudstone in the Chang 7₃ sub-member exhibit micro- and nano-scale pore-throat systems, with varying oil-bearing properties across different lithologies and significant differences in mobile oil content. (6) It was determined that the fine-grained sediment complexes formed by multiple episodes of sandstones and mudstones associated with density flow in the Chang 7₃ formation exhibit characteristics of “overall oil-bearing with differential storage capacity”. The combination of mudstone with low total organic carbon content (TOC) and siltstone is identified as the most favorable exploration target at present.

This paper investigates the macroscopic and microscopic characteristics of viscosity reduction and quality improvement of heavy oil in a supercritical water environment through laboratory experiments and analytical testing. The effect of three reaction parameters, i.e. reaction temperature, reaction time and oil-water ratio, is analyzed on the product and their correlation with viscosity. The results show that the flow state of heavy oil significantly improved with a viscosity reduction of 99.4% in average after the reaction in supercritical water. Excessively high reaction temperature leads to a higher content of resins and asphaltenes, with significantly increasing production of coke. The optimal temperature ranges in 380 °C-420 °C. Prolonged reaction time could continuously increase the yield of light oil, but it will also results in the growth of resins and asphaltenes, with the optimal reaction time of 150 minutes. Reducing the oil-water ratio helps improve the diffusion environment within the reaction system and reduce the content of resins and asphaltenes, but it will increase the cost of heavy oil treatment. An oil-water ratio of 1:2 is considered as optimum to balance the quality improvement, viscosity reduction, and reaction economics. The correlation of the three reaction parameters relative to the oil sample viscosity is ranked as temperature, time, and oil-water ratio. Among the four fractions of heavy oil, the viscosity is dominated by asphaltene content and less affected by resins and saturates contents.

Through investigating the Triassic Yanchang Formation in the Ordos Basin, black carbon has been found for the first time in the seventh member of the Middle Triassic Yanchang Formation (Chang 7 Member). This study fills the gap in black carbon record in the Middle Triassic in terrestrial basins in in the East Tethys, and suggests that the oxygen content in the East Tethys during the Middle Triassic was beyond 15% and that plants had recovered from the Late Permian mass extinction. The results show that the distribution of black carbon in the Chang 7 Member is heterogeneous in the basin. In the southeastern part, the black carbon content is the highest (possibly ˃6%) in shale, with the proportion in TOC up to 20%, which is lower than 10% in the northwestern and northeastern parts. It is intriguing that the proportion of black carbon in the organic matter can reach to this high level during the Middle Triassic when black carbon was stunted. Therefore, it is postulated that black carbon could account for great proportion in organic matter after vegetation on land in the Silurian. The traditional practice needs to be caution when TOC is set as a critical proxy in source rock evaluation and shale oil and gas sweet spot screening. Source rock bearing high TOC but high proportion in black carbon may not be good target for unconventional oil and gas exploitation, while shale bearing low TOC with low or no black carbon may become promising option. The TOC in the source rock can be fractioned into black carbon (w_b), active carbon (w_a), residual carbon (w_r), and maturated oil carbon (w_o). TOC subtract w_b or TOC-w_b is recommended for evaluation of source rock, w_a for screening the in-situ recovery area of low to medium maturity shale oil, and w_o of matured shale oil for appraisal of the favorable exploration area of medium to high matured shale oil. These results allow for the quantitative evaluation of organic matter composition of shale, hydrocarbon generation potential, maturation stage, and expulsion and retention of shale oil, and also guide the reconstruction of paleoclimate in the source rock development period and the shale oil and gas sweet spot screening.

The depositional facies types of the fourth member of the Middle Triassic Leokoupo Formation (Lei-4 Member) in western Sichuan Basin are examined through the methods of sedimentology, lithology and the mineral composition interpretation, as well as the special lithofacies indicators such as microbialite, anhydrite-halite succession and tempestites, using the data of about 400 boreholes and 11 outcrop sections. The distribution evolution characteristics and its hydrocarbon significances of the paleo-bay facies have been discussed further. The Lei-4 Member in western Sichuan Basin has an ocean-bay-flat depositional model, with the presence of evaporated tidal flat, restricted tidal flat and paleo-bay facies from east to west. The subfacies such as bay margin, subtidal bay and bay slope are recognized within the paleo-bay, with microbial reef and grain bank microfacies in the bay margin, microbial dolomitic flat, deep-water spongy reef and hydrostatic mudstone microfacies in the subtidal bay, and tempestites and collapsed deposits in the upper bay slope. The bay margin covered the Guangyuan-Zitong-Dujiangyan area in the period of the first submember of the Lei-4 Member (Lei-4-1), regressed westward into the Shangsi-Jiangyou-Dujiangyan area in the period of Lei-4-2, and expanded to the Jiange-Zitong-Langzhong-Wusheng-Yanting-Chengdu area in the northern part of central Sichuan Basin in the period of Lei-4-3 along with a small-scale transgression. The topographic pattern of “one high and two lows” is confirmed in the Lei-4 Member, corresponding to a configuration of source rocks and reservoir rocks that are alternated horizontally and superimposed vertically. Two efficient source-reservoir configuration models, i.e. side source & side reservoir, and self-generating & self-storing, are available with the microbial reef and grain bank reservoirs at the bay margin and the high-quality source rocks within the sags on both sides of the bay. The research findings will inevitably open up a new situation for the hydrocarbon exploration in the Leikoupo Formation.

Based on 2D and 3D seismic data and well logging data, this paper studies the distribution of well-seismic stratigraphic filling and shoal controlled reservoirs of Upper Cambrian Xixiangchi Formation in the south slope of Leshan-Longnüsi paleouplift in the Sichuan Basin, to reveal the genetic relationship between stratigraphic filling, paleogeomorphology and large-scale grain shoal. (1) The Xixiangchi Formation in the study area is overlapped and filled gradually to the Leshan-Longnüsi paleouplift, but gets thin sharply due to truncation only near the denudation pinch-out line of the paleouplift. Therefore, 2 overlap slope break belts and 1 erosion slope break belt are identified, and the Xixiangchi Formation is divided into 4 members from bottom to top. (2) The filling pattern of the overlapping at the base and erosion at the top indicates that the thickness of Xixiangchi Formation can reflect the pre-depositional paleogeomorphology, and reveals that the study area has a monoclinal geomorphic feature of plunging to southeast and being controlled by multistage slope break belts. (3) The large-scale grain shoals and shoal controlled reservoirs are developed longitudinally in the third and fourth member of the Xixiangchi Formation, and laterally in the vicinity of the multistage overlap slope break belts. (4) Overlap slope break belts are closely related to northwest trending reverse faults. The northwest to southeast compressive stress formed by the convergence of the western margin of South China Plate with the Himalayas landmass of the Qiangtang-Tethyan realm in the middle and late Cambrian led to the rapid uplift of the northwest margin of the Yangtze Plate and the expansion to the southeast, forming a gradually plunging multistage slope break paleogeomorphology. Combined with oil and gas test results, it is predicted that the favorable exploration zone of the grain shoal controlled reservoirs can cover an area of 3340 km².

Based on the analyses of the core, cast thin section, physical property, CT, wireline loggings, well tests and seismic data, taking the Lower Cretaceous Yamama Formation in Oilfield A of the Central Arabian Basin as an example, the sedimentation and diagenesis characteristics and favorable reservoir distribution in semi-restricted carbonate ramp are clarified. The results show that semi-restricted carbonate ramp is enriched with Algae, Benthic foraminifera, Bivalve, Bacinella, and peloids, and is characterized by diverse low-energy and shallow-water lithofacies. The depositional environment of the Yamama Formation at early stage is dominated by open shelf, and then is dominated by large scale lagoon, locally being grain shoal, patchy reef, back shoal and tidal flat. There are three sequences in the Yamama Formation, namely I, II, and III, from bottom to top. During the regression cycle, the sequence I is dominated by cementation, the sequence II by dissolution, and the sequence III by alternating cementation and dissolution. The reservoirs are composed of packstone, wackstone and bindstone, with varying lithological sequence laterally which is difficult to be correlated. The reservoirs are porous, with the space contributed by micropores, moldic pores, and skeletal pores, as well as less primary intergranular pores, corresponding to medium- and micro-throats. The physical properties generally exhibit low to medium porosity, and low to ultra-low permeability. The medium-high permeability reservoirs are underdeveloped. It is found that the development of favorable reservoir in semi-restricted carbonate ramp are controlled by high-energy sedimentation locally, soluble bioclastic enrichment, and intense dissolution. Local high-energy grain shoals and patchy reef contain primary intergranular pores with no intense cementation, and they are important facies of favorable reservoirs in semi-restricted carbonate ramp. Low- to medium-energy facies such as lagoon and back shoal are rich in soluble bioclastics such as Algae and Bacinella. The bioclastics were intensely dissolved, forming a large number of moldic pores and skeletal pores, which effectively improved the reservoir physical properties, thus facilitating the formation of large-scale favorable reservoirs. The favorable reservoirs of the Yamama Formation in Oilfield A are mainly distributed in the north-central anticline axis of YA member and YB member.

The application framework leveraging large language models (LLMs) is explored to address the sophisticated demands of data retrieval and analysis, detailed well profiling, computation of key technical indicators, and the development of solutions in reservoir dynamic analysis (RDA). This framework encompasses a large language foundation model augmented with incremental pre-training, fine-tuning, and subsystems coupling. Key innovations in specialized fine-tuning technologies include named entity recognition (NER) based on prompt engineering, classification-based tool invocation, and Text-to-SQL construction, all aimed at resolving pivotal challenges in developing the specific application of LLMs for RDA. This study conducted a detailed accuracy test on feature extraction models, tool classification models, data retrieval models, and analysis recommendation models. The results indicate that these models have demonstrated good performance in various key aspects of reservoir dynamic analysis. The research takes some injection and production well groups in the real block of the PK3 Fault Block transition zone of the Daqing Oilfield as an example for testing. Testing results show that our model has significant potential and practical value in assisting reservoir engineers with RDA. The research results provide a powerful support to the application of LLM in reservoir performance analysis.

The fracture propagation and channeling patterns of zipper fracturing under the factory-like development mode of deep shale gas well remain unclear. Based on the finite element-discrete element method, a fluid-solid coupling model for fracture propagation of zipper fracturing was established, which incorporates the influence of natural fracture zone. This model was validated using both experimental data and field-monitored pressure surge data. Taking the deep shale gas reservoirs in southern Sichuan Basin as example, the propagation and channeling patterns of hydraulic fractures under the influences of natural fracture zones with various characteristics were investigated. The results show that the fracture zone with large approaching angle can block the forward propagation of hydraulic fractures and the intersection of inter well fractures. During pump shutdown, hydraulic fractures continue to expand under the net pressure driving. Under high stress difference, as the approaching angle of the fracture zone increases, the pressure increase of response well shows a trend of decreasing and then increasing, and the total length of hydraulic fractures tends to increase and then decrease. Compared to fracture zones with small approaching angle, natural fracture zones with large approaching angles require longer time to intersect; The width of fracture zone and the length of natural fractures, respectively, are negatively and positively correlated with the increase in response well pressure, and positively and negatively correlated with the time required for channeling, the total length of hydraulic fractures, and fracturing efficiency. As the well displacement increases, the probability of fractures channeling decreases, but the influence regularity between the well displacement and the increase in response well pressure and total length of hydraulic fractures is not obvious.

By benchmarking with the iteration of drilling technology, fracturing technology and well placement mode for shale oil and gas development in the United States, and considering the geological characteristics and development difficulties of shale oil in the Jiyang continental rift lake basin, the development technology system suitable for the geological characteristics of shale oil in continental fault lake basins has been primarily formed through innovation and iteration of development technology, drilling technology and fracturing technology. The technology system supports the rapid growth of shale oil production and reduces the development investment cost. By comparing with the shale oil development technology in the United States, the prospect of the shale oil development technology iteration in continental rift lake basins is proposed. It is suggested to continuously strengthen the overall three-dimensional development, improve the precision level of engineering technology, upgrade the engineering technical indicator system, accelerate the intelligent optimization of engineering equipment, explore the application of complex structure wells, form a whole-process integrated quality management system from design to implementation, and constantly innovate the concept and technology of shale oil development, so as to promote the realization of extensive, beneficial and high-quality development of shale oil in continental fault lake basins.

Based on an elaboration of the resource potential and annual production of tight sandstone gas and shale gas in the United States and China, this paper reviews the researches on distribution of tight sandstone gas and shale gas reservoirs, and analyzes the distribution characteristics and genetic types of tight sandstone gas reservoirs. It is indicated that, in the United States, the proportion of tight sandstone gas in the total gas production declined from 20%-35% in 2008 to about 8% in 2023, and the shale gas production was 8 310×10⁸ m³ in 2023, as about 80% of the total gas production, in contrast to the range of 5%-17% during 2000-2008. In China, the proportion of tight sandstone gas in the total gas production increased from 16% in 2010 to 28% or higher in 2023. China began to produce shale gas in 2012, with the production reaching 250×10⁸ m³ in 2023, as about 11% of the country's total gas production. The distribution of shale gas reservoirs is continuous. According to the fault presence and the gas layer thickness, the continuous shale gas reservoirs can be divided into two types: continual and intermittent. Most of previous studies believed that both tight sandstone gas reservoirs and shale gas reservoirs are continuous, but this paper holds that the distribution of tight sandstone gas reservoirs is not continuous. According to the trap types, tight sandstone gas reservoirs can be divided into lithologic, anticlinal, and synclinal reservoirs. The tight sandstone gas is coal-derived gas in typical basins in China and Egypt, but oil-type gas in typical basins in the United States and Oman.

This paper reviews the basic research means for oilfield development and also the researches and tests of enhanced oil recovery (EOR) methods for mature oilfields and continental shale oil development, analyzes the problems of EOR methods, and proposes the relevant research prospects. The basic research means for oilfield development include in-situ acquisition of formation rock/fluid samples and non-destructive testing. The EOR methods for conventional and shale oil development are classified as modified water flooding (e.g. nano-water flooding), chemical flooding (e.g. low-concentration middle-phase micro-emulsion flooding), gas flooding (e.g. mcro/nano bubble flooding), thermal recovery (e.g. air injection thermal-aided immiscible flooding), and multi-cluster uniform fracturing/water-free fracturing, which are discussed in this paper for their mechanisms, approaches, and key technique research and field test. These methods have been studied with remarkable progress, and some achieved ideal results in field tests. Nonetheless, some problems exist, such as inadequate research on mechanisms, imperfect supporting processes, and incomplete industrial chains. It is proposed to further strengthen the basic researches and expand the field tests, thereby driving the formation, promotion and application of new technologies.

To address the key problems in the application of intelligent technology in geothermal development, smart application scenarios for geothermal development were constructed. The research status and existing challenges of intelligent technology in each scenario were analyzed, and the construction scheme of smart geothermal field system was proposed. The smart geothermal field is an organic integration of geothermal development engineering and advanced technologies such as the artificial intelligence. At present, the technology of smart geothermal field is still in the exploratory stage. It has been tested for application in scenarios such as intelligent characterization of geothermal reservoirs, dynamic intelligent simulation of geothermal reservoirs, intelligent optimization of development schemes and smart management of geothermal development. However, it still faces many problems, including the high computational cost, difficult real-time response, multiple solutions and strong model dependence, difficult real-time optimization of dynamic multi-constraints, and deep integration of multi-source data. Therefore, the construction scheme of smart geothermal field system is proposed, which consists of modules including the full database, intelligent characterization, intelligent simulation and intelligent optimization control. The connection between modules is established through the data transmission and the model interaction. In the next stage, it is necessary to focus on the basic theories and key technologies in each module of the intelligent geothermal field system, accelerate the lifecycle intelligent transformation of the geothermal development and utilization, and promote the intelligent, stable, long-term, optimal and safe production of geothermal resources.

The research progress of deep and ultra-deep drilling fluid technology at home and abroad is systematically reviewed, the key problems existing are analyzed, and the future development direction is proposed. In view of the high temperature, high pressure and high stress, fracture development, wellbore instability, drilling fluid lost circulation and other problems faced in the process of deep and ultra-deep complex oil and gas drilling, domestic and foreign scholars have developed deep and ultra-deep high-temperature and high-salt resistant water-based drilling fluid technology, high-temperature resistant oil-based/synthetic drilling fluid technology, drilling fluid technology for reservoir protection and drilling fluid lost circulation control technology. However, there are still some key problems such as insufficient resistance to high temperature, high pressure and high stress, well wall instability and serious lost circulation. Therefore, the development direction of deep and ultra-deep drilling fluid technology in the future is proposed: (1) The technology of high temperature resistant water-based drilling fluid should focus on improving high temperature stability, improving rheological properties, strengthening filtration control and improving compatibility with formation. (2) The technology of oil-based/synthetic drilling fluid resistant to high temperature should further study in the aspects of easily degradable environmental protection additives with low toxicity such as high temperature stabilizer, rheological regulator and related supporting technologies. (3) The drilling fluid technology for reservoir protection should be devoted to the development of new high-performance additives and materials, and further improve the real-time monitoring technology by introducing advanced sensor networks and artificial intelligence algorithms. (4) The lost circulation control of drilling fluid should pay more attention to the integration and application of intelligent technology, the research and application of high-performance plugging materials, the exploration of diversified plugging techniques and methods, and the improvement of environmental protection and production safety awareness.

This article elucidates the concept of large model technology, summarizes the research status of large model technology both domestically and internationally, provides an overview of the application status of large models in vertical domains, outlines the challenges and issues confronted in applying large models in the oil and gas sector, and offers prospects for the application of large models in the oil and gas industry. The existing large models can be divided into three categories: large language models, visual large models, and multimodal large models. The application of large models in the oil and gas industry is still in its infancy. Based on open-source large language models, some oil and gas enterprises have released large language model products using methods like fine-tuning and retrieval augmented generation. Several scholars have attempted to develop scenario-specific models for oil and gas operations by using visual/multimodal foundation models. Additionally, a few researchers have constructed pre-trained foundation models for seismic data processing and interpretation, as well as core analysis. The application of large models in the oil and gas industry faces challenges such as current data quantity and quality being difficult to support the training of large models, high research and development costs, and poor algorithm autonomy and control. The application of large models must be guided by the needs of oil and gas business, to take the application of large models as an opportunity to improve data lifecycle management, enhance data governance capabilities, promote the construction of computing power, strengthen the construction of “artificial intelligence + energy” composite teams, and boost the autonomy and control of big model technology.

Taking the Lower Cretaceous Qingshuihe Formation in the southern margin of Junggar Basin as an example, the influences of the burial process on the diagenesis and the development of high-quality reservoirs of deep and ultra-deep clastic rocks was investigated using thin section, scanning electron microscope, electron probe, stable isotopic composition and fluid inclusion data. The Qingshuihe Formation went through four burial stages of "slow shallow burial", "tectonic uplift", "progressive deep burial" and "rapid deep burial" successively. The stages of "slow shallow burial" and "tectonic uplift" not only can alleviate the mechanical compaction of grains, but also can maintain an open diagenetic system in the reservoir for a long time, which promotes the dissolution of soluble components by meteoric freshwater and inhibits the precipitation of dissolution products. The late “rapid deep burial” process contributed to the development of fluid overpressure, which effectively inhibits the destruction of primary pores by compaction and cementation. Moreover, the fluid overpressure promotes the development of microfractures in the reservoir, which enhances the dissolution effect of organic acids. Based on the quantitative reconstruction of porosity evolution history, it is found that the long-term "slow shallow burial" and "tectonic uplift" processes make the greatest contribution to the development of deep-ultra-deep high-quality clastic rock reservoirs, followed by the late "rapid deep burial" process, and the "progressive deep burial" process has little contribution.

The ternary-element storage and flow theory for shale oil reservoirs in Jiyang Depression, Bohai Bay Basin, East China, was proposed based on the experiments of more than 10,000 meters cores and the practical production of more than 60 horizontal wells. The synergy of three elements (storage, fracture and pressure) contributes the enrichment and high production of shale oil in Jiyang Depression. The storage element controls the enrichment of shale oil; specifically, the presence of inorganic pores and fractures, as well as laminae textures of lime-mud rocks, in the saline lake basin, is conducive to the storage of shale oil, and the high hydrocarbon generating capacity and free hydrocarbon content are the material basis for high production. The fracture element controls the shale oil flow; specifically, natural fractures act as flow channels for shale oil to migrate and accumulate, and induced fractures communicate natural fractures to form complex fracture network, which is fundamental to high production. The pressure element controls the high and stable production of shale oil; specifically, the high formation pressure provides the drive force for the migration and accumulation of hydrocarbons, and fracturing stimulation significantly increases the elastic energy of rock and fluid, improves the imbibition replacement of oil in the pores/fractures, and reduces the stress sensitivity, guaranteeing the stable production of shale oil for a long time. Based on the ternary-element storage and flow theory, a 3D development technology was formed, with the core techniques of 3D well pattern optimization, 3D balanced fracturing, and full-cycle optimization of adjustment and control. This technology effectively guides the production and provides a support to the large-scale beneficial development of shale oil in Jiyang Depression.

A physical simulation method with a combination of dynamic displacement and imbibition was established by integrating nuclear magnetic resonance (NMR) and CT scanning. The microscopic pore throat production mechanism of tight/shale oil dynamic imbibition and the influencing factors on the development effect of dynamic imbibition were analyzed. The dynamic seepage process of fracking-soaking-backflow-production integration was simulated, which reveals the dynamic production characteristics of different development stages and their contribution to enhancing oil recovery (EOR). The results show that the seepage of tight/shale reservoirs can be divided into three stages: strong displacement and weak imbibition produced rapidly by displacement between macropores and fractures, weak displacement and strong imbibition produced slowly by reverse imbibition of small pores, and weak displacement and weak imbibition at dynamic equilibrium. The greater the displacement pressure, the higher the displacement recovery, and the lower the imbibition recovery. However, if the displacement pressure is too high, the injected water is easy to break through the front and reduce the recovery degree. The higher the permeability, the greater the imbibition and displacement recovery, the shorter the time of imbibition balance, and the higher the final recovery. The fracture can effectively increase the imbibition contact area between matrix and water, reduce the oil-water seepage resistance, promote the oil-water displacement between matrix and fracture, and improve the oil displacement rate and recovery of the matrix. The soaking after fracturing is beneficial to the imbibition replacement and energy storage of the fluid; also, the effective use of the carrying of the backflow fluid and the displacement in the mining stage is the key to enhancing oil recovery.

Thin section and argon-ion polishing-scanning electron microscope observations were used to analyze the sedimentary and diagenetic environments and main diagenesis of the Fengcheng Formation shales in different depositional zones of Mahu Sag in the Junggar Basin, and to reconstruct their differential diagenetic evolutional processes. The diagenetic environment of shales in the central region of alkaline lake can keep alkaline, which mainly underwent the early stage (R_o<0.5%) dominated by authigenic Na-containing carbonates and K-feldspar and the late stage (R_o>0.5%) dominated by replacement of Na-containing carbonates by reedmergnerite. The shales from the gentle slope zone of lake margin underwent a transition from weak alkaline to acidic diagenetic environments, with the early stage dominated by authigenic minerals of Mg-containing clay and silicoide and later stage dominated by the dissolution of feldspar and carbonate minerals. The shales from the transitional zone also underwent a transition from an early alkaline diagenetic environment (evidenced by authigenic dolomite and zeolite) to a later acidic diagenetic environment (represented by reedmergnerite replacement and silicification). The differences in forming authigenic minerals during early stage determine the fracability of shales. The differences in dissolution of minerals during late stage control the content of free shale oil. Dolomitic shales and silty shales from the transitional zone-marginal zone have relatively high content of free shale oil and strong fracability, and are favorable “sweet spots” for shale oil exploitation.

The existing automatic correlation methods are mainly data-driven methods, which are difficult to adapt to the automatic correlation of oil-bearing strata with large changes in lateral sedimentary facies and strata thickness. We propose to introduce knowledge-driven in automatic correlation of oil-bearing strata, constraining the correlation process by stratigraphic development patterns and improving the similarity measuring machine and conditional constraint dynamic time warping algorithm to automate correlation of marker layers and the interfaces of each strata, forming an intelligent automatic correlation method of oil-bearing strata based on pattern constraints. The application in Bohai Bay Basin Shishen 100 block shows that the coincidence rate of the marker layers identified by this method is over 95.00%, and the average coincidence rate of identified oil-bearing strata reaches 90.02%, which is about 17 percentage points higher than that of the existing automatic correlation methods. The accuracy of the automatic correlation of oil-bearing strata has been effectively improved.

A seepage-geomechanical coupled embedded fracture flow model has been established for multi-field coupled simulation in tight oil reservoirs, revealing the patterns of change in the pressure field, seepage field, and stress field following long-term water injection in tight oil reservoirs. Based on this, a technique for enhanced oil recovery (EOR) combining multi-field reconstruction and combined displacement-permeation in tight oil reservoirs has been proposed. The study shows that after long-term water flooding for tight oil development, the pressure diffusion range is limited, making it difficult to establish an effective displacement system. The variation in geostress exhibits diversity, with the change in horizontal minimum principal stress being greater than that in horizontal maximum principal stress, and the variation around the injection wells being more significant than that around production wells. The deflection of geostress direction around injection wells is also large. The technology for EOR through multi-field reconstruction and combined displacement-permeation employs water injection wells converted to production and large-scale fracturing techniques to restructure the artificial fracture network system. Through a full lifecycle energy replenishment method of pre-fracturing energy supplementation, energy increase during fracturing, well soaking for energy storage, and combined displacement-permeation, it effectively addresses the issue of easy channeling of the injection medium and difficult energy replenishment after large-scale fracturing. By intensifying the imbibition effect through the coordination of multiple wells, it reconstructs the combined system of displacement and imbibition under a complex fracture network, transitioning from avoiding fractures to utilizing them, thereby improving microscopic sweep and oil displacement efficiencies. Field application in Block Yuan 284 of the Huaqing Oilfield in the Ordos Basin has demonstrated that this technology increases the recovery factor by 12 percentage points, enabling large scale and efficient development of tight oil.

Based on the global basement reservoir database and the dissection of basement reservoirs in China, the characteristics of hydrocarbon accumulation in basement reservoirs are analyzed, and the favorable conditions for hydrocarbon accumulation in deep basement reservoirs are investigated to highlight the exploration targets. The results show that the discovered basement reservoirs worldwide are mainly buried in the Archean and Precambrian granitic and metamorphic formations with depths less than 4500 m, and the relatively large reservoirs have been found in rift, back-arc and foreland basins in tectonic active zones of the Meso-Cenozoic plates. The hydrocarbon accumulation in basement reservoirs exhibits the characteristics in three aspects. First, the porous-fractured reservoirs with low porosity and ultra-low permeability are dominant, where extensive hydrocarbon accumulation occurred during the weathering denudation and later tectonic reworking of the basin basement. High resistance to compaction allows the physical properties of these highly heterogeneous reservoirs to be independent of the buried depth. Second, the hydrocarbons were sourced from the formations outside the basement. The source-reservoir combinations are divided into contacted source rock-basement and separated source rock-basement patterns. Third, the abnormal high pressure in the source rock and the normal-low pressure in the basement reservoirs cause a large pressure difference between the source rock and the reservoirs, which is conducive to the suction charging of hydrocarbons into the deep basement. The deep basement prospects are mainly evaluated by the factors such as tectonic activity of basement, source-reservoir combination, presence of large deep faults (especially strike-slip faults), and regional seals. The Precambrian crystalline basements at the margin of the intra-cratonic rifts, as well as the Paleozoic folded basements and the Meso-Cenozoic fault-block basements adjacent to the hydrocarbon generation depressions, have favorable conditions for hydrocarbon accumulation, and thus they are considered as the main targets for future exploration of deep basement reservoirs.

Based on the microfluidic technology, a large-scale microscopic visualization model was used to mimic the gas injection process in the initial construction stage and the bottom water invasion/gas injection process in the cyclical injection-production stage of the underground gas storage (UGS) rebuilt from water-invaded gas reservoirs. Through analysis of the gas-liquid contact stabilization mechanism, flow and occurrence, the optimal control method for lifecycle efficient operation of UGS was explored. The results show that in the initial construction stage of UGS, the action of gravity should be fully utilized by regulating the gas injection rate, so as to ensure the macroscopically stable migration of the gas-liquid contact, and greatly improve the gas sweeping capacity, providing a large pore space for gas storage in the subsequent cyclical injection-production stage. In the cyclical injection-production stage of UGS, a constant gas storage and production rate leads to a low pore space utilization. Gradually increasing the gas storage and production rate, that is, transitioning from small volume to large volume, can continuously break the hydraulic stability of the remaining fluid in the porous media, which then expands the pore space and flow channels. This is conducive to the expansion of UGS capacity and efficiency for purpose of peak shaving and supply guarantee.