For shale oil reservoirs in the Jimsar Sag of Junggar Basin, the fracturing treatments are challenged by poor prediction accuracy and difficulty in parameter optimization. This paper presents a fracturing parameter intelligent optimization technique for shale oil reservoirs and verifies it by field application. A self-governing database capable of automatic capture, storage, calls and analysis is established. With this database, 22 geological and engineering variables are selected for correlation analysis. A separated fracturing effect prediction model is proposed, with the fracturing learning curve decomposed into two parts: (1) overall trend, which is predicted by the algorithm combining the convolutional neural network with the characteristics of local connection and parameter sharing and the gated recurrent unit that can solve the gradient disappearance; and (2) local fluctuation, which is predicted by integrating the adaptive boosting algorithm to dynamically adjust the random forest weight. A policy gradient-genetic-particle swarm algorithm is designed, which can adaptively adjust the inertia weights and learning factors in the iterative process, significantly improving the optimization ability of the optimization strategy. The fracturing effect prediction and optimization strategy are combined to realize the intelligent optimization of fracturing parameters. The field application verifies that the proposed technique significantly improves the fracturing effects of oil wells, and it has good practicability.

To improve the accuracy and generalization of well logging curve reconstruction, this paper proposes an artificial intelligence large language model - “Gaia” and conducts model evaluation experiments. By fine-tuning the pre-trained large language model, the Gaia significantly improved its ability in extracting sequential patterns and spatial features from well-log curves. Leveraging the adapter technology for fine-tuning, this model required training only about 1/70 of its original parameters, greatly improving training efficiency. Comparative experiments, ablation experiments, and generalization experiments were designed and conducted using well-log data from 250 wells. In the comparative experiments, the Gaia model was benchmarked against cutting-edge small deep learning models and conventional large language models, demonstrating that the Gaia model reduced the mean absolute error (MAE) by at least 20%. In the ablation experiments, the synergistic effect of the Gaia model's multiple components was validated, with its MAE being at least 30% lower than that of single-component models. In the generalization experiments, the superior performance of the Gaia model in blind-well predictions was further confirmed. Compared to traditional models, the Gaia model is significantly superior in accuracy and generalization for logging curve reconstruction, fully showcasing the potential of large language models in the field of well-logging. This provides a new approach for future intelligent logging data processing.

Based on a large amount of basic research and experimental analysis data from Shengli Oilfield, Bohai Bay Basin, guided by the theory of whole petroleum system, the distribution of sedimentary systems, the distribution and hydrocarbon generation and expulsion process of source rocks, the variation of reservoir properties, and the control of fracture systems on hydrocarbon accumulation in the Paleogene of the Jiyang Depression, Boahai Bay Basin, were systematically analyzed, and the geological characteristics of the whole petroleum system in the fault basin were identified. Taking the Dongying Sag as an example, combined with the distribution of discovered conventional, tight, and shale oil/gas, a hydrocarbon accumulation model of the fault-controlled whole petroleum system in fault basin was proposed, and the distribution patterns of conventional and unconventional oil and gas reservoirs in large geological bodies horizontally and vertically were clarified. The research results show that paleoclimate and tectonic cycles control the orderly distribution of the Paleogene sedimentary system in the Jiyang Depression, the multi-stage source rocks provide sufficient material basis for in-situ shale oil/gas accumulation and other hydrocarbon migration and accumulation, the changes in reservoir properties control the dynamic threshold of hydrocarbon accumulation, and the combination of faults and fractures at different stages controls hydrocarbon migration and accumulation, and in-situ retention and accumulation of shale oil/gas, making the whole petroleum system in the fault basin associated, segmented and abrupt. The above elements are configured to form a composite whole petroleum system controlled by faults in the Paleogene of the Jiyang Depression. Moreover, under the control of reservoir-forming dynamics, a whole petroleum system can be divided into conventional subsystem and unconventional subsystem, with shale oil, tight oil and conventional oil in an orderly distribution in horizontal and vertical directions. This systematic understanding is referential for ananlyzing the whole petroleum system in continental fault basins in eastern China.

Based on large-field rock thin section scanning, high-resolution field emission-scanning electron microscopy (FE-SEM), fluorescence spectroscopy, and rock pyrolysis experiments of the Mesoproterozoic Jixianian Hongshuizhuang Formation shale samples from the Yanliao Basin in northern China, combined with sedimentary forward modeling, a systematic petrological and organic geochemical study was conducted on the reservoir quality, oil-bearing potential, distribution, and resource potential of the Hongshuizhuang Formation shale in Well Yuanji-2. The results indicate that: (1) The original organic carbon content of the Hongshuizhuang Formation shale averages up to 6.24%, and the original hydrocarbon generation potential is as high as 44.09 mg/g, demonstrating a strong oil generation potential. (2) The rock type is primarily siliceous shale containing low clay mineral content, characterized by the development of shale bedding fractures and organic shrinkage fractures, resulting in good compressibility and reservoir quality. (3) The fifth and fourth members of the Hongshuizhuang Formation serve as shale oil sweet spots, contributing more than 60% of shale oil production with their total thickness as only 40% of the target formation. (4) The Kuancheng-Laozhuanghu area is the most prospective shale oil exploration option in the Yanliao Basin and covers approximately 7 200 km². Its original total hydrocarbon generation potential reaches about 74.11 billion tons, with current estimated retained shale oil resources exceeding 1.148 billion tons (lower limit) - comparable to the geological resources of the Permian Lucaogou Formation shale oil in the Jimsar Sag of the Junggar Basin. These findings demonstrate the robust exploration potential of the Hongshuizhuang Formation shale oil in the Yanliao Basin.

Accurate identification of natural gas origin is fundamental to the theoretical research on natural gas geosciences and the exploration deployment and resource potential assessment of oil and gas. 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 isotopic compositions, molecular composition, light hydrocarbon fingerprints, and geological context. This paper systematically reviews the core framework established by him and his team according to related references and application results, 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 identification 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. The structured overview of the development trajectory of natural gas origin discrimination methodologies provides a technical support for natural gas geological theory and practice and offer a scientific foundation for the academic evaluation and application of related achievements.

Currently, unconventional reservoirs are characterized by low single well-controlled reserves, high initial production but 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 development”. The technical connotation, theoretical model, and core techniques of energy-focused fracturing development are systematically examined, and the implementation path of this technology is determined. The energy-focused fracturing development 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 energy-focused fracturing development technology has been successfully applied in the carbonate reservoirs in buried hill, shallow coalbed methane reservoirs, and coal-rock gas reservoirs in China, demonstrating the technology’s promising application. It is concluded that the energy-focused fracturing development 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 control 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 petroliferous 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 orderly distribution of hydrocarbon accumulations in various circles. A model for the integrated, systematic accumulation 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 sag 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.

This study systematically reviews the development history and key technological breakthrough of large gas fields in the Ordos Basin, and summarizes the development models of three gas reservoir types, low-permeability carbonates, low-permeability sandstones and tight sandstones, as well as the progress in deep coal-rock gas development. The current challenges and future development directions are also discussed. Mature development models have been formed for the three representative types of gas reservoirs in the Ordos Basin: (1) Low-permeability carbonate reservoir development model featuring groove fine-scale characterization and three-dimensional vertical succession between Upper and Lower Paleozoic formations. (2) Low-permeability sandstone reservoir development model emphasizing horizontal well pressure-depletion production and vertical well pressure-controlled production. (3) Tight sandstone gas reservoir development model focusing on single-well productivity enhancement and well placement optimization. In deep coal-rock gas development, significant progress has been achieved in reservoir evaluation, sweet-spot prediction, and geosteering of horizontal wells. The three types of reservoirs have entered the mid-to-late stages of the development, when the main challenge lies in accurately characterizing residual gas, evaluating secondary gas-bearing layers, and developing precise potential-tapping strategies. In contrast, for the early-stage development of deep coal-rock gas, continuous technological upgrades and cost reduction are essential to achieving economically viable large-scale development. Four key directions of future research and technological breakthroughs are proposed: (1) Utilizing dual-porosity (fracture-matrix) modeling techniques in low-permeability carbonate reservoirs to delineate the volume and distribution of remaining gas in secondary pay zones, supporting well pattern optimization and production enhancement of existing wells. (2) Integrating well-log and seismic data to characterize reservoir spatial distribution of successive strata, enhancing drilling success rates in low-permeability sandstone reservoirs. (3) Utilizing the advantages of horizontal wells to penetrate effective reservoirs laterally, achieving meter-scale quantification of small-scale single sand bodies in tight gas reservoirs, and applying high-resolution 3D geological models to clarify the distribution of remaining gas and guide well placement optimization. (4) Further strengthening the evaluation of deep coal-rock gas in terms of resource potential, well type and pattern, reservoir stimulation, single-well performance, and economic viability.

During drilling operations, the low resolution of seismic data often limit the accurate characterization of small-scale geological bodies near the borehole and ahead of the drill bit. This study investigates high-resolution seismic data processing technologies and methods tailored for drilling scenarios. The high-resolution processing of seismic data is divided into three stages: pre-drilling processing, post-drilling correction, and while-drilling updating. By integrating seismic data from different stages, spatial ranges, and frequencies, together with information from drilled wells and while-drilling data, and applying artificial intelligence modeling techniques, a progressive high-resolution processing technology of seismic data based on multi-source information fusion is developed, which performs simple and efficient seismic information updates during drilling. Case studies show that, with the gradual integration of multi-source information, the resolution and accuracy of seismic data are significantly improved, and thin-bed weak reflections are more clearly imaged. The updated seismic information while-drilling demonstrates high value in predicting geological bodies ahead of the drill bit. Validation using logging, mud logging, and drilling engineering data ensures the fidelity of the processing results of high-resolution seismic data. This provides clearer and more accurate stratigraphic information for drilling operations, enhancing both drilling safety and efficiency.

This study takes shale samples from the Jiaoshiba block in the Fuling shale gas field of the Sichuan Basin, and uses the true triaxial testing system to conduct a series of mechanical experiments under deep shale reservoir conditions after shale hydration. Stress-strain data and mechanical parameters of shale after hydration under high temperature and high pressure were obtained to investigate the effects of reservoir temperature, hydration time and horizontal stress difference on the mechanical strength of shale after hydration. By using nonlinear regression and interpolation methods, a prediction model for the mechanical strength of shale after hydration was constructed, and the mechanical strength chart of deep shale under high stress difference was plotted. First, higher hydration temperature, longer hydration reaction time, and greater horizontal stress difference cause shale to enter the yield stage earlier during the compression process after hydration and to exhibit more prominent plastic characteristics, lower peak strength, peak strain, residual strength and elastic modulus, and higher Poisson’s ratio. Second, the longer the hydration time, the smaller the impact of hydration temperature on the mechanical strength of deep shale. As the horizontal stress difference increases, the peak strength and residual strength weaken intensely, and the peak strain, elastic modulus and Poisson’s ratio deteriorate slowly. Third, the mechanical strength of shale decreases significantly in the first 5 days of hydration, but gradually stabilizes as the hydration time increases. Fourth, the visual mechanical strength chart helps to understand the post-fracturing dynamics in deep shale gas reservoir fracturing site and adjust the drainage and production plan in time.

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 proved gas initially-in-place (merely 2264.33×10⁸ 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, the natural gas industry of China has developed rapidly. By the end of 2023, China registered the cumulative proved gas initially-in-place 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 proved reserves initially-in-place 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 promoted China from a gas-poor country to a major gas-producing country in the world.

Taking the Wangfu fault depression 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 fault depression 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 controls 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.

The core sampling experiments conducted after hydraulic fracturing were carried out in the three-dimensional development zone of Fuling shale gas. Six coring wells of different well types were systematically designed. Based on the integrated engineering technology of post-fracturing drilling, coring and monitoring of shale and the analysis of fracture source tracing, the evaluation of the fracture network after fracturing in the three-dimensional development of shale gas was conducted. The data of core fractures after fracturing indicate that three major types of fractures are formed after fracturing: natural fractures, hydraulic fractures, and fractures induced by external mechanical force, which are further classified into six subcategories: natural structural fractures, natural bedding fractures, hydraulic fractures, hydraulically activated fractures, drilling induced fractures, and fractures induced by core transportation. The forms of the artificial fracture network after fracturing are complex. Hydraulic fractures and hydraulically activated fractures interweave with each other, presenting eight forms of artificial fracture networks, among which the linear simple fracture is the most common, accounting for approximately 70% of the total fractures. When the distance from the fractured wellbore is less than 35 m, the density of the artificial fracture network is relatively high; when it is 35-100 m, the density is lower; and when it is beyond 100 m, the density gradually increases. The results of the fracture tracing in the core sampling area confirm that the current fracturing technology can essentially achieve the differential transformation of the reservoir in the main area of Jiaoshiba block in Fuling. The three-layer three-dimensional development model can efficiently utilize shale gas reserves, although there is still room for improvement in the complexity and propagation uniformity of fractures. It is necessary to further optimize technologies such as close-cutting combined with temporary plugging and diverting within fractures or at fracture mouths, as well as limited entry perforation, to promote the balanced initiation and extension of fractures.

The presence of clay coatings on the surfaces of quartz grains can play a pivotal role in determining the porosity and permeability of sandstone reservoirs, thus directly impacting their reservoir quality. This study employs a multiphase-field model of syntaxial quartz cementation to explore the effects of clay coatings on quartz cement volumes, porosity, permeability, and their interrelations in sandstone formations. To generate various patterns of clay coatings on quartz grains within three-dimensional (3D) digital sandstone grain packs, a pre-processing toolchain is developed. Through numerical simulation experiments involving syntaxial overgrowth cementation on both single crystals and multigrain packs, the main coating parameters controlling quartz cement volume are elucidated. Such parameters include the growth of exposed pyramidal faces, lateral encasement, coating coverage, and coating pattern, etc. The coating pattern has a remarkable impact on cementation, with the layered coatings corresponding to fast cement growth rates. The coating coverage is positively correlated with the porosity and permeability of sandstone. The cement growth rate of quartz crystals is the lowest in the vertical orientation, and in the middle to late stages of evolution, it is faster in the diagonal orientation than in the horizontal orientation. Through comparing the simulated results of dynamic evolution process with the actual features, it is found that the simulated coating patterns after 20 and 40 d show clear similarities with laboratory physical experiments and natural samples, proving the validity of the proposed three-dimensional numerical modeling of coatings. The methodology and findings presented contribute to improved reservoir characterization and predictive modeling of sandstone formations.

The method for optimizing the hydraulic fracturing parameters of the cube development infill well pad was proposed, aiming at the well pattern characteristic of “multi-layer and multi-period” of the infill wells in Sichuan Basin. The fracture propagation and inter-well interference mode were established based on the evolution of 4D in-situ stress, and the evolution characteristics of stress and the mechanism of interference between wells were analyzed. The research shows that the increase in horizontal stress difference and the existence of natural fractures/faults are the main reasons for inter-well interference. Inter-well interference is likely to occur near the fracture zones and between the infill wells and parent wells that have been in production for a long time. When communication channels are formed between the infill wells and parent wells, it can increase the productivity of parent wells in the short term. However, it will have a delayed negative impact on the long-term sustained production of both infill wells and parent wells. The change trend of in-situ stress caused by parent well production is basically consistent with the decline trend of pore pressure. The lateral disturbance range of in-situ stress is initially the same as the fracture length and reaches 1.5 to 1.6 times that length after 2.5 years. The key to avoiding inter-well interference is to optimize the fracturing parameters. By adopting the M-shaped well pattern, the optimal well spacing for the infill wells is 300 m, the cluster spacing is 10 m, and the liquid volume per stage is 1 800 m³.

Conventional borehole image log interpretation of linear fractures on volcanic rocks represented as sinusoids on unwrapped cylinder projections is relatively straight-forward, however, interpreting non-linear rock structures and complex facies geometries can be more challenging. To characterize diverse volcanic paleoenvironments related to the formation of the South American continent, this study presents a new methodology based on image logs, petrography, and seismic data. The presented methodology used pseudo-boreholes images generated from outcrop photographs with typical igneous rock features worldwide simulating 2D unwrapped cylinder projections of a 31 cm (12.25 in) diameter well. These synthetic images and standard outcrop photographs were used to define morphological patterns of igneous structures and facies for comparison with wireline borehole image logs from subsurface volcanic and subvolcanic units, providing a “visual scale” for geological evaluation of volcanic facies, significantly enhancing the identification efficiency and reliability of complex geological structures. Our analysis focused on various scales of columnar jointing and pillow lava lobes with additional examples including pahoehoe lava, ignimbrite, hyaloclastite, and various intrusive features in Campos, Santos, and Parnaíba basins in Brazil. This approach increases confidence in the interpretation of subvolcanic, subaerial, and subaqueous deposits. The image log interpretation combined with regional geological knowledge has enabled paleoenvironmental insights into the rift magmatism system related to the breakup of Gondwana with associated implications for hydrocarbon exploration.

The Mesozoic volcanic rocks of the Bodong Low Uplift in the Bohai Bay Basin have been studied and explored for years. In 2024, the LK7-A well drilled in this region tested high-yield oil and gas flows from volcanic weathered crust. These volcanic rocks need to be further investigated in terms of distribution patterns, conditions for forming high-quality reservoirs, and main factors controlling hydrocarbon accumulation. Based on the logging, geochemical and mineralogical data from wells newly drilled to the Mesozoic volcanic rocks in the basin, and high-resolution 3D seismic data, a comprehensive study was conducted for this area. The research findings are as follows. First, the volcanic rocks in the LK7-A structure are adakites with a large source area depth, and the deep and large faults have provided channels for the emplacement of intermediate-acidic volcanic rocks. Second, volcanic rock reservoirs are mainly distributed in tectonic breccias and intermediate-acidic lavas, and they are dominantly fractured-porous reservoirs, with high-porosity and low-permeability or medium-porosity and low-permeability. Third, the dominant lithologies/lithofacies represent a fundamental condition for forming large-scale volcanic rock reservoirs. Structural fractures and late-stage strong weathering are crucial mechanisms for the continuous formation of reservoirs in the Mesozoic volcanic rocks. Fourth, the Bodong Low Uplift exhibits strong hydrocarbon charging by two sags and overpressure mudstone capping, which are favorable for forming high-abundance oil and gas reservoirs. The Mesozoic volcanic buried hills in the study area reflect good trap geometry, providing favorable conditions for large-scale reservoir formation, and also excellent migration and accumulation conditions. Areas with long-term exposure of intermediate-acidic volcanic rocks, particularly in active structural regions, are key targets for future exploration.

For deep prospects in the foreland thrust belt, southern Junggar Basin, NW China, there are uncertainties in factors controlling the structural deformation, distribution of paleo-structures and detachment layers, and distribution of major hydrocarbon source rocks. Based on the latest 3D seismic, gravity-magnetic, and drilling data, together with the results of previous structural physical simulation and discrete element numerical simulation experiments, the spatial distribution of pre-existing paleo-structures and detachment layers in deep strata of southern Junggar Basin were systematically characterized, the structural deformation characteristics and formation mechanisms were analyzed, the distribution patterns of multiple hydrocarbon source rock suites were clarified, and hydrocarbon accumulation features in key zones were reassessed. The exploration targets in deep lower assemblages with possibility of breakthrough were expected. Key results are obtained in three aspects. First, structural deformation is controlled by two-stage paleo-structures and three detachment layers with distinct lateral variations: the Jurassic layer (moderate thickness, wide distribution), the Cretaceous layer (thickest but weak detachment), and the Paleogene layer (thin but long-distance lateral thrusting). Accordingly, a four-layer composite deformation sequence was identified, and the structural genetic model with paleo-bulge controlling zonation by segments laterally and multiple detachment layers controlling sequence vertically. Second, the Permian source rocks show a distribution pattern with narrow trough (west), multiple sags (central), and broad basin (east), which is depicted by combining high-precision gravity-magnetic data and time-frequency electromagnetic data for the first time, and the Jurassic source rocks feature thicker mudstones in the west and rich coals in the east according to the reassessment. Third, two petroleum systems and a four-layer composite hydrocarbon accumulation model are established depending on the structural deformation strength, trap effectiveness and source-trap configuration. The southern Junggar Basin is divided into three segments with ten zones, and a hierarchical exploration strategy is proposed for deep lower assemblages in this region, that is, focusing on five priority zones, expanding to three potential areas, and challenging two high-risk targets.

To optimize the bit selection for large-diameter wellbore in the upper section of an ultra-deep well S-1, a full-well dynamic model integrating drill string vibration and bit rock-breaking was established and then verified using measured vibration data of drilling tools and actual rate of penetration (ROP) from Well HT-1 in northern Sichuan Basin. This model was employed to calculate and analyze drill string dynamic characteristics during large-diameter wellbore drilling in the Jurassic Penglaizhen Formation of Well S-1, followed by bit optimization. Research results show that during the drilling in Penglaizhen Formation of Well S-1, considering both the ROP of six candidate bits and the lateral/axial/torsional vibration characteristics of downhole tools, the six-blade dual-row cutter bit with the fastest ROP (average 7.12 m/h) was optimally selected. When using this bit, the downhole tool vibration levels remained at medium-low values. Field data showed over 90% consistency between actual ROP data and dynamic model calculation results after bit placement, demonstrating that the model can be used for bit program screening.

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

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

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

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

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

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

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

To clarify the mechanism of differential enrichment of intrasource shale oil, taking the third of seventh member of the Triassic Yanchang Formation (Chang7₃ submember for short) in the Ordos Basin as an example, we integrated high-resolution scanning electron microscopy (SEM), optical microscopy, laser Raman spectroscopy, rock pyrolysis, and organic solvent extraction experiments to identify solid bitumen of varying origins, obtain direct evidence of intrasource micro-migration of shale oil, and establish the coupling between the shale nano/micro-fabric and the oil generation, migration and accumulation. The Chang7₃ shale with rich alginite in laminae has the highest hydrocarbon generation potential but a low thermal transformation ratio. Frequent alternations of micron-scale argillaceous-felsic laminae enhance the hydrocarbon expulsion efficiency, yielding consistent aromaticity between in-situ and migrated solid bitumen. Mudstone laminae rich in terrestrial organic matter (OM) and clay minerals exhibit lower hydrocarbon generation threshold but stronger hydrocarbon retention capacity, with a certain amount of light oil/bitumen preserved to differentiate the chemical structure of in-situ versus migrated bitumen. Tuffaceous and sandy laminae contain abundant felsic minerals and migrated bitumen. Tuffaceous laminae develop high-angle microfractures under shale overpressure, facilitating oil charging into rigid mineral intergranular pores of sandy laminae. Fractionation during micro-migration progressively decreases the aromatization of solid bitumen from shale, through tuffaceous and mudstone, to sandy laminae, while increasing light hydrocarbon components and enhancing OM-hosted pore development. The intrasource micro-migration and enrichment of the Chang7₃ shale oil result from synergistic organic-inorganic diagenesis, with crude oil component fractionation being a key mechanism for forming sweet spots in laminated shale oil reservoirs.

Lacustrine rift basins in China are characterized by pronounced structural segmentation, strong sedimentary heterogeneity, extensive fault-fracture development, and significant variability in thermal maturity and mobility of shale oil. This study reviews the current status of exploration and development of shale oil in such basins and examines theoretical frameworks such as “binary enrichment” and source-reservoir configuration, with a focus on five key subjects: (1) sedimentation-diagenesis coupling mechanisms of fine-grained shale reservoir formation; (2) dynamic diagenetic evolution and hydrocarbon occurrence mechanisms of organic-rich shale; (3) dominant controls and evaluation methods for shale oil enrichment; (4) fracturing mechanisms of organic-rich shale and simulation of artificial fracture networks; and (5) flow mechanisms and effective development strategies for shale oil. Integrated analysis suggests that two major scientific challenges must be addressed: the coupled evolution of fine-grained sedimentation, differential diagenesis, and hydrocarbon generation under tectonic influence and its control on shale oil occurrence and enrichment; and multi-scale, multiphase flow mechanisms and three-dimensional development strategies for lacustrine shale oil in complex fault blocks. In response to current exploration and development bottlenecks, future research will be conducted primarily to: (1) deeply understand organic-inorganic interactions and reservoir formation mechanisms in organic-rich shales, and clarify the influence of high-frequency sequence evolution and diagenetic fluids on reservoir space; (2) elucidate the dynamic processes of hydrocarbon generation, expulsion, and retention across different lithofacies, and quantify their relationship with thermal maturity, including the conditions for the formation of self-sealing systems; (3) develop a geologically adaptive, data- and intelligence-driven quantitative classification and grading evaluation system of shale oil; (4) reveal artificial fracture propagation pattern and optimize physical field coupled fracturing technologies for complex lithofacies assemblages; and (5) overcome challenges in multi-scale geological modeling and multiphase flow characterization, and establish advanced numerical simulation methodologies.

To address the unclear permeability evolution mechanisms during in-situ conversion of deep continental shale, this study employs a self-developed online THMC (thermo-hydro-mechanical-chemical)-CT coupled experimental system to investigate the permeability evolution, dynamic pore-fracture structural responses, and hydrocarbon production behavior under high-temperature and high-stress conditions. The results show that: (1) Under high stress constraints (axial/confining stresses of 50/25, 100/50 MPa), shale permeability exhibits a three-stage evolution with increasing temperature, including a low-permeability stage (25-350 ℃), a rapid-increase stage (350-450 ℃), and a significant-decrease stage (450-600 ℃). (2) Under coupled in-situ stress (25/20 MPa axial/confining stress) and temperature, fractures undergo a dynamic “two-expansion and two-contraction” process, where the first expansion (25-300 ℃) and first contraction (300-350 ℃) correspond to the low-permeability stage, the second expansion (350-450 ℃) corresponds to the rapid-increase stage, and the second contraction (450-550 ℃) corresponds to the significant-decrease stage. (3) The controlling mechanisms at each stage are as follows: at temperatures up to 350 ℃, the maximum yield of retained oil and the filling of heavy hydrocarbons in pores and fractures result in reduced permeability. Between 350 ℃ and 450 ℃, thermal cracking and kerogen decomposition jointly enhance pore-fracture network development. Above 450 ℃, illitization of clay minerals, matrix plastic deformation, and fracture closure under stress result in permeability reduction. These findings clarify the staged permeability behavior and associated mechanisms, providing essential theoretical and experimental support for the temperature-stress synergistic optimization of in-situ shale oil conversion processes.

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.

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

Based on 3D seismic, logging, and core data from the Tahe Oilfield, Tarim Basin, this study carried out logging-based identification of cave filling facies in drilled Ordovician paleokarst conduits and quantitative calculation of filling degree, and analyzed the internal structure of paleokarst conduits. On this basis, a quantitative prediction of the filling degree of conduit networks in plan view was achieved by constructing a nonlinear relationship model. The results show that, according to differences in petrophysical fabric, filling facies in drilled caves can be classified into host-rock facies within caves, sandy-muddy cemented conglomeratic clastic facies, transported sandstone facies, chemical sedimentary filling facies and unfilled cave facies. Using a convolutional neural network algorithm, the filling degree of 156 drilled caves in the study area was quantitatively calculated, among which caves with a filling degree greater than 80% account for 39.7%, whereas those with a filling degree less than 20% account for only 16.0%. The genetic types of paleokarst conduits were divided into 7 categories: main-stream conduits, tributary conduits, outflow conduits, along-stream conduits, turnaround conduits, sinking-river conduits and labyrinthine conduits; and six conduit morphologies were identified: sinkholes, hall-shaped chambers, underflow loops, horizontal underflow passages, corridor passages and medium-dip passages. On this basis, a backpropagation neural-network- based quantitative prediction method for conduit filling degree was established using geological controlling factors. The prediction results indicate that the filling within paleokarst conduits shows obvious spatial differentiation: the probability of filling is relatively high in underflow loop segments, zones of increased potential energy, and medium-dip passage segments, whereas the spaces above hall-shaped chambers, the upper parts of medium-dip connecting passages, and downstream outlets of conduits have relatively low filling probabilities. The latter should therefore be regarded as key potential targets for future fine-scale development of paleokarst conduit reservoirs.

Outcrop coal samples from the Shizhuang South Block of the Qinshui Basin, Shanxi Province, China, were subjected to true triaxial hydraulic fracturing experiments to simulate frature propagation. Combined with CT scanning and three-dimensional fracture reconstruction, the study examined fracture propagation patterns and bedding activation behaviors under variable pumping-rate fracturing in coal reservoirs. Results indicate that the variable pumping-rate fracturing technique effectively overcomes the strong trapping effect of coal bedding. Micro-fractures are initiated at multiple weak points along bedding planes, leading to multi-point fracture initiation and competitive propagation of fractures toward the far field, thereby generating a more complex three-dimensional fracture network. The geometry and aperture of the induced fracture network are primarily controlled by the ramp-up rate of injection flowrate. A gradual ramp-up favors the development of a more complex fracture network, though at the expense of lower breakdown pressure, insufficient initiation, and narrower apertures. In contrast, a rapid ramp-up produces wider fractures and larger propped lengths, but results in more pronounced aperture fluctuations. For coal reservoirs with relatively high rock strength, a moderately higher ramp-up rate is recommended to avoid excessively narrow fractures and potential proppant bridging. Different coal lithotypes necessitate tailored ramp-up strategies to optimize fracture morphology and stimulation effectiveness.

Four types of volcanic rock samples, i.e. breccia, andesite, tuff, and dacite, selected from the Carboniferous in the Junggar Basin were characterized through experiments such as X-ray diffraction (XRD), scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR) for identifying the acid imbibition and ion diffusion behaviors during fracture acidizing in volcanic rock reservoirs. The results demonstrate that the invaded acid dissolves the minerals and alters the pore structure in the reservoir. Volcanic rocks of different lithologies exhibit substantial variations in their acidification and dissolution effects. Breccia and andesite, which contain abundant calcite and other soluble minerals, show markedly improved pore connectivity after acidizing. In addition, pronounced differences are observed between the acid-induced dissolution responses of oil-rich and water-rich pores within volcanic rocks. In water-rich pores, acid-induced dissolution is dominated by H⁺ diffusion, whereas in oil-rich pores, imbibition-driven dissolution is the primary mechanism. The hydrated hydrogen-ion network formed in water-rich pores enhances H⁺ diffusion, facilitating uniform dissolution across pore scales. As a result, the pore structure becomes more homogenized, leading to a reduction in fractal dimension. In oil-rich pores, acid imbibition driven by capillary pressure is the predominant mechanism, enabling small pores to be dissolved preferentially, followed by medium to large pores. Consequently, the overall extent of acid erosion remains limited, and pore heterogeneity persists at a high level. Both the acid-imbibition and ion-diffusion processes exhibit a three-stage evolution: linear- transitional-stable. In the linear stage, the acid imbibition and H⁺ diffusion distances scale proportionally with the square root of time. In the transitional stage, the H⁺ diffusion rate decreases due to pore-throat blockage induced by the hydration and precipitation of clay minerals. Concurrently, acid imbibition and mineral dissolution enhance the fluid flow capacity, partially offsetting the attenuation of capillary pressure, and sustaining the increase in imbibition rate. In the stable stage, both acid imbibition and ion diffusion approach equilibrium.

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

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

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

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

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

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