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.

The Paleogene Liushagang Formation in the Wushi Sag of the Beibuwan Basin is characterized by dispersed hydrocarbon distribution, small-scale residual exploration targets and large burial depth. Based on data from drilling, laboratory experiments, and geophysic analysis, this study systematically investigates the hydrocarbon accumulation conditions and enrichment patterns in the Liushagang Formation. The key findings are obtained in five aspects. First, the structural evolution of the sag involved three distinct stages: early faulting, mid-stage detachment deformation and late adjustment, governed by an “extension-detachment-strike-slip” composite fault system that controlled basin subsidence, depocenter migration and sedimentary environment evolution. Second, three principal source rock intervals in the Eocene Liushagang Formation, concentrated in the southern East Sub-sag under the control of the No. 7 Fault Zone, are characterized by considerable thickness and high quality, with the oil shale in the lower part of the second member of Liushagang Formation (lower Liu-2 Member) being the most prolific, providing a robust resource foundation in the sag. Third, four reservoir-seal assemblages are identified, corresponding to three hydrocarbon migration systems: direct source-reservoir contact, fault-sandbody coupling, and fault-structural ridge-sandbody stepwise composite networks. Fourth, three accumulation models are established: “young source-old reservoir” with lateral stepwise migration, “self-sourced and self-stored” intra-source enrichment, and “lower source-upper reservoir” with vertical migration. Fifth, exploration priorities are further delineated, highlighting deep fault-block traps in the central zone of the eastern subsag, intrasag lithologic traps, and bedrock buried-hill targets with direct source-reservoir connectivity, all demonstrating significant resource potential.

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.

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

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.

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.

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

Taking the Middle-Upper Cambrian Xixiangchi Group in the central-southern Sichuan Basin as an example, this study investigates the sedimentary characteristics and evolutionary history of tempestites using field outcrop, core, thin-section and logging data, and elucidates the patterns and processes by which storms have reworked grain shoal reservoirs in carbonate platforms, thereby identifying the zones with favorable reservoirs. The results indicate that: (1) The Xixiangchi Group develops massive storm deposits, with five intervals occurred in a complete storm sedimentary sequence; Xixiangchi Group exhibits six typical storm depositional sequences, with storm-related grain shoals developed in settings such as mixed tidal flats, intra-platform depressions, and margins of the intra-platform depressions. (2) During the deposition of the Xixiangchi Group, storm activities were mainly in the southeastern, central and southwestern parts of the Sichuan Basin. Overall, storm action showed an initial increase followed by a decrease. (3) The impact of storms on the reworking of grain shoal reservoirs varies across different facies zones. The intra-platform depression margins, influenced by storm centers, experienced strong reworking, leading to the vertical stacking of storm-related grain shoals and normal grain shoals, which expands the scale of the shoal complex. Furthermore, storms enhance the penecontemporaneous dissolution, favoring the development of large-scale high-quality reservoirs. The intra-platform depressions and mixed tidal flats, controlled by the storm centers, were weakly modified, possibly inducing scattered storm-related grain shoals under low-energy conditions. The degree of karst modification is generally low, and local conditions are favorable for reservoir development. (4) The Dazu-Hechuan-Guang’an area, strongly reworked by storm activities, exhibits a large scale of storm-related grain shoals with good physical properties, providing favorable conditions for the development of contiguous, high-quality grain shoal reservoirs, so it can be regarded as a key target for subsequent exploration of the Xixiangchi Group.

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.

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.

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.

Starting from the first principle thinking, this study systematically reviews the development mechanisms of gas reservoirs and proposes the development concept of “full lifecycle enhanced gas recovery (EGR)”. Following the principles of scientificity, practicality and comparability, a generational classification system for EGR technologies is established. The research indicates that the properties of natural gas dictate a development mechanism primarily driven by pressure depletion to release the elastic expansion energy of gas. This leads to a development model centered on primary depletion, supplemented by limited adjustments in late stages. Early development essentially lies in well pattern optimization and risk pre-control, while late development focuses on targeted local adjustments and integrated collaborative control. Primary gas recovery, relying on natural energy depletion, achieves a recovery factor of 25%-55%. Secondary gas recovery, through active regulation of the reservoir pressure field via techniques like blockage removal, and injection-production optimization, can enhance the recovery factor by 10-15 percentage points. Tertiary gas recovery, employing multiple mechanisms to alter the reservoir’s physical and chemical fields synergistically, offers a potential further increase of 5-10 percentage points. Currently, primary recovery technologies are mature and well-established. Synergistic optimization of well patterns and fracture networks enables effective production from gas-drive reservoirs, while optimized development strategies facilitate orderly production from water-drive gas reservoirs. Secondary recovery technologies, in the field pilot stage currently, adopt active measures like enhanced water drainage, water shutoff, and gas injection to effectively control water influx and release trapped gas. Tertiary recovery remains largely in the laboratory or pilot test stage. Future efforts should focus on cross-generational technologies, such as “primary + secondary” and “primary + tertiary” combinations, to continuously improve recovery factors throughout the full lifecycle of gas reservoirs.

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 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.

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.

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

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