By considering the thermo-poroelastic effects of rock, the constitutive relationship of fatigue deterioration under cyclic loading, elastic-brittle failure criteria, and wellbore stress superposition effects, a thermal-hydraulic-mechanical-fatigue damage coupled model for fracture propagation during soft hydraulic fracturing in hot dry rock (HDR) was established and validated. Based on this model, numerical simulations were conducted to investigate the fracture initiation and propagation characteristics in HDR under the combined effects of different temperatures and cyclic loading. The results are obtained in three aspects. First, cyclic injection, fluid infiltration, pore pressure accumulation, and rock strength deterioration collectively induce fatigue damage of rocks during soft hydraulic fracturing. Second, the fracture propagation pattern of soft fracturing in HDR is jointly controlled by temperature difference and cyclic loading. A larger temperature difference generates stronger thermal stress, facilitating the formation of complex fracture networks. As cyclic loading decreases, the influence range of thermal stress expands. When the cyclic loading is 90%p_b and 80%p_b (where p_b is the breakdown pressure during conventional hydraulic fracturing), the stimulated reservoir area increases by 88.33% and 120%, respectively, compared to conventional hydraulic fracturing (with an injection temperature of 25 ℃). Third, as cyclic loading is further reduced, the reservoir stimulation efficiency diminishes. When the cyclic loading decreases to 70%p_b, the fluid pressure cannot reach the minimum breakdown pressure of the rock, resulting in no macroscopic hydraulic fractures.

The basic geological characteristics of the Qiongzhusi Formation reservoir and high-yield conditions for shale gas enrichment were studied by using methods such as mineral scanning, organic and inorganic geochemistry, breakthrough pressure, and triaxial mechanics testing based on the core, logging, seismic, and production data. (1) Both types of silty shale, rich in organic matter in deep water and low in organic matter in shallow water, have good gas bearing properties. (2) The brittle mineral composition of shale has the characteristic of equivalent content of feldspar and quartz. (3) The pores are mainly inorganic pores with a small amount of organic pores. Pore development primarily hinges on a synergy between felsic minerals and total organic carbon content (TOC). (4) Dominated by Type I organic matters, the hydrocarbon generating organisms are algae and dubious sources, with high maturity and high hydrocarbon generation potential. (5) Deep- and shallow-water shale gas exhibit in-situ and mixed characteristics, respectively. (6) The basic law of shale gas enrichment in the Qiongzhusi Formation was proposed as “TOC controlled storage and inorganic pore controlled enrichment”, which includes the in-situ enrichment model of “three highs and one over” (high TOC, high felsic mineral content, high inorganic pore content, overpressured formation) for organic rich shale represented by Well ZY2, and the in-situ + carrier bed enrichment model of “three highs, one medium and one low” (high felsic content, high formation pressure, medium inorganic pore content, low TOC) for low organic shale gas represented by Well JS103. It is a new type of shale gas that is different from the Longmaxi Formation, enriching the formation mechanism of deep and ultra-deep shale gas. The deployment of multiple exploration wells has achieved significant breakthroughs in shale gas exploration.

Two etching models, the spherical-rod standard pore channel and the pore structure, were used to conduct displacement experiments in the water-gas dispersion system to observe the morphological changes and movement characteristics of microbubbles. Additionally, numerical simulation methods were employed for quantitative analysis of experimental phenomena and oil displacement mechanisms. In the experiment, it was observed that microbubble clusters can disrupt the pressure equilibrium state of fluids within the transverse pores, and enhancing the overall fluid flow; bubbles exhibit a unique expansion-contraction vibration phenomenon during the seepage process, which is nearly unobservable in water flooding and gas flooding processes. Bubble vibration can accelerate the adsorption and expansion of oil droplets, and promote the emulsification of crude oil, thereby improving microscopic oil displacement efficiency. Combining experimental data with numerical simulation analysis of bubble vibration effects, it was found that microbubble vibrations exhibit characteristics of a sine function, and the energy release process follows an exponential decay pattern; compared to the gas drive front interface, microbubbles exhibit a significant “rigidity” characteristic; the energy released by microbubble vibrations alters the stability of the seepage flow field, resulting in significant changes to the flow lines; during the oil displacement process, the vast number of microbubbles can fully exert their vibrational effects, facilitating the migration of residual oil and validating the mechanism of the water-gas dispersion system enhancing microscopic oil displacement efficiency.

The thermal flux curve of phase-transition fluid (PF) was tested using differential scanning calorimetry (DSC), based on which a reaction kinetics model was established to reflect the relationship between phase transition conversion rate, temperature and time. A temperature field model for fractures and rock matrix considering phase transition heat was then constructed, and its reliability was verified using previously established temperature field models. Additionally, the new model was used to study the effects of different injection parameters and phase-transition fracturing performance parameters on the temperature variations in fractures and matrix. The study indicates that, at different positions and times, the cooling effect of the injected cold fluid and the exothermic effect during the phase transition alternately dominate the temperature within the fracture. At the initial stage of fracturing fluid injection, the temperature within the fracture is high, and the phase transition rate is rapid, resulting in a significant impact of exothermic phase transition on the reservoir rock temperature. In the later stage of injection, the fracture temperature decreases, the phase transition exothermic rate slows, and the cooling effect of the fracturing fluid on the reservoir rock intensifies. Phase transition heat significantly affects the temperature of the fracture. Compared to cases where phase transition heat is not considered, when it is taken into account, the temperature within the fracture increases to varying degrees at the end of fluid injection. As the phase transition heat increases from 20 J/g to 60 J/g, the maximum temperature rise in the fracture increases from 2.1 ℃ to 6.2 ℃. The phase transition heat and PF volume fraction are positively correlated with fracture temperature changes, while specific heat capacity is negatively correlated with temperature changes. With increasing injection time, the temperature and phase transition rate at the fracture opening gradually decrease, and the location of the maximum phase transition rate and temperature difference gradually shifts from the fracture opening to about 10 m from the opening.

The saline lacustrine hybrid sedimentary rocks are complex in lithology and unknown for their sedimentary mechanisms. The hybrid sedimentary rocks samples from the Neogene upper Ganchaigou Formation to lower Youshashan Formation (N₁-N₂¹) in the Fengxi area, the Qaidam Basin, were investigated through core-log and petrology-geochemistry cross-analysis by using the core, casting thin section, scanning electron microscope, X-ray diffraction, logging, and carbon/oxygen isotope data. The results indicate that the hybrid sedimentary rocks in the Fengxi area were deposited in a shallow lake environment far from the source, or occasionally in a semi-deep lake environment, with 5 lithofacies types and 6 microfacies types recognized. Stable carbon and oxygen isotopes reveal that the formation of sedimentary cycles is controlled by a climate-driven compensation-undercompensation cyclic mechanism. A sedimentary cycle model of hybrid sedimentary rocks in an arid and saline setting is proposed. According to this model, in the compensation period, the lake level rises sharply, and microfacies such as mud flat, sand-mud flat and beach are developed, with physical subsidence as the dominant sedimentary mechanism; in the undercompensation period, the lake level falls slowly, and microfacies such as lime-mud flat, lime-dolomite flat and algal mound/mat are developed, with chemical-biological process as the dominant sedimentary mechanism. Unlike marine carbonate rock formed during transgression, lacustrine carbonate rock is mainly formed along with regression. In the saline lacustrine sedimentary system, the facies change is not interpreted by the accommodation believed traditionally, but controlled by the temporary fluctuation of lake water chemistry caused by climate change. The research results update the interpreted high-resolution sequence model and genesis of hybrid sedimentary rocks in the saline lacustrine basin and provide a valuable guidance for exploring unconventional hydrocarbons of saline lacustrine facies.

This paper presents an analysis of four aspects, including the distribution and production of global oil and gas fields, the distribution and changes of remaining recoverable reserves, the differences in oil and gas production between regions/countries, and the development potentials of oil and gas fields unproduced and to be produced in 2023. On this basis, the situation and characteristics of global oil and gas development are expounded, and the trend of global oil and gas development is forecasted. In 2023, oil and gas fields were widely distributed around the world, with an expanding upstream production landscape; Oil and gas reserves increased year-on-year, driven by significant contributions from new discoveries and reserve revisions; The overall oil and gas production grew continuously, with notable contributions from new projects coming online and capacity expansion efforts; and The oil and gas fields unproduced or to be produced, especially large onshore conventional oil fields and economically challenging offshore gas fields, host abundant reserves. From the perspectives of reshaping oil and gas production areas due to the pandemic and Russia-Ukraine conflicts, geopolitical crises, capital expenditure structures in exploration and development, and the proactive layout of associated resources, the trend of global oil and gas development in 2023 was analyzed systematically. The enlightenment and suggestions in four aspects are proposed for Chinese oil companies to focus on core businesses and clarify development strategies in the post-pandemic era and the context of energy transition: The global oil and gas landscape is undergoing profound adjustments, and it is essential to grasp development trends, especially in core businesses; Upstream business exhibits a strong potential, and emerging business is considered as a replacement; The prospects for tight/shale oil and gas are promising, and new pathways to ensure national energy security are explored; Cutting-edge breakthroughs are achieved in emerging industries of strategic importance, and a comprehensive energy collaboration system for supply security is established.

The high temperature and high pressure visualization PVT experiments of different gas media-crude oil were carried using the interface disappearance method. The experiments show that there are two miscible temperature domains in the miscibility of CO₂-crude oil during heating process under constant pressure. Under the experiment pressure of 15 MPa, when the temperature is less than 140 °C, the miscible zone shows liquid phase characteristics, and increasing the temperature inhibits the miscible process; when the temperature is greater than 230 °C, the miscible zone tends to gas phase characteristics, and increasing the temperature is conducive to the miscibility formation. Under a certain pressure, with the increase of temperature, the miscibility of flue gas/nitrogen and crude oil is realized. When the temperature is low, the effect of CO₂ on promoting miscibility is obvious, and the order of miscible temperature of gas medium and crude oil is N₂ > flue gas > CO₂; however, when the temperature is high, the effect of CO₂ on promoting miscibility gradually decreases, and the miscible temperature of N₂ and crude oil is close to that of flue gas. The miscibility is dominated by the distillation and volatilization of light components of crude oil. There are many light hydrocarbon components in the gas phase at phase equilibrium, and the miscible zone is characterized by gas phase.

Based on the data of 3D seismic survey, drilling, sidewall coring, thin sections and tests, this paper systematically discusses the necessary conditions for the formation of buried-hills, reservoirs, and accumulations in the large oil and gas fields in deep to ultra-deep composite buried hills in the Bohai Sea through the analysis of the Meso-Cenozoic geotectonic dynamics, buried-hill reservoir characteristics, and differential enrichment patterns of oil and gas in the buried hills, as well as case study of typical reservoirs. The key findings are as follows. First, the double-episode destruction of the North China Craton in the Yanshanian and Himalayan served as the primary tectonic driver for the development of deep to ultra-deep composite buried hills in the Bohai Sea. Jointly controlled by the destruction of the North China Craton and the activity of the Tanlu Fault, the destruction center migrated and converged episodically from the margins of the Bohai Bay Basin towards the Bozhong Depression, resulting in an orderly mountain-building process within the basin and subsequently two development zones for composite buried hills, i.e. the middle and inner rim zones within the Bozhong Depression. Second, under the coupling of favorable lithologies and multi-stage structures, the middle and inner rim zones are conducive to the formation of reservoirs in fluid dissolution-pore/fracture zones underlying the weathering crust. Third, during the Episode II craton destruction, the middle and inner rim zones subsided intensely, along which massive hydrocarbons were generated, resulting in the overpressure, and then migrated to and accumulated in the composite buried hills. The lower parts and interiors of these buried hills still possess excellent conditions for hydrocarbon accumulation. These findings promote a shift in buried hill exploration to three-dimensional exploration of composite buried hills. It is emphasized that the deep to ultra-deep composite buried hill interiors in the middle rim zone and the multi-stage volcanic edifices in the inner rim zone of the depression represent important successor areas for future exploration in the Bohai Sea.

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

Taking the Ordos Basin as an example, this paper proposed that the construction of an energy super basin should follow the principle of “more energy, less carbon, and better energy structure”. The modeling workflow of energy super basin was built. Based on the resources/reserves, development status and infrastructures of the Ordos Basin, the development potential of the basin was evaluated, the uncertainties in the construction of energy super basin were analyzed, and the future vision and realization path of the Ordos Energy Super Basin were recommended. This study demonstrates that the Ordos Basin has the advantages of abundant sources, perfect infrastructures, well-matched carbon source and sink, small population density, and proximity to the energy consumption areas. These characteristics ensure that the Ordos Basin is a good candidate of the energy super basin. It is expected that the energy supply of the Ordos Basin in 2050 will reach 23×10⁸ tons of standard coal, and the proportion of fossil fuels in energy supply will decrease to 41%. The carbon emissions will decrease by 20×10⁸ tons of carbon dioxide equivalent compared to the emissions in 2023. The future construction of the basin should focus on the generation and storage of renewable energy. The carbon capture, utilization and storage technology requires breakthrough innovation.

The shales in the ancient Qiongzhusi Formation in the Sichuan Basin are characterized by large burial depth and high maturity, but unknown for shale gas enrichment pattern. Through detailed characterization of the depositional environment of the Deyang-Anyue aulacogen and the Leshan-Longnüsi paleouplift, thermal simulation experiments, and analysis of the main controlling factors of shale gas enrichment, the aulacogen-uplift enrichment pattern is proposed. It is revealed that the Deyang-Anyue aulacogen controls the depositional environment of the Qiongzhusi Formation, where high-quality sedimentary facies and thick strata are observed, and the Leshan-Longnüsi paleouplift controls the maturity evolution of the shale in the Qiongzhusi Formation, with the uplift located in a high position and exhibiting a moderate degree of thermal evolution and a high resistivity. The aulacogen-uplift overlap area is conducive to the enrichment of shale gas during the deposition, oil generation, gas generation, and adjustment stages, and has a joint control on the development of reservoirs, resulting in multiple reservoirs of high quality and large thickness. Based on the aulacogen-uplift enrichment pattern and combinations, four types of shale gas play are identified, and the sweet spot evaluation criteria for the Qiongzhusi Formation is established. Accordingly, a sweet spot area of 8 200 km² in the aulacogen is determined, successfully guiding the deployment of Well Zi 201 with a high-yield industrial gas flow of 73.88×10⁴ m³/d. The study insights provide an important basis for the development of deep Cambrian shale gas.

Based on commercial databases from S&P Global and Rystad Energy and public information from oil companies around the world, a systematic analysis has been conducted on the global hydrocarbon exploration investment, award of exploration blocks, exploratory drilling, new conventional oil and gas discoveries, and exploration of associated resources in 2023. The results show that, in 2023, the global hydrocarbon exploration investment increased steadily and the total number and area of awarded exploration blocks increased significantly, but the increase in drilling costs led to a decline in the number of exploration wells for conventional oil and gas resources around the world. The decline in the number and success rate of high-impact exploration wells directly affected the quantity of additional oil and gas reserves discovered globally in 2023. In recent years, the deepwater areas of passive margin basins have been the major targets for seeking medium- and large-sized conventional oil and gas fields. In 2023, however, the newly discovered onshore reserves were equivalent to the newly discovered offshore reserves, and fine exploration in mature blocks achieved significant results. Oil companies continued to plan and perform unconventional oil and gas exploration activities and accelerated access to mineral resources such as natural hydrogen and helium and other emerging industries. For Chinese oil companies international exploration business, it is recommended to: (1) continue the upstream investment to strengthen upstream services for consolidating the strategic position of oil and gas resources; (2) uphold oil and gas exploration activities by further deploying exploration activities in the deepwater areas of passive margin basins, deeply exploring mature basins, closely following hotspot basins, and gaining access to frontier basins; (3) follow the principle of integrated development to plan the exploration of associated resources while exploiting conventional and unconventional resources; and (4) make technological innovations to develop and improve core technologies and promote the application of artificial intelligence.

With the continuous discovery of unconventional oil and gas, traditional petroleum system theories and methods can no longer adapt to the research of all underground oil and gas resources. Traditional petroleum system theories emphasize the restoration of the accumulation process from “source” to “trap”. The main oil and gas resources in the concept are conventional oil and gas, lacking the concept and research of unconventional oil and gas enrichment mechanism. The whole petroleum system is developed from the traditional petroleum system. Compared with the petroleum system, the whole petroleum system adds the research content of unconventional oil and gas. Although the study of the whole petroleum system is still in three aspects: geological elements, dynamic evolution and oil and gas distribution, its research ideas and research contents are very different, mainly including the following three aspects. (1) In terms of geological elements, the traditional petroleum system mainly studies the characteristics of source rocks and hydrocarbon generation evolution, and the reservoir properties, traps, migration and preservation conditions of conventional oil and gas. On the basis of the above research, the whole petroleum system has increased the quantitative evaluation of retained hydrocarbons, unconventional reservoir characterization, source reservoir configuration and other research contents. (2) In terms of dynamic evolution, the petroleum system mainly studies the matching between the evolution of conventional oil and gas source rocks and the formation period of traps, that is, the critical moment of oil and gas accumulation, while the whole petroleum system has increased the research content of the matching of unconventional reservoir densification and oil and gas charging, and the later transformation of unconventional oil and gas reservoirs. (3) In terms of oil and gas distribution, the petroleum system takes buoyancy accumulation mechanism as the core to study the migration, accumulation and distribution of conventional oil and gas. The whole petroleum system adds unconventional oil and gas self-sealing accumulation mechanism and conventional-unconventional oil and gas distribution sequence, so as to determine the oil and gas distribution characteristics of the whole petroleum system.

Considering the adsorption loss of the hydraulic fracturing assisted oil displacement (HFAD) agent in the matrix, a method is proposed to characterize the dynamic saturation adsorption capacity of the HFAD agent with pressure differential and permeability. On this basis, coupled with the viscosity-concentration relationship of the HFAD agent, a non-linear seepage model of HFAD was established, taking into account the adsorption effect of high pressure drops, and the influencing factors were analyzed. The findings indicate that the replenishment of formation energy associated with HFAD technology is predominantly influenced by matrix permeability, fracture length and the initial concentration of the HFAD agent. The effect of replenishment of formation energy is positively correlated with matrix permeability and fracture length, and negatively correlated with the initial concentration of the HFAD agent. The initial concentration and injection amount of the high-pressure HFAD agent can enhance the concentration of the HFAD agent in the matrix and improve the efficiency of oil washing. However, a longer fracture is not conducive to maintaining the high concentration of the HFAD agent in the matrix. Furthermore, the fracture length and pump displacement are the direct factors affecting the fluid flow velocity in the matrix subsequent to HFAD. These factors can be utilized to control the location of the displacement phase front, and thus affect the swept area of HFAD. A reasonable selection of the aforementioned parameters can effectively supplement the formation energy, expand the swept volume of the HFAD agent, improve the recovery efficiency of HFAD, and reduce the development cost.

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

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

The researches on the geological theory of coal-formed gas are reviewed, the contribution of coal-formed gas to China's natural gas reserves and production and to the development of natural gas in major gas-producing basins are analyzed, and the key favorable exploration zones for coal-formed gas in China are comprehensively evaluated. The following results are obtained. First, coal measures are good gas source rocks, and hydrocarbon generation from coal measure was dominated by gas generation, followed by oil. Second, a natural gas genetic identification index system based on stable isotopes, light hydrocarbon components, and biomarkers is established. Third, the quantitative and semi-quantitative factors controlling the formation of large gas fields, represented by the indicator of gas generation intensity greater than 20×10⁸ m³/km², are identified to guide the discovery of large gas fields in China. Fourth, coal-formed gas is the major contributor to China's current natural gas reserves and production, both accounting for over 55%. The high proportion of coal-formed gas has enabled the Tarim, Sichuan, and Ordos basins to be the major gas production areas in China. Fifth, deep coal rock gas is an important option for future exploration of coal-formed gas, and key zones include the Carboniferous Benxi Formation in the Wushenqi-Mizhi area of the Ordos Basin, the Permian Longtan Formation in central-southern Sichuan Basin, the Jurassic Xishanyao Formation in the southern margin and Luliang uplift of the Junggar Basin, Sixth, tight gas is the main area for increasing reserves and production, and the favorable exploration zones include the Carboniferous-Permian in southern Ordos Basin and the Bohai Bay Bain, and the Triassic Xujiahe Formation in the transition zone between central and western Sichuan Basin. Seventh, the Jurassic in the southern margin of the Junggar Basin is a key favorable exploration zone for subsequent investigation of conventional coal-formed gas. These insights have valuable theoretical and practical significance for further developing and improving the theory of coal-formed gas, and guiding the exploration of coal-formed gas fields in China.

Considering the demands, situations, and trends in respect to global climate change, carbon neutrality, and energy transition, the achievements and implications of the global green energy transition and China’s new energy revolution are summarized, and the “energy triangle” theory is proposed. The research indicates that the energy technology revolution is driving a dual transformation in global energy: the black “shale oil and gas revolution” in North America and the green “new energy revolution” in China. China’s green energy revolution has achieved significant milestones in wind, solar, and hydrogen storage technologies, leading the world in photovoltaic and wind power. The country has developed the world’s largest, most comprehensive, and competitive new energy innovation, industrial, and value chains, along with the largest clean power supply system globally. New quality productivity represents green productivity. China’s green “new energy revolution” has accelerated the transformation of its energy structure and the global shift towards clean energy, promoting a new win-win model for the global green and low-carbon transition. The “energy triangle” theory in the context of new quality productivity interprets the relationship and development between energy security, economy and greenness, carbon neutrality goal, and green energy transition. Compared to the global energy resource endowment, China’s energy resources are characterized by abundant coal, limited oil and gas, and unlimited wind and photovoltaic energy. Moving forward, China's energy strategies will focus on the advancement of technologies to clean coal for carbon emission reduction, increase gas output while stabilizing oil production, increase green energy while enhancing new energy, and achieve intelligent integration. Vigorously developing new energy is an essential step in maintaining China’s energy security, and establishing a carbon-neutral “super energy system” is a necessary choice. It is crucial to enhance China’s international competitiveness in new energy development, promote high-quality energy productivity, support the country’s transition to an “energy power,” and strive for “energy independence.”

Based on petroleum exploration and new progress of oil and gas geology study in the Qiongdongnan Basin, combined with seismic, drilling, logging, core wall, geochemistry data, a systematic study is conducted on the source, reservoir, cap conditions, trap types, migration and accumulation characteristics, enrichment mechanisms, and reservoir formation models of ultra-deep and ultra-shallow natural gas taking the Lingshui 36-1 gas field as an example. (1) The genetic types of the ultra-deep water and ultra-shallow natural gas in the Qiongdongnan Basin include thermogenic gas and biogenic gas. (2) The reservoirs are mainly composed of deep-water gravity flow sedimentary submarine fan sandstone. (3) The types of cap rocks include deep-sea mudstone, mass flow mudstone, and hydrate bearing formations. (4) The types of traps are mainly lithological, and also include structural, lithological, and structural traps. (5) The migration channels include vertical transport channels such as faults, gas chimneys, fracture zones, and lateral transport layers such as large sand bodies and unconformity surfaces, forming a single or composite transport framework. A new natural gas accumulation model is proposed for ultra-deep water and ultra-shallow layers, that is, dual source hydrocarbon supply, gas chimney submarine fan composite migration, late dynamic accumulation, deep-sea mud mass flow hydrate-bearing strata ternary sealing, and large-scale enrichment at ridges of the Quaternary submarine fan. The new understanding obtained from the research has reference and enlightening significance for the next step of deepwater and ultra-shallow layers exploration, as well as oil and gas exploration in related fields or regions.

This study integrates field outcrop profiles, drilling cores, 2D seismic profiles, and 3D seismic data of key areas to analyze the Triassic tectonic-sequence stratigraphy in the Kuqa foreland basin, and investigates the impact of episodic thrust structures on sedimentary evolution and source rock distribution. (1) The Kuqa foreland basin has experienced stages of initial strong, weakened activities, relaxation and inactivity of episodic thrusting, resulting the identification of 4 second-order sequences (Ehebulake Formation, Karamay Formation, Huangshanjie Formation, Taliqike Formation) and 11 third-order sequences (SQ1-SQ11). Each sequence or secondary sequence displays a “coarse at the bottom and fine at the top” pattern due to the influence of secondary episodic thrust activity. (2) The episodic thrusting is closely linked to regional sequence patterns, deposition and source rock formation and distribution. The sedimentary evolution in the Triassic period progresses from fan delta to braided river delta, lake, braided river delta, and meandering river delta, corresponding to the initial strong (Ehebulake Formation), weakened (Karamay Formation), relaxation (Huangshanjie Formation), and inactivity (Taliqike Formation) of episodic thrusting. The development stage of thick, coarse-grained sandy conglomerate reservoirs aligns with the strong to weakened thrust activities, while the source rock formation period coincides with the relaxation to inactivity stages. (3) Controlled by the intensity and stages of episodic thrust activity, the nearly EW trending thrust fault not only significantly thickened the footwall source rock during the Huangshanjie Formation, becoming the development center of Triassic source rock, but also experienced multiple overthrust nappes in the soft stratum of the source rock, showing “stacked style” distribution. (4) The deep layers of the Kuqa foreland basin have the foundation and conditions necessary for the formation of substantial gas reservoirs, capable of forming various types of reservoirs such as self-generating and self-storing lithology, lower generating and upper storing fault-lithology, and stratigraphic unconformity. This area holds significant importance for future gas exploration efforts aimed at enhancing storage and production capabilities.

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

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

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

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

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

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

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

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

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

The Fuyu reservoirs of the Lower Cretaceous Quantou Formation in northern Songliao Basin develops tight oil below the source rocks. Based on the geochemical, seismic, logging, and drilling data, the Fuyu reservoirs are systematically studied in terms of the geological characteristics, the tight oil enrichment model and its major controlling factors. First, the Quantou Formation is overlaid by high-quality source rocks of the Upper Cretaceous Qingshankou Formation, with the development of ring-concave nose structure and the broad and continuous distribution of sand bodies. The reservoirs are tight on the whole. Second, the configuration of multiple elements, such as high-quality source rocks, reservoir rocks, fault, overpressure and structure, controls the tight oil enrichment in the Fuyu reservoirs. The source-reservoir combination controls the tight oil distribution pattern. The fault-sandbody transport system determines the migration and accumulation of oil and gas. The pressure difference between source and reservoir drives the charging of tight oil. The positive structure is the favorable place for tight oil enrichment, and the fault-horst zone is the key part of syncline for tight oil exploration. Third, based on the source-reservoir relationship, transport mode, drive and other elements, three tight oil enrichment models are recognized in the Fuyu reservoirs: (1) vertical or lateral transport of hydrocarbon from source rocks to adjacent reservoir rocks, that is, driven by overpressure, hydrocarbon generated by the source rocks is transported vertically or laterally to and accumulates in the adjacent reservoir rocks; (2) transport of hydrocarbon through faults between separated source and reservoirs, that is, driven by overpressure, hydrocarbon migrates downward through faults to the reservoir rocks that are separated from the source rocks; and (3) sandbody migration of hydrocarbon downwards through faults and sandbodies between separated source and reservoirs, that is, driven by overpressure, hydrocarbon migrates downwards through faults to the reservoir rocks that are separated from the source rocks, and migrates laterally through sandbodies. Fourth, the differences in oil source conditions, fracture distribution, charging drive, sandbody and reservoir physical properties cause the differential enrichment of tight oil in the Fuyu reservoirs. Comprehensive analysis suggests that the Fuyu reservoir in the Qijia-Gulong Depression has good conditions for tight oil and has been less explored, and it is an important new zone for tight oil exploration in the future.

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

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

Based on the methodology for petroleum systems and through the anatomy and geochemical study of typical helium-rich gas fields, the geological conditions, genetic mechanisms, and accumulation patterns of helium resources are investigated. Helium differs greatly from other natural gas resources in formation, migration, and accumulation. Helium is mostly generated due to the slow alpha decay of basement U/Th-rich elements or released from the deep crust-mantle, and then migrates along the multiple tectonic layers of the exosphere to the gas reservoir-forming system, where it accumulates depending on a suitable carrier gas. Crust-mantle-originated helium migration and conduction are mainly controlled by the multi-tectonic-layer conduction system consisting of lithospheric fractures, basement fractures, sedimentary layer fractures, and effective carriers. Based on the analysis of the helium-gas-water phase equilibrium in underground fluids and the phase-potential coupling, three occurrence states, i.e. water-soluble phase, gas phase, and free phase, in the process of helium migration and accumulation, as well as three migration mechanisms of helium, i.e. mass flow, seepage and diffusion, are proposed. The formation and enrichment of helium-rich gas reservoirs are usually controlled by three major factors, i.e. high-quality helium source, high-efficiency conduction, and suitable carrier, and conform to three genetic mechanisms, i.e. gas-stripping and convergence, buoyancy-driven, and differential pressure displacement. Helium-rich gas reservoirs discovered generally follow the distribution rule and geological pattern of "near helium source, adjacent to fault, low fluid potential area, and high site". To explore and evaluate helium-rich areas, it is necessary to conduct concurrent/parallel exploration with natural gas. The comprehensive evaluation and selection of profitable "source-trap connected, low fluid potential with high site, and gas/helium properly matched" helium-rich areas should focus on the coupling and matching of the helium formation, migration and accumulation elements with the natural gas source, reservoir and caprock conditions, and based on favored carrier gas trapping areas in local low fluid potential with tectonic high sites.

A three-dimensional reconstruction of rough fracture surfaces of hydraulically fractured rock outcrops is carried out by casting process, a large-scale experimental setup for visualizing rough fractures is built, and proppant transport experiments are performed. The typical characteristics of proppant transport in rough fractures and its intrinsic mechanisms are investigated, and the influences of fracture inclination, fracture width and fracturing fluid viscosity on proppant transport and placement in rough fractures are analyzed. The results show that the rough fractures cause variations in the shape of the flow channel and the fluid flow pattern, resulting in the bridging buildup during proppant transport to form unfilled zone, the emergence of multiple complex flow patterns such as channeling, reverse flow and bypassing of sand-laden fluid, and the influence on the stability of the sand dune. The proppant has a higher placement rate in inclined rough fractures, with a maximum increase of 34.77% in the experiments compared to vertical fractures, but exhibits poor stability of the sand dune. Reduced fracture width aggravates the bridging of proppant and induces higher pumping pressure. Increasing the viscosity of the fracturing fluid can weaken the proppant bridging phenomenon caused by the rough fractures.

Based on core and thin section data, the source rock samples from the Permian Fengcheng Formation in the Mahu Sag of the Junggar Basin were analyzed in terms of zircon SIMS U-Pb geochronology, organic carbon isotopes, major and trace element contents, as well as rock minerals. Two zircon U-Pb ages (306.0±5.2 Ma and 303.5±3.7 Ma) were obtained from the first member of Fengcheng Formation. Combined with organic carbon isotope stratigraphy, it is inferred that the depositional age of the Fengcheng Formation is about 297-306 Ma, spanning the Carboniferous-Permian boundary and placing the majority to the interglacial period between C4 and P1 glaciation. Multiple increases in Hg/TOC ratios and altered volcanic ash were found in the shale rocks of the Fengcheng Formation, indicating that multiple phases of volcanic activity occurred during its deposition. An interval with a high B/Ga ratio was found in the middle of the second member of Fengcheng Formation associated with the occurrence of evaporite minerals and searlesite, indicating that the high salinity of the water mass is related to hydrothermal activity. Comprehensive analysis suggests that the organic matter enrichment of the Fengcheng Formation is controlled by multiple factors such as paleoclimate, volcanic activity, and salinity. Warm and humid climate during the deposition of Fengcheng Formation is conducive to the growth of organic matter such as algae and bacteria in lake, and accelerates the continental weathering, driving the input of nutrients. Volcanic and hydrothermal activities supply a large amount of nutrients and stimulate primary productivity. The high salinity encourages water stratification, leading to water anoxia that benefits organic matter preservation.

To explore the geological characteristics and exploration potential of the Carboniferous Benxi Formation coal rock gas in the Ordos Basin, this paper presents a systematic research on the coal rock distribution, coal rock reservoirs, coal rock quality, and coal rock gas features, resources and enrichment. Coal rock gas is a high-quality resource distinct from coalbed methane, and it has unique features in terms of burial depth, gas source, reservoir, gas content, and carbon isotopes. The Benxi Formation coal rocks cover an area of 160 000 km⊃2;, with thicknesses ranging from 2 to 25 m, primarily consisting of bright and semi-bright coals with primitive structures and low volatile and ash content, indicating a good coal quality. The medium-to-high rank coal rocks have the total organic carbon (TOC) content ranging from 33.49% to 86.11%, averaging 75.16%. They have a high degree of evolution (R_o of 1.2%-2.8%), and a high gas-generating capacity. They also have high stable carbon isotope values (δ¹³C₁: -37.6‰ to -16‰; δ¹³C₂: -21.7‰ to -14.3‰). Deep coal rocks develop matrix pores such as gas bubble pores, organic pores, and inorganic mineral pores, which, together with cleats and fractures, form good reservoir spaces. The coal rock reservoirs exhibit the porosity of 0.54%-10.67% (averaging 5.42%) and the permeability of 0.001-14.6 mD (averaging 2.32 mD). Vertically, there are five types of coal rock gas accumulation and dissipation combinations, among which the coal rock-mudstone gas accumulation combination and the coal rock-limestone gas accumulation combination are the most important, which have good sealing conditions and high peak values of total hydrocarbon in gas logging during drilling. A model of efficient hydrocarbon accumulation has been constructed, which includes source-reservoir integration, widespread distribution of medium-to-high rank coal rocks continually generating gas, matrix pores and cleats/fractures in coal rocks acting as large-scale reservoir spaces, tight cap rocks providing sealing, and five types of enrichment patterns (lateral pinchout complex, lenses, low-amplitude structures, nose-like structures, and lithologically self-sealing). According to the geological characteristics of coal rock gas, the Benxi Formation is divided into 8 plays, and the estimated coal rock gas resources with a buried depth of more than 2 000 m are more than 12.33 trillion cubic meters. The above understandings guide the deployment of risk exploration. Two wells drilled accordingly obtained an industrial gas flow, driving the further deployment of exploratory and appraisal wells. Substantial breakthroughs have been achieved, with the possible reserves booked to be over a trillion cubic meters and the proved reserves over a hundred billion cubic meters, which is of great significance for the reserves increase and efficient development of natural gas reserves in China.

Based on the research and summary of igneous intrusions and contacted metamorphic rock reservoirs in Bohai Bay Basin, a geological model of igneous intrusion contact metamorphic system is proposed using seismic data, logging data, physical property analysis and oriented thin section, combined with the condensation characteristics of magma intrusion along the bedding of sedimentary rock, the high-temperature baking effect on the surrounding rock and the symbiotic relationship. This model is applied on the reservoirs of Paleogene Shahejie Formation in Nanpu sag, and the geological significance of reservoir is revealed. This system, consisted of the intrusion, the upper metamorphic zone and the lower metamorphic zone, as well as top and bottom host rock, has three basic elements: the intrusion, contact metamorphic zones (metamorphic rock reservoirs) and host rock. In this sense, a research method and process for determining intrusion bodies, identifying contact metamorphic zones, and characterizing metamorphic rock reservoirs have been established. The host rock of the system is sedimentary rock, which is metamorphic rock formed after thermal contact and metamorphism near the intrusion, with matrix pores and fractures as reservoir spaces. The matrix pores are secondary “intergranular pores” distributed around metamorphic minerals after baking, metamorphism and transformation. The fractures are mainly structural fractures and intrusive compression fractures. A mixed light source superposition display method for thin section is innovated, which can clearly display the identification, spatial distribution and connectivity of complex micro reservoir spaces. The thickness of the intrusion body and the intensity of baking control the reservoir spatial distribution of the contact metamorphic zone. The coupling of thermal contact and metamorphism with favorable lithology is the key to the formation of favorable reservoirs. The proposal and application of the geological model of the igneous intrusion contact metamorphic system have promoted the further research and exploration of contact metamorphic rock reservoirs in Nanpu sag, and has an instructional significance for the study of contact metamorphic reservoirs in the middle-deep strata of the Bohai Bay Basin.

The types, occurrence and composition of authigenic clay minerals in the first member of the Middle Permian Maokou Formation (Mao-1 Member) in eastern Sichuan Basin were investigated through outcrop section measurement, core description, thin section identification, argon ion polishing, XRD diffraction, SEM-EDS and LA-ICP-MS. The diagenetic evolution sequence of clay minerals was clarified, and the sedimentary-diagenetic evolution model of clay minerals was established. The results show that authigenic sepiolite minerals were precipitated in the Si^{4 +} and Mg^{2 +}-rich cool aragonite sea and sepiolite-bearing strata were formed in the Mao-1 Member. During burial diagenesis, authigenic clay minerals undergo two possible evolution sequences. First, from the early diagenetic stage A to the middle diagenetic stage A₁, the sepiolite kept stable in the shallow-buried environment lack of Al³⁺. It began to transform into stevensite in the middle diagenetic stage A₂, and then evolved into disordered talc in the middle diagenetic stage B₁ and finally into talc in the period from the middle diagenetic stage B₂ to the late diagenetic stage. Thus, the primary diagenetic evolution sequence of authigenic clay minerals, i.e. sepiolite-stevens-disordered talc-talc, was formed in the Mao-1 Member. Second, in the early diagenetic stage A, as Al³⁺ carried by the storm and upwelling currents was involved in the diagenetic process, trace of sepiolite started to evolve into smectite, and a part of smectite turned into chlorite. From the early diagenetic stage B to the middle diagenesis stage A₁, a part of smectite evolved to illite/smectite mixed layer (I/S). The I/S evolved initially into illite from the middle diagenesis stage A₂ to the middle diagenesis stage B₂, and then totally into illite in the late diagenesis stage. Thus, the secondary diagenetic evolution sequence of authigenic clay minerals, i.e. sepiolite-smectite-chlorite/illite, was formed in the Mao-1 Member. The types and evolution of authigenic clay minerals in argillaceous limestone of sepiolite-bearing strata are significant for petroleum geology in two aspects. First, sepiolite can adsorb and accumulate a large amount of organic matters, thereby effectively improving the quality and hydrocarbon generation potential of the source rocks of the Mao-1 Member. Second, the evolution from sepiolite to talc is accompanied by the formation of numerous organic matter pores and clay shrinkage pores/fractures, as well as the releasing of the Mg²⁺-rich diagenetic transformation fluid, which allows for the dolomitization of limestone within or around the sag. As a result, the new assemblages of self-generation and self-accumulation, and lower/side source and upper/lateral reservoir, are created in the Middle Permian, enhancing the hydrocarbon accumulation efficiency.

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

Based on the analysis of light hydrocarbon compositions of natural gas and regional comparison in combination with the chemical components and carbon isotopic values of methane, the indication of geochemical characteristics of light hydrocarbon on the migration features and secondary alteration of natural gas from the Dongsheng gas field in the Ordos Basin is revealed, and the effect of migration on specific light hydrocarbon indexes is further discussed. The study indicates that, natural gas from the Lower Shihezi Formation (P₁x) in the Dongsheng gas field displays higher iso-C_5-7 contents than n-C_5-7, and the C_6-7 light hydrocarbons are mainly composed of paraffins with extremely low aromatic contents (<0.4%), whereas the C₇ light hydrocarbons are mainly dominated by methylcyclohexane, suggesting the characteristics of coal-derived gas with the influence by secondary alterations such as dissolution. The natural gas from the Dongsheng gas field has experienced free-phase migration from south to north and different degrees of dissolution after charging, and the gas in the Shiguhao area to the north of the Borjianghaizi fault has experienced apparent escape after accumulation. Long-distance migration in free phase results in the decrease of the relative contents of the methylcyclohexane in C₇ light hydrocarbons and the toluene/n-heptane ratio, as well as the increase of the n-heptane/methylcyclohexane ratio and heptane values. The dissolution causes the increase of isoheptane values of the light hydrocarbons, whereas the escape of natural gas in the Shiguhao area results in the increase of n-C_5-7 contents compared to the iso-C_5-7 contents.