The types and configurations of source-reservoir coupling can be identified based on the shale oil and gas source-reservoir coupling, which provides a basis for the determination of ideas about shale oil and gas exploration and the efficient exploration and development of shale oil and gas. However, until now, shale oil and gas have not introduced by any scholars into a unified evaluation system for the classification of source-reservoir coupling types, which to some extent restricts the exploration and development process of shale oil and gas. In view of this, based on analyzing the source-reservoir configuration characteristics of typical marine and terrestrial shale oil and gas reservoirs in China, the source-reservoir coupling relationship of shale oil and gas is divided into three categories. Moreover, this study makes clear the geological connotations of different source-reservoir coupling types and their mechanisms controlling oil and gas enrichment, and proposes an efficient exploration approach based on the overall evaluation of shale oil and gas in China. The research results suggest that the source-reservoir coupling types of shale oil and gas can be divided into three categories: source-reservoir separation, source-reservoir coexistence, and source-reservoir integration. Specifically, the migration distance of source-reservoir separation hydrocarbons is above meter scale, and the near-source oil and gas forms sweet spots, represented by the Lower Cambrian Qiongzhusi Formation in Sichuan Basin, the first and second submembers of Member 7 of Triassic Yanchang Formation in Ordos Basin, and the Permian Lucaogou Formation in Jimusar sag of Junggar Basin. The source-reservoir coexistence is characterized with the multi-source supply of hydrocarbons and the coexistence of source and reservoir, of which hydrocarbons are migrated into the nearby advantageous reservoirs to make them oil-bearing as a whole, represented by the Member 2 of Permian Wujiaping Formation in Sichuan Basin, the Jurassic Lianggaoshan Formation in Sichuan Basin, and the Member 4 of Paleogene Shahejie Formation in Jiyang depression of Bohai Bay Basin. The source-reservoir integration indicates that the source rock and reservoir are in the same stratum, and hydrocarbons undergo micro migration within the stratum, represented by the Ordovician Wufeng Formation and Silurian Longmaxi Formation in Sichuan Basin and the Cretaceous Qingshankou Formation in Songliao Basin. Sedimentary environment, biogenic silica, thermal maturity, and hydrocarbon generation/expulsion efficiency are the core elements that affect the shale oil and gas source-reservoir configuration and furtherly control the enrichment of shale oil and gas. Taking the typical shale oil and gas reservoirs in China as an example, the paper furtherly clarifies the exploration levels and ideas under the vertical multi-type source-reservoir coupling configuration at different levels of maturity. The research results are beneficial for quickly identifying and optimizing favorable intervals of shale oil and gas, providing an important scientific basis for the efficient exploration and development of shale oil and gas in China.

The Cambrian Qiongzhusi Formation is one of the earliest series of strata for shale gas exploration and research in China. In the early stage, due to unclear understandings of the overall geological cognition and limited technological conditions, a number of wells were only deployed in the Weiyuan anticline and Changning anticline with a burial depth less than 3 500 m and a relatively gentle structure. The production rate of the wells is low, indicating a failure in the large-scale commercial development. Recently, major exploration breakthroughs have been made in Well Zi201 and Well Weiye1H, marking significant progress in geological cognition of the deep shale gas in Qiongzhusi Formation of the Deyang-Anyue aulacogen. The sedimentary environment of Qiongzhusi Formation is controlled by the aulacogen. The deep-water siliceous argillaceous shelf facies in the trough and deep-water silty argillaceous shelf facies on the slope of the trough edge are the dominant sedimentary facies zones, which are conducive to the enrichment and accumulation of shale gas. Vertically, Qiongzhusi Formation has developed multiple sets of shale reservoirs, mainly consisting of the 1st, 3rd, 5th, and 7th substrata. In particular, the 5th substratum is a key breakthrough layer with the total organic carbon content of 2.7% to 3.1%, porosity of 4.2% to 4.9%, brittle mineral content of 69.5% to 76.5%, gas content of 7.8 m ³/t to 9.5 m ³/t, and moderate maturity of 3.0% to 3.5%. The 3rd substratum is a potential exploration stratum. Qiongzhusi Formation is expected to realize multi-interval three-dimensional development. The bottom margin of the Cambrian System has a simple structure in the middle section of the aulacogen, lacking of obvious major faults. The pressure coefficient of Qiongzhusi Formation is generally above 1.8, and the preservation conditions are favorable. The aulacogen provides sufficient sedimentary space and material basis, as a result of which the shale in Qiongzhusi Formation is rich in hydrocarbon sources and has achieved a high volume of gas production; the existence of Leshan-Longnüsi paleo-uplift prevents the shale in Qiongzhusi Formation from excessive thermal evolution. A "aulacogen-paleouplift" shale gas enrichment model has been established, and it has been determined that the favorable exploration area of Qiongzhusi Formation is 4 400 km ² and the resources amounts to 2×10 ¹²m ³. The exploration breakthrough of shale gas in Qiongzhusi Formation has opened up another new field for achieving a trillion of cubic meters of reserves and a billion of cubic meters of production. Next, the geological-engineering integrated high-yield model of Well Zi201 will be promoted and applied to the exploration and development fields of marine deep and ultra-deep shale gas in the entire Upper Yangtze area of southern China.

Six sets of high-quality source rocks have been identified globally, with three of them in the pre-Mesozoic strata serving as the primary source rocks for ancient oil and gas reservoirs. Ancient oil and gas reservoirs from the pre-Mesozoic strata exhibit five key characteristics. (1) The predominant basin types include foreland, passive continental margin, and cratonic basins. (2) Their primary type of oil and gas resources remains conventional, although shale oil and gas is developing rapidly. (3) Their oil and gas accumulations are primarily concentrated in the Permian, Devonian, Carboniferous, and Ordovician. (4) Their reservoir lithology is primarily composed of limestones, sandstones, shales, and dolomites. (5) Their burial depth is predominantly within the middle to shallow layers, indicating significant potential for deep plays. The substantial discoveries of ancient oil and gas plays demonstrate enrichment in four fields: the periphery of cratons, carbonate reservoirs, shale oil and shale gas reservoirs, and basement reservoirs. After analyzing the major discoveries in key areas, it is revealed that high-quality source-reservoir-seal combinations form readily in the peripheral regions of cratons that were historically located within low-latitude intertropical convergence zones. Global significant events have played a crucial role in shaping the development of source rocks and the enrichment of shale oil and gas. Within the temporal framework of these significant global events, potential plays can be optimized in advance by reconstructing the paleo-positions of accumulation elements. Based on independent evaluations of recoverable oil and gas reserves and yet-to-be-discovered resources, it is evident that conventional oil and gas exploration should focus on the Arabian Basin, Zagros Basin, Tarim Basin, and other basins. Basement rocks and residual strata are also important potential exploration areas. For shale oil and shale gas exploration, the focus should be on the Devonian Domanik shale in the Timan-Pechora and the Volga-Ural basins in Russia, the Silurian hot shale in the Arabian Basin in the Middle East, the Silurian and Devonian plays in the Ghadames Basin in the North Africa, and several sets of shales in the Sichuan and Junggar basins in China.

A new wave of technological revolution and industrial transformation is rapidly advancing against the backdrop of global climate change, the consensus on carbon neutrality, and the imperative for energy transition. The emerging industries of new energy has become a key development focus for nations worldwide. Emerging industries symbolize the trajectory of future technological and industrial advancement. The emerging industries is growing under the leadership of established sectors innovately, while nurturing future industries and serving as a crucial direction for the development of new quality productive forces. New energy stands as a pivotal strategic emerging industry, playing a paramount role within China’s energy strategies of "cleaning up coal, stabilizing oil production, enhancing gas utilization, strengthening new energy development, promoting multi-energy complementarity, and advancing intelligent collaboration". Fueled by advancements in manufacturing, infrastructure and intelligentization capabilities, the existing energy system relied on underground resource endowments is shifting to a novel energy system grounded in technological innovation. The advancement of new quality productive forces promotes the high-quality development of emerging industries in the field of new energy. Through the synergy of technological innovation and the dual carbon goals, the "four-wheel drive" of technology innovation and carbon emissions reduction leading the way, and energy economy and security propelling the progress, will successfully resolve the "impossible triangle" contradiction that has been troubling the energy field. This transition steers towards the transformation of the energy landscape from the fossil fuel-dominated "impossible triangle" to the new energy-driven "achievable triangle", enriches and develops the "energy triangle" theory. Through a series of measures such as constructing innovation platforms, driving technological innovation, fostering collaborative innovation, developing talent teams, and constructing industrial supply chains, a group of technology leaders emerge, which will accelerate the formation of new quality productive forces in emerging industries of new energy. This effort holds the promise of transforming fossil fuels such as coal and oil into more chemical material-oriented resources, striving for new energy to achieve "technological independence", and helping China achieve "energy independence".

A study is performed on the reservoir-controlling of strike-slip faults in deep marine carbonate rocks (>4 500 m) in Sichuan Basin, which is of important significance for the efficient exploration and development of gas reservoirs in tight carbonate rocks. Through the analyses of gas reservoirs as well as static and seismic data, investigations are carried out on the temporal and spatial relationship between strike-slip fault and hydrocarbon accumulation, as well as the controlling effects of strike-slip fault on the gas migration, trap and enrichment. The results show that the pre-Mesozoic strike-slip fault system is dispersively distributed and widely developed in the central Sichuan Basin, which had destructive effect on hydrocarbon accumulation in the Caledonian period. However, the petroleum accumulation conditions were superior in the Indonian-Yanshanian period, thus forming the pre-Mesozoic multi-layer superimposed hydrocarbon accumulation system controlled by strike-slip faults. The strike-slip faults constitute the pre-Mesozoic vertical-lateral oil/gas transport system throughout the central Sichuan Basin. The strike-slip fault system has formed two kinds of migration modes, including the near-source lateral fault-controlled petroleum migration in the Upper Sinian-Lower Cambrian carbonate reservoirs, and the far-source vertical petroleum migration of the Middle Permian carbonate reservoirs. This has led to subsequent differentiation in stratified and zonal oil/gas accumulation. In the tight carbonate rocks, the effective structural-lithologic traps are developed under the joint action of high energy microfacies and strike-slip faults, and the both also play a role of controlling the effectiveness of traps, thus forming the gas reservoiring mode of "small gas reservoir but large field" along the strike-slip fault zones. The strike-slip faults control the distribution of the high porosity and high permeability "sweet spots" fracture-vug reservoirs and high-yield wells, which can increase the reserves, and control the hydrocarbon enrichment. The results reveal that there is a pre-Mesozoic deep carbonate strike-slip fault-controlled gas-rich system in the central Sichuan Basin, with the ternary coupling factors of "source-fault-reservoir" that control the gas accumulation; there are differences in controlling gas migration, trapping and enrichment by strike-slip faults; the strike-slip fault-controlled "sweet spot" gas reservoir is a new favorable field for exploration and development of deep carbonate rocks.

Since establishing the Da’an circulation block in western Chongqing in June 2021, Zhejiang oilfield has been making every effort to increase and accelerate the exploration and evaluation of deep shale gas, as well as implementation work, and constantly deepen geological understanding and improve engineering technology. Thus, industrial breakthroughs have been achieved in the production tests of multiple wells, and the Da’an deep shale gas field was discovered in western Chongqing. Through systematically introducing the exploration and discovery process of the Da’an block in western Chongqing in the past two years, the paper comprehensively analyzes the geological accumulation conditions in terms of regional geological characteristics, sedimentary lithofacies, organic geochemistry, pores and fractures, physical properties, gas-bearing properties, fracture characteristics, geological and mechanical properties of rock, as well as high-quality reservoir distribution characteristics, and also summarizes the key techniques for the exploration and development of deep shale gas in Da’an block, which have been formed through practice and innovation. Da’an block was the depocenter of the Upper Yangtze foreland basin at the northern foot of the Jiangnan-Xuefeng Caledonian orogenic belt during the sedimentary period of the submember 1 of Member 1 of Wufeng-Longmaxi formations. The high-quality shale layer in the lower section was of deep-water shelf facies, and the strong reduction and anaerobic environment provided good source and reservoir conditions. As a result, the organic carbon-rich siliceous shale was developed; this block possesses excellent organic geochemical indicators, well-developed micro-reservoir space, good physical properties, good self-sealing property of shale, and high gas-bearing properties, indicating an overpressure continuous shale gas reservoir with over-matured dry gas. Based on the good conditions of shale roof and floor and the deformation of comb-shaped fold structure, an enrichment and accumulation model has been built for the deep shale gas (burial depth of 3 500-4 500 m) in western Chongqing based on the characteristics of "narrow steep anticlinal faults as the barrier bed and contiguous widely-distributed gentle synclines, hydrocarbon enrichment and high production in tectonic transition belt and low-amplitude anticline structure", reflecting the theoretical connotation of enrichment, accumulation and occurrence of mountainous shale gas under the mode of "multi-field synergy, multi-element coupling, multi-factor superposition". Through practical exploration, five comprehensive evaluation methods and technologies have been developed for the exploration and development of deep shale gas in Da’an block, including the fine identification and stability evaluation technology of multi-scale natural fractures, the integrated evaluation and design technology for the full life cycle of well platforms, the matching technology of safe, excellent and fast drilling under high temperature, the segmented volume fracturing 2.0 technology for horizontal wells that focuses on increasing reserves and production under the control of dense crushed fractures while preventing casing deformation, and the fine pressure control and flowback technology for deep shale gas based on continuous monitoring of high-frequency pressure and dynamic evaluation optimization of artificial gas reservoirs. The exploration and discovery of Da’an deep shale gas field the western Chongqing has further promoted the rapid development of deep-ultra deep marine shale gas in China.

The light oil from Gulong shale is widely distributed, with favorable components and temperature-pressure conditions for miscibility with CO ₂. Pre-fracturing with CO ₂ injection and huff-and-puff can offer significant potential to enhance oil recovery. However, there is a lack of sufficient understanding of the high-pressure phase behavior of Gulong shale oil. Based on the equation of state and two-phase equilibrium theory, through verifying the results of constant mass expansion experiment and slim tube experiment for shale oil, the paper establishes a thermodynamic oil-CO ₂ two-phase equilibrium model considering the nano-confinement effect, and also a calculation method for the minimum miscibility pressure based on the two-phase equilibrium model. This paper is a case study of Gulong shale oils in Well Guye 2HC and Well Guye 9HC, and elucidates the interphase mass transfer behavior of Gulong shale oil and CO ₂, which is influenced by the factors such as maturity, oil/CO ₂ ratio, pressure, and nano-confinement effect. The results show that with an increase in CO ₂ mole fraction, the saturation pressure of Well Guye 2HC and Well Guye 9HC shale oils gradually decreases. Under reservoir temperature and pressure conditions, both Well Guye 2HC and Well Guye 9HC shale oils can be miscible with CO ₂. Under the same amount of CO ₂ injection, Well Guye 2HC shale oil exhibits a higher molecular weight and viscosity with a greater drop, and a lower saturation pressure and expansion coefficient with a smaller variation than Well Guye 9HC shale oil. The multilevel contact process of CO ₂ injection shows that the dissolution capacity and extraction effect of CO ₂ are similar in both Well Guye 2HC and Well Guye 9HC shale oils. After sufficient contact, C ₁-C ₆ components in the oil phase of Well Guye 2HC and Well Guye 9HC shale oils at the far end opposite to injection gas front are all extracted into the gas phase, and the mole fractions of CO ₂ in the oil phase increase to 86.63 % and 87.35 %, respectively. The presence of nano-confinement effect reduces the compositional differences between oil and gas inside nanopores, leading to a decrease in the interfacial tension and minimum miscibility pressure, which is beneficial to the mutual dissolution and miscibility between CO ₂ and shale oil. The impact of the nano-confinement effect on Well Guye 2HC and Well Guye 9HC shale oils is not significantly different. When the pore radius decreases from 100 nm to 10 nm, the minimum miscibility pressure of Well Guye 2HC and Well Guye 9HC shale oils with CO ₂ is decreased by 20.90 % and 21.31 %, respectively. Understanding the phase behavior of fluids in shale oil reservoirs can provide a theoretical guidance for the optimization of CO ₂ injection development.

In 2021, a great breakthrough has been made in discovery of crude oil in the risk exploration well, i.e., Well Gulashou-1, in deep water area of Santos Basin in South America; a daily production of thousands of tons of high-yield oil flows was obtained in the drill stem testing, thus determining a super large oil reservoir in the Alam block in Brazil and confirming its potential for large-scale commercial development. To better understand this major breakthrough, the tectonic-sedimentary environment, accumulation conditions and reservoir characteristics of Well Gulashao-1 were analyzed in detail based on the analysis of regional geological background, in combination with the exploration history. The results show as follows. (1) Alam block is located in the Alam-Uirapuru uplift belt of Santos Basin, facing with Lula oilfield in the Lula-Sugar uplift belt across a lake, and the both has a similar tectonic-sedimentary background. The large paleo-uplift in the center of the basin provides favorable conditions for carbonate sedimentation. (2) Alam block is adjacent to the main hydrocarbon generating sag with abundant oil sources. (3) The inherited paleo-uplift controls the contiguous distribution of lacustrine carbonate reservoirs. (4) Salt rocks, post-salt calcilutites and mudstones have formed multiple effective seals on the oil reservoir. (5) The pre-salt anticlinal trap is developed on a large scale, demonstrating a favorable migration direction of oil and gas. (6) The pool in Well Gulashao-1 is an overpressure reservoir, which produces medium crude oil with low CO ₂ and H ₂S contents. The successful drilling of Well Gulashao-1 is a major breakthrough of oil exploration expanding from the pre-salt core area to the periphery in Santos Basin of Brazil. It is a major success achieved by PetroChina Company Limited (PetroChina) in adhering to overseas risk exploration and also a successful practice of overseas cooperation for deepwater oil and gas exploration in PetroChina. It is of guiding significance to the pre-salt oil and gas exploration in Santos Basin of Brazil and the development strategy of deepwater oil and gas business in PetroChina.

Well Xiongtan 1 in Kalayuergun structural belt of western Tabei uplift, Tarim Basin, has made a major breakthrough in oil and gas exploration in the Upper Cambrian Xiaqiulitage Formation in September 2023. This is another significant oil bearing strata discovery that has been made since Cretaceous and Paleogene in Tabei area, demonstrating the three-dimensional multi-layer hydrocarbon accumulation in Tabei area. Based on comprehensively analyzing the structural styles, fault characteristics, as well as the drilling, logging and testing data of Well Xiongtan 1, the paper makes clear the source rock conditions, oil and gas channel, reservoir-cap conditions and trap types of Kalayuergun structural belt, and systematically summarizes the accumulation elements and modes of the Cambrian Xiaqiulitage Formation in Kalayuergun structural belt. Two sets of deep source rocks are developed in Tabei uplift. The hydrocarbon source correlation shows that the Cambrian Yuertusi Formation is the main source rock layer, and the potential source rock is developed in the pre-Cambrian rift trough. Tectonic movement is active in the study area, forming Caledonian, Hercynian and Himalayan faults. NNW-trending strike-slip faults are superimposed with NW- and EW-trending thrust faults, forming an interlaced fault system, which vertically communicates with deep source rocks and reservoirs. Traps of the Upper Cambrian Xiaqiulitage Formation were formed at an early stage, where multiple periods of oil and gas accumulation occurred; under the influence of strong compression in Late Hercynian period, several faults connected with source rocks and related structural traps were initially formed. As a result of the late tectonic movement, the whole area continued to uplift, and formed a large area of continuously distributed tectonic traps in the Upper Cambrian reservoir, capturing oil and gas in multiple stages. The hydrocarbon accumulation mode of "lower generation and upper reservoir, dredging by faults and near-source accumulation" is established. The research results reveal that the Cambrian Xiaqiulitage Formation in western Tabei uplift has a huge exploration prospect, and it is expected to become a new strategic replacement area for increasing reserve and production in the platform area of Tarim Basin.

In recent years, the disciplines of petroleum geochemistry and hydrocarbon accumulation have developed rapidly under the guidance of new technologies, new methods and new ideas, and have played important roles in guiding the exploration and development of ultra-deep, unconventional, and complex oil-gas reservoirs. Among them, the unconventional isotope systems such as metal isotope (non-traditional stable isotope), halogen isotope, and high-dimensional stable isotopes (clumped isotope, triple oxygen isotope, polysulfide isotope and intramolecular isotope) have attracted great attention from the academic community and demonstrate one of the most rapid development directions of geochemistry. With the further upgrading of traditional isotope technologies, the analysis technologies of C, H, O, S and N isotope series are still playing a major role. Halogen and silicon isotopes are emerging rapidly. Geochronological study of hydrocarbon accumulation has entered a new era of accurate dating of oil-gas reservoirs. New analysis methods of organic chemicals have made it possible to discover new compounds, and this discovery has provided a new evidence for studying the genesis of oil and gas. With the increasing complexity of oil-gas exploration targets, it is more urgent to carry out the research of petroleum geochemistry. In the future, the research and development and application of new technologies will be the important mission for researchers in the field of petroleum geochemistry and hydrocarbon accumulation.

The hydraulic fracturing assisted oil displacement (HFAD) technique, which is based on large-scale hydraulic fracturing, has been applied to the old oilfields with extra high water cut, achieving a remarkable effect of enhanced oil recovery (EOR). To further clarify the impact of HFAD technique on the oil displacement efficiency of HFAD agents, the paper investigates the adsorption loss of HFAD agents on the porous media surface under high pressure. Firstly, by carrying out dynamic adsorption experiments under ordinary pressure and high pressure conditions, changes in the dynamic adsorption capacity of HFAD agents on the core surface during HFAD process were compared and analyzed. In combination with conventional mercury injection experiment and scanning electron microscope (SEM)test, the mechanism of reduced absorption under high pressure was clarified. Then the impact of high-pressure reduced adsorption on enhanced oil recovery by HFAD technique was confirmed by the physical simulation experiment of reverse hydraulic fracturing-assisted oil displacement. Research shows that the dynamic adsorption capacity of HFAD agents on the core surface is decreased with the increase of the displacement pressure difference. When the displacement pressure differences are 0.5 MPa, 1.0 MPa and 1.5 MPa, the dynamic saturated adsorption capacity of HFAD agents on the core surface is decreased by 40.67 %, 62.17 % and 72.38 %, respectively, as compared with that under the displacement pressure difference of 0.1 MPa. At a high pressure, the core pore structure is changed, i.e., the average pore radius and seepage velocity are increased, fluid seepage resistance is decreased, and the dynamic saturated adsorption capacity of HFAD agents on core surface is reduced. Additionally, the oil displacement efficiency of HFAD agents can be improved by reduced absorption under high pressure, which is 1.96 times higher than that under ordinary pressure. In conclusion, high displacement pressure in the HFAD process can effectively reduce the dynamic adsorption capacity of HFAD agents in reservoirs, thus improving the oil displacement efficiency. The research results are of important guiding significance for further EOR in the field application stage of HFAD technique.

At present, it is considered that the accumulation of tight oil is characterized by source-reservoir integration or large-scale near-source distribution. However, the exploration practice indicates that the sweet spots near high-quality source rocks in continental tight oil areas in China generally contain no oil or even produce a large amount of water. Therefore, it is necessary to re-recognize the sweet spots where tight oil is enriched. Based on systematically summarizing the classification scheme and geneses of the existing source-reservoir interlayer, as well as a large amount of core observations, the source-reservoir interlayer is divided into three types, i.e., argillaceous interlayer, tight sandstone with argillaceous laminae, and sand-shale transition section, of which the physical properties, distribution and logging response characteristics are described separately. The study suggests that the tight oil accumulation is mainly driven by the expansive force generated as a result of the hydrocarbon generation pressurization of source rock. When the charging resistance is greater than the expansive force, it is not conducive to oil-gas accumulation. Quantitative characterization shows that the thickness, transverse continuity and fracture development of source-reservoir interlayer jointly control the charging resistance and affect the barrier capacity of source-reservoir interlayer. Based on this, four pool-controlling modes for tight oil enrichment in the source-reservoir interlayer are established as follows. (1)When the thickness of the source-reservoir interlayer is smaller than the effective barrier thickness, the oil and gas will break through the barrier and continue to migrate. (2)When the extension radius of the source-reservoir interlayer is smaller than the radius of the affected area, the oil and gas can break through from the edge area and form a radial oil-gas accumulation zone. (3)When the thickness of the source-reservoir interval is greater than the effective barrier thickness and the extension radius is greater than the radius of the affected area, oil and gas migration can be effectively blocked, resulting in the phenomenon of "sand without oil" in local areas. (4)When cracks are developed in the source-reservoir interlayer, the barrier capacity will be reduced, making it easier for oil and gas to break through. In conclusion, these research results and understandings are expected to improve the theoretical basis of continental tight oil in China and provide theoretical guidance for the exploration and development of continental tight oil in China.

The water-flooding oilfield in Bohai Bay is dominated by the unconsolidated sandstone with high porosity and high permeability. As a result, the heterogeneity is further intensified from the stage of strong injection and production in long subsection to the high water cut stage. This leads to a series of problems, such as the difficulty in exploiting more sub-layers by water flooding and conventional polymer flooding and continuously and effectively expanding the swept volume. According to the differences in flooding control strength in chemical system, polymer gel, elastic dispersion fluid and polymer were defined as being of strong, medium and weak flooding control system. Based on the dynamic change rules of flow resistance during continuous chemical flooding (continuous injection in a single slug system), in combination with a test on the effective injection pressure of heterogeneous cores, a study was performed on the dynamic characteristics of expanding the swept volume by discontinuous chemical flooding (hereinafter referred to as DCF), composed of strong, medium, and weak flooding control systems. Then, the microscopic mechanism of the expanded swept volume was revealed by microfluidic experiment. The discontinuous chemical flooding slug combined injection mode was optimized by the parallel-cores flooding experiment. Finally, the feasibility of enhanced oil recovery by discontinuous chemical flooding was verified by field tests in offshore oilfields. The results show that the total mobility of oil and water phases during the continuous chemical flooding process is increased, the proportion of the total mobility of the high-permeability area in heterogeneous core is also increased, and the ability of expanding swept volume is restricted. Therefore, DCF substitution model for the slug combinations of different pharmaceutical systems can be used to effectively solve the problem of insufficient, excessive or uneven resistance increasing capacity from single slug injection. In addition, microfluidic experiments show that the "strong-weak" and "weak-strong" combinations of DCF can expand the swept volume by 29.2 % and 14.0 % as compare with the single continuous injection mode, respectively. Core flooding experiments show that the "medium-strong-weak-strong-weak" combination of DCF has a better EOR effect and can further improve oil recovery by 4.41 % as compared with continuous polymer flooding. Thus, it can be seen that effective control of injection and production pressure difference and continuous expansion of microscopic heterogeneous remaining oil are the main mechanisms of EOR by non-continuous chemical flooding. The pilot test of DCF in 2 wells of BZ oilfield in Bohai Bay shows that the water cut of the flooding response well is reduced by up to 14 %, and the oil production is increased to 6.97×10 ⁴t, indicating a good effect of controlling water control and increasing oil production.

Millimeter-scale fine evaluation of shale reservoir performance and oil-bearing property is of great significance for studying the enrichment characteristics of shale oil. This study targets at the medium to high maturity shale in Member 1 of Qingshankou Formation in Gulong sag of Songliao Basin. A series of analytical experiments were carried out, including micro-X-ray fluorescence spectroscopy, rock thin section observation, low-temperature nitrogen adsorption, high-pressure mercury injection, rock pyrolysis, as well as measurement of total organic carbon content. The results show that calcite+clay mineral lamina, clay mineral lamina, calcite lamina, felsic lamina, clay mineral layer, pyrite layer, and dolomite+clay mineral layer are mainly developed in the laminated and layered shale in key exploration sections of the study area. The combination of clay minerals and organic matter can always form organic-clay complexes, and the interaction between the both results in the formation of clay mineral lamina/layer and calcite/dolomite+ clay mineral lamina/layer with larger pore volume and specific surface area, when compared with calcite, felsic, and pyrite lamina/layer. It is verified that clay mineral and organic matter content are the main factors affecting shale reservoir shale reservoir performance and oil-bearing property in the study area. It is suggested that the shale strata rich in organic matter and clay mineral should be the preferred target for exploration.

Industrial oil flow has been discovered in hydrocarhon exploration from the Permian to the Jurassic in the central Mahu sag, showing promising indications of oil and gas. However, the level of overall exploration in the study area remains relatively low. In addition, there is a notable absence of systematic research on the geological conditions for hydrocarbon enrichment, accumulation mode and primary controlling factors. A deep understanding of accumulation conditions and the distribution of favorable zones within the central Mahu sag is crucial to improving the efficiency of hydrocarbon exploration efforts. Based on recent data from core, logging, well tie and seismic profiles, and microscopic rock thin section observation, this paper investigates the characteristics of source rocks in the central Mahu sag, as well as the sedimentary characteristics and reservoir-controlling factors of key target strata, including the Permian Xiawuerhe Formation, Triassic Baikouquan Formation and Baijiantan Formation, and Jurassic Badaowan Formation. On this basis, this study determines the locations of multi-layered oil-gas target strata and identifies three-dimensional accumulation modes, thus providing a forward-looking prediction for the next phase of exploration. The study indicates that a widespread strike-slip fault system facilitates communication with the underlying Permian source rocks. Thus, oil and gas can be transported vertically and laterally to the Permian Xiawuerhe Formation and Triassic Bakouquan Formation through faults and unconformities, and further to shallow formations through faults for oil-gas accumulations. The extensive hydrocarbon accumulation in Mahu sag lies in the good reservoir-cap assemblage of widespread fan delta front facies mud-poor gravel reservoirs and retrogradational fan delta facies sediments with the late massive set of mudstone in Xiawuerhe Formation and Bakouquan Formation. The shallow oil-gas accumulation is associated with the favorable reservoir-cap assemblage of the thin-bedded glutenite reservoirs with massive mudstone in Baijiantan Formation and Badaowan Formation. A comprehensive analysis suggests that the fan delta front facies sandbodies of the Xiawuerhe Formation and the upper submember of Member 1 of the Baikouquan Formation in the central Mahu sag can develop high-quality reservoirs, and possess conditions for the large-scale development of stratigraphic traps. Moreover, braided fluvial delta front facies thin-bedded glutenites of the Member 2 of Baijiantan Formation and the Member 1 of Badaowan Formation in the central Mahu sag can develop high-quality reservoirs and provide favorable conditions for the formation of lithological traps. All the above are key strata for further oil-gas exploration in the central Mahu sag.

Several groups of strike-slip faults are developed in the central Sichuan Basin. Due to the small vertical displacement of strike-slip faults and the superposition of multi-period activities, it is difficult to identify the fault formation time. Comprehensively based on the U-Pb dating of multi-stage carbonate cements near the fault zone, in combination with the analyses of mineral diagenetic sequence and fluid inclusions as well as dating results of other minerals, the paper confirms the multi-stage activity time of strike-slip faults in the central Sichuan Basin, and also analyzes the controlling effect of strike-slip faults on hydrocarbon accumulation. The research results indicate that the strike-slip faults underwent multiple stages of activities, and mainly occurred from the Early Caledonian period to Yanshan period. The tensional strike-slip faults, which formed during the Late Hercynian period and were affected by the Emei taphrogenic movement, vertically connected with multiple layers and facilitated the formation of high-quality reservoirs near the fault zone, thus providing transportation conditions for the formation of large-scale paleo-oil reservoirs during the Indosinian period. Moreover, a significant amount of oil was generated in the source rocks of the rifting trough during the Indosinian period. The oil was then transported vertically and horizontally along the NWW-trending strike-slip fault over long distances, resulting in the three-dimensional differential enrichment of paleo-oil reservoirs. The paleo-oil reservoir underwent quasi-in-situ cracking in the Yanshanian period, leading to the formation of paleo-gas reservoirs. Subsequently, these paleo-gas reservoirs underwent adjustment, reconstruction and re-migration during the period from the Late Yanshanian to the Himalayan epoch. At that time, the NWW-trending strike-slip faults primarily played a role in sealing and transverse shielding, thus controlling the local gas enrichment and preservation. In conclusion, the NWW-trending strike-slip faults played a significant role in controlling the formation, migration, and accumulation of hydrocarbons in the study area.

Since the discovery of Lucaogou Formation shale oil in Jimusar sag of Junggar Basin, it has third-level reserves of 4.3×10 ⁸t through ten years of exploration and development. In 2020, Jimusar sag became a national development demonstration zone of continental shale oil with an oil production of 60×10 ⁴t. A series of theoretical innovation and technological breakthroughs have been achieved in terms of geological theory of shale oil accumulation in Jimusar sag, supporting exploration and development technologies, and benefits management. The research results show as follows. Jimusar sag is a vast lake basin under the stable tectonic setting, where multi-component peperite with rich organic matters has been deposited, with the thickness of 275 m. The integrated distribution of thin source-reservoir interbeds plays an important role in the enrichment and preservation of shale oil. Due to high source-reservoir ratio (4.5:1), high organic matter abundance (3.24 %) and sedimentary environment of saline lake, the maturity of crude oil in the sag has been improved, and the vitrinite reflectance R _o is up to 1.05 %. Overpressure commonly exists in tsag with an average pressure coefficient of 1.36. The charging efficiency and oil enrichment degree are enhanced as a result of the source-reservoir pressure difference, indicating the formation of reservoirs with high oil saturation and high pressure coefficient. The current exploration and development technologies of shale oil in Jimusar sag are basically established. The geological understanding has been improved by the fine three-dimensional seismic technique of broadband excitation and combination of logging and seismic acquisition. The fine characterization of shale oil "sweet spots" and classified evaluation provide the bases for hydrocarbon development and deployment. The drilling ratio for "gold targets" can provide a basis for high and stable production of horizontal wells. The complex fracture networks are effective means for the efficient development of shale oil. The reasonable drainage and production system is beneficial to fully expand the production capacity of horizontal wells. The market-based cost reduction is key to the benefit development of shale oil in Jimusar sag. The technology, management and benefit of shale oil in Jimusar sag lead the way in China, and provide references and demonstration for the efficient exploration and development of continental shale oil in China.

This study focuses on the Lucagou Formation of Jimusaer sag in Junggar Basin. Based on the lithological and reservoir pore characteristics, the migration and enrichment mechanisms of shale oil were determined using geochemical analysis data. The analysis of biomarkers shows that the lower section of sweet spots and the central thick mudstone interval of Lucagou Formation are independent petroleum systems without the occurrence of mixed shale oil source in the longitudinal direction, and the crude oil in reservoir sandbodies is derived from adjacent hydrocarbon source rocks, and characterized with near-source migration and in-situ accumulation, displaying a self-generation, self-reservoir and near-source accumulation model. Besides originating from nearby hydrocarbon source rocks, the shale oil in the upper section of sweet spots is mainly derived from deep hydrocarbon source rocks, and characterized with lateral migration and enrichment of shale oil, displaying a mixed accumulation model based on long-distance lateral migration and vertical near-source migration. The analyses of well profiles, rock thin sections, and high-pressure mercury injection experiments show that the upper section of sweet spots has the characteristics of low crude oil density, large reservoir thickness (single sandbody with the thickness of more than 1.6 m), well-developed intergranular pores, and good horizontal permeability, providing favorable conditions for the lateral migration of shale oil. By contrast, the crude oil density is higher, the reservoir thickness is thinner, and intergranular pores are not well developed in the central mudstone interval and the lower section of sweet spots, which is unfavorable for the lateral migration and enrichment of shale oil. The research results have identified two favorable depth intervals for the development of sweet spots of shale oil in the upper section of Lucagou Formation, i.e., the shallow depth section with high porosity and the deep depth section with developed secondary dissolution pores. The lateral migration distances of shale oil during enrichment in these two sections are 7300 m and 4100 m respectively. The shale oil enrichment in the lower section of sweet spots and the central thick mudstone interval needs to consider the hydrocarbon generation intensity and expulsion amount of adjacent source rocks. The favorable exploration interval in the lower section of sweet spots is below the peak oil generation depth (over 3 300 m). The research results have certain guiding significance for the discovery of interbedded shale oil sweet spots and the shale oil exploitation.

It is traditionally considered that shale gas reservoirs do not contain or contain little hydrogen sulfide (H ₂S). However, low to extra-high content of H ₂S has been detected in 9 shale gas reservoirs in the ten years of exploration and development practice, and high to extra-high content of H ₂S are often found in calcareous shale gas reservoirs. According to the sequential order of H ₂S formation time, "natural geological process" and "anthropogenic cause" are regarded as two major causes for the occurrence of H ₂S in shale play. The former focuses on demonstrating the residue or migration of primary H ₂S in gas reservoirs as a result of the natural geological processes, while the latter emphasizes that the introduction of microorganisms and chemical substances by field operations (such as drilling, hydraulic fracturing) can result in the formation and emergence of secondary H ₂S after multiple processes under the complex downhole conditions. The proposal of "anthropogenic cause" has shed new light on the occurrence of H ₂S in shale gas reservoirs, but has not received much attention till now. Meanwhile, the mutually exclusive and complementary relationships between "natural geological process" and "anthropogenic cause" have not yet been clarified. Furthermore, the research of evaluating the primary supply capacity of H ₂S in shale gas reservoirs shall be carried out in the future. Meanwhile, it is required to deeply explore and establish the genesis identification criteria and output prediction system of epigenetic H ₂S based on field production data, so as to deepen the understanding of the genetic mechanism of H ₂S in shale gas reservoirs, thus providing a theoretical support for subsequent exploration and development of shale gas.

The shale oil reservoirs in Qingcheng oilfield, located in Ordos Basin, are characterized by multiple periods of vertically stacked oil layers and strong lateral heterogeneity, making it challenging to optimize the development well pattern. Based on considering the geological characteristics of shale oil reservoirs in Qingcheng oilfield, and comprehensively using the methods of oilfield application, reservoir engineering and numerical simulation, a systematic study was conducted on the orientation, length, well spacing, three-dimensional well pattern development, and reasonable stratification of the horizontal section, so as to maximize the utilization of reserves. The results show that the main orientation of horizontal wells should be perpendicular to the maximum principal stress direction; however, taking into account the distribution direction of sand bodies, the utilization of underground reserves, and the location of surface well site, the orientation of wells in horizontal section can be appropriately deviated in the target front area and restricted surface area. The optimal length of horizontal section is mainly 1 500 m, and the length of the horizontal section affected by the extension of sand body is within the range of 600 m to 800 m. The optimized controllable reserves per well is (25-30)×10 ⁴ t, and generally the well spacing is 500 m; there are various deployment areas in the oil layers of different thickness. The three-dimensional development technique is applied for the oil layers with a vertically stratified thickness greater than 10 m. Based on the above study, a three-dimensional well pattern has been established for the multi-layered shale oil reservoirs. The research results present a single well estimated ultimate recovery (EUR) of (2.6-2.8)×10 ⁴ t and an annual oil production of 165×10 ⁴ t in Qingcheng oilfield, achieving large-scale efficient development.