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 industries, 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 briefly 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. Scholars have attempted to develop scenario-specific models for oil and gas operations by using visual/multimodal foundation models. 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 should be guided by the needs of oil and gas business, taking 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 large model technology.

We present a systematic summary of the geological characteristics, exploration and development history and current state of shale oil and gas in the United States. The hydrocarbon-rich shales in the major shale basins of the United States are mainly developed in six geological periods: Middle Ordovician, Middle-Late Devonian, Early Carboniferous (Middle-Late Mississippi), Early Permian, Late Jurassic, and Late Cretaceous (Cenomanian-Turonian). Depositional environments for these shales include intra-cratonic basins, foreland basins, and passive continental margins. Paleozoic hydrocarbon-rich shales are mainly developed in six basins, including the Appalachian Basin (Utica and Marcellus shales), Anadarko Basin (Woodford Shale), Williston Basin (Bakken Shale), Arkoma Basin (Fayetteville Shale), Fort Worth Basin (Barnett Shale), and the Wolfcamp and Leonardian Spraberry/Bone Springs shale plays of the Permian Basin. The Mesozoic hydrocarbon-rich shales are mainly developed on the margins of the Gulf of Mexico Basin (Haynesville and Eagle Ford) or in various Rocky Mountain basins (Niobrara Formation, mainly in the Denver and Powder River basins). The detailed analysis of shale plays reveals that the shales are different in facies and mineral components, and "shale reservoirs" are often not shale at all. The United States is abundant in shale oil and gas, with the in-place resources exceeding 0.246×10¹² t and 290×10¹² m³, respectively. Before the emergence of horizontal well hydraulic fracturing technology to kick off the "shale revolution", the United States had experienced two decades of exploration and production practices, as well as theory and technology development. In 2007-2023, shale oil and gas production in the United States increased from approximately 11.2×10⁴ tons of oil equivalent per day (toe/d) to over 300.0×10⁴ toe/d. In 2017, the shale oil and gas production exceeded the conventional oil and gas production in the country. In 2023, the contribution from shale plays to the total U.S. oil and gas production remained above 60%. The development of shale oil and gas has largely been driven by improvements in drilling and completion technologies, with much of the recent effort focused on “cube development” or “co-development”. Other efforts to improve productivity and efficiency include refracturing, enhanced oil recovery, and drilling of “U-shaped” wells. Given the significant resources base and continued technological improvements, shale oil and gas production will continue to contribute significant volumes to total U.S. hydrocarbon production.

In recent years, great breakthroughs have been made in the exploration and development of natural gas in deep coal-rock reservoirs in Junggar, Ordos and other basins in China. In view of the inconsistency between the industrial and academic circles on this new type of unconventional natural gas, this paper defines the concept of "coal-rock gas" on the basis of previous studies, and systematically analyzes its characteristics of occurrence state, transport and storage form, differential accumulation, and development law. Coal-rock gas, geologically unlike coalbed methane in the traditional sense, occurs in both free and adsorbed states, with free state in abundance. It is generated and stored in the same set of rocks through micro-migration, occasionally with the accumulation from other sources. Moreover, coal rock develops cleat fractures, and the free gas accumulates differentially. The coal-rock gas reservoirs deeper than 2 000 m are high in pressure, temperature, gas content, gas saturation, and free-gas content. In terms of development, similar to shale gas and tight gas, coal-rock gas can be exploited by natural formation energy after the reservoirs connectivity is improved artificially, that is, the adsorbed gas is desorbed due to pressure drop after the high-potential free gas is recovered, so that the free gas and adsorbed gas are produced in succession for a long term without water drainage for pressure drop. According to buried depth, coal rank, pressure coefficient, reserves scale, reserves abundance and gas well production, the classification criteria and reserves/resources estimation method of coal-rock gas are presented. It is preliminarily estimated that the coal-rock gas in place deeper than 2 000 m in China exceeds 30×10¹² m³, indicating an important strategic resource for the country. The Ordos, Sichuan, Junggar and Bohai Bay basins are favorable areas for large-scale enrichment of coal-rock gas. The paper summarizes the technical and management challenges and points out the research directions, laying a foundation for the management, exploration, and development of coal-rock gas in China.

Based on the latest results of near-source exploration in the Middle and Lower Jurassic of the Tuha Basin, a new understanding of the source rocks, reservoir conditions, and source-reservoir-cap rock combinations of the Jurassic Shuixigou Group in the Taibei Sag is established using the concept of the whole petroleum system, and the coal-measure whole petroleum system is analyzed thoroughly. The results are obtained in three aspects. First, the coal-measure source rocks of the Badaowan Formation and Xishanyao Formation and the argillaceous source rocks of the Sangonghe Formation in the Shuixigou Group exhibit the characteristics of long-term hydrocarbon generation, multiple hydrocarbon generation peaks, and simultaneous oil and gas generation, providing sufficient oil and gas sources for the whole petroleum system in the Jurassic coal-bearing basin. Second, multi-phase shallow braided river delta-shallow lacustrine deposits contribute multiple types of reservoirs, e.g. sandstone, tight sandstone, shale and coal rock, in slope and depression areas, providing effective storage space for the petroleum reservoir formation in coal-measure strata. Third, three phases of hydrocarbon charging and structural evolution, as well as effective configuration of multiple types of reservoirs, result in the sequential accumulation of conventional-unconventional hydrocarbons. From high structural positions to depression, there are conventional structural and structural-lithological reservoirs far from the source, low-saturation structural-lithological reservoirs near the source, and tight sandstone gas, coal rock gas and shale oil accumulations within the source. Typically, the tight sandstone gas and coal rock gas are the key options for further exploration, and the shale oil and gas in the depression area is worth of more attention. The new understanding of the whole petroleum system in the coal measures could further enrich and improve the geological theory of the whole petroleum system, and provide new ideas for the overall exploration of oil and gas resources in the Tuha Basin.

Super oil and gas basins provide the energy foundation for social progress and human development. In the context of climate change and carbon peak and carbon neutrality goals, constructing an integrated energy and carbon neutrality system that balances energy production and carbon reduction becomes crucial for the transformation of such basins. Under the framework of a green and intelligent energy system primarily based on “four news”, new energy, new electricity, new energy storage, and new intelligence, integrating a “super energy system” composed of a huge amount of underground resources of coal, oil, gas and heat highly overlapping with abundant wind and solar energy resources above ground, and a regional intelligent energy consumption system with coordinated development and utilization of fossil energy and new energy, with a carbon neutrality system centered around carbon cycling is essential. This paper aims to select the traditional oil and gas basins as “super energy basins” with the conditions to build world-class energy production and demonstration bases for carbon neutrality. The Ordos Basin has unique regional advantages, including abundant fossil fuel and new energy resources, as well as matching CO₂ sources and sinks, position it as a carbon neutrality “super energy basin” which explores the path of transformation of traditional oil and gas basins. Under the integrated development concept and mode of “coal + oil + gas + new energy + carbon capture, utilization and storage (CCUS)/carbon capture and storage (CCS)”, the carbon neutrality in super energy basin is basically achieved, which enhance energy supply and contribute to the carbon peak and carbon neutrality goals, establish a modern energy industry and promote regional green and sustainable development. The pioneering construction of the world-class carbon neutrality “super energy system” demonstration basin in China represented by the Ordos Basin will reshape the new concept and new mode of exploration and development of super energy basins, which is of great significance to the global energy revolution under carbon neutrality.

This paper expounds the basic principles and structures of the whole petroleum system to reveal the pattern of conventional oil/gas - tight oil/gas - shale oil/gas sequential accumulation and the hydrocarbon accumulation models and mechanisms of the whole petroleum system. It delineates the geological model, flow model and production mechanism of shale and tight reservoirs, and proposes the future research orientations. The main structure of the whole petroleum system includes three fluid dynamic fields, three types of oil and gas reservoirs/resources, and two types of reservoir-forming processes. Conventional oil/gas, tight oil/gas, and shale oil/gas are orderly in generation time and spatial distribution, and sequentially rational in genetic mechanism, showing the pattern of sequential accumulation. The whole petroleum system involves two categories of hydrocarbon accumulation models: hydrocarbon accumulation in detrital basin and hydrocarbon accumulation in carbonate basin/formation. The accumulation of unconventional oil/gas is of self-sealing, which is microscopically driven by the intermolecular force (van der Waals force). The unconventional oil/gas production has proved that the geological model, flow model and production mechanism of shale and tight reservoirs represent a new and complex field that needs further study. Shale oil/gas must be the most important resource replacement for oil and gas resources of China. Future research efforts include: (1) the characteristics of the whole petroleum system in carbonate basins and the source-reservoir coupling patterns in the evolution of composite basins; (2) flow mechanisms in migration, accumulation and production of shale oil/gas and tight oil/gas; (3) geological characteristics and enrichment of deep and ultra-deep shale oil/gas, tight oil/gas and coalbed methane; (4) resource evaluation and new generation of basin simulation technology of the whole petroleum system; (5) research on earth system - earth organic rock and fossil fuel system - whole petroleum system.

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 improved water flooding (e.g. nano-water flooding), chemical flooding (e.g. low-concentration middle-phase micro-emulsion flooding), gas flooding (e.g. micro/nano bubble flooding), thermal recovery (e.g. air injection thermal-aided miscible flooding), and multi-cluster uniform fracturing/water-free fracturing, which are discussed in this paper for their mechanisms, approaches, and key technique researches and field tests. These methods have been studied with remarkable progress, and some achieved ideal results in field tests. Nonetheless, some problems still exist, such as inadequate research on mechanisms, imperfect matching technologies, 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.

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 of shale gas/tight sandstone gas reservoirs and genetic types of tight sandstone gas reservoirs. In the United States, the proportion of tight sandstone gas in the total gas production declined from 35% in 2008 to about 8% in 2023, and the shale gas production was 8 310×10⁸ m³ in 2023, as over 70% 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 total gas production of the country. The distribution of shale gas reservoirs is continuous. According to the fault segmentation, fault displacement and the gas layer thickness, the continuous shale gas reservoirs can be divided into two types: continuity and intermittency. 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 three cratonic basins in China and Obavied Subbasin in Egypt, but oil-type gas in Appalachia Basin in the United States and Ghaba Salt Basin in Oman.

By reviewing the research progress and exploration practices of shale gas geology in China, analyzing and summarizing the geological characteristics, enrichment laws, and resource potential of different types of shale gas, the following understandings have been obtained: (1) Marine, transitional, and lacustrine shales in China are distributed from old to new in geological age, and the complexity of tectonic reworking and hydrocarbon generation evolution processes gradually decreases. (2) The sedimentary environment controls the type of source-reservoir configuration, which is the basis of "hydrocarbon generation and reservoir formation". The types of source-reservoir configuration in marine and lacustrine shales are mainly source-reservoir integration, with occasional source-reservoir separation. The configuration types of transitional shale are mainly source-reservoir integration and source-reservoir symbiosis. (3) The resistance of rigid minerals to compression for pore preservation and the overpressure facilitate the enrichment of source-reservoir integrated shale gas. Good source reservoir coupling and preservation conditions are crucial for the shale gas enrichment of source-reservoir symbiosis and source-reservoir separation types. (4) Marine shale remains the main battlefield for increasing shale gas reserves and production in China, while transitional and lacustrine shales are expected to become important replacement areas. It is recommended to carry out the shale gas exploration at three levels: Accelerate the exploration of Silurian, Cambrian, and Permian marine shales in the Upper-Middle Yangtze region; make key exploration breakthroughs in ultra-deep marine shales of the Upper-Middle Yangtze region, the new Ordovician marine shale strata in the North China region, the transitional shales of the Carboniferous and Permian, as well as the Mesozoic lacustrine shale gas in basins such as Sichuan, Ordos and Songliao; explore and prepare for new shale gas exploration areas such as South China and Northwest China, providing technology and resource reserves for the sustainable development of shale gas in China.

This study took the Gulong Shale in the Upper Cretaceous Qingshankou Formation of the Songliao Basin, NE China, as an example. Through paleolake-level reconstruction and comprehensive analyses on types of lamina, vertical associations of lithofacies, as well as stages and controlling factors of sedimentary evolution, the cyclic changes of waters, paleoclimate, and continental clastic supply intensity in the lake basin during the deposition of the Qingshankou Formation were discussed. The impacts of lithofacies compositions/structures on oil-bearing property, the relation between reservoir performance and lithofacies compositions/structures, the differences of lithofacies in mechanical properties, and the shale oil occurrence and movability in different lithofacies were investigated. The insights of this study provide a significant guideline for evaluation of shale oil enrichment layers/zones. The non-marine shale sedimentology is expected to evolve into an interdisciplinary science on the basis of sedimentary petrology and petroleum geology, which reveals the physical, chemical and biological actions, and the distribution characteristics and evolution patterns of minerals, organic matters, pores, fluid, and phases, in the transportation, sedimentation, water-rock interaction, diagenesis and evolution processes. Such research will focus on eight aspects: lithofacies and organic matter distribution prediction under a sequence stratigraphic framework for non-marine shale strata; lithofacies paleogeography of shale strata based on the forward modeling of sedimentation; origins of non-marine shale lamina and log-based identification of lamina combinations; source of organic matter in shale and its enrichment process; non-marine shale lithofacies classification by rigid particles + plastic components + pore-fracture system; multi-field coupling organic-inorganic interaction mechanism in shale diagenesis; new methods and intelligent core technology for shale reservoir multi-scale characterization; and quantitative evaluation and intelligent analysis system of shale reservoir heterogeneity.

Based on the new data of drilling, seismic, logging, test and experimental analysis, the key scientific problems in reservoir formation, hydrocarbon accumulation and efficient oil and gas development methods of deep and ultra-deep marine carbonate strata in the central and western superimposed basin in China have been continuously studied. (1) The fault-controlled carbonate reservoir and the ancient dolomite reservoir are two important types of reservoirs in the deep and ultra-deep marine carbonates. According to the formation origin, the large-scale fault-controlled reservoir can be further divided into three types: fracture-cavity reservoir formed by tectonic rupture, fault and fluid-controlled reservoir, and shoal and mound reservoir modified by fault and fluid. The Sinian microbial dolomites are developed in the aragonite-dolomite sea. The predominant mound-shoal facies, early dolomitization and dissolution, acidic fluid environment, anhydrite capping and overpressure are the key factors for the formation and preservation of high-quality dolomite reservoirs. (2) The organic-rich shale of the marine carbonate strata in the superimposed basins of central and western China are developed in the sedimentary environments of deep-water shelf of passive continental margin and carbonate ramp. The tectonic-thermal system is the important factor controlling the hydrocarbon phase in deep and ultra-deep reservoirs, and the reformed dynamic field controls oil and gas accumulation and distribution in deep and ultra-deep marine carbonates. (3) During the development of high-sulfur gas fields such as Puguang, sulfur precipitation blocks the wellbore. The application of sulfur solvent combined with coiled tubing has a significant effect on removing sulfur blockage. The integrated technology of dual-medium modeling and numerical simulation based on sedimentary simulation can accurately characterize the spatial distribution and changes of the water invasion front. Afterward, water control strategies for the entire life cycle of gas wells are proposed, including flow rate management, water drainage and plugging. (4) In the development of ultra-deep fault-controlled fractured-cavity reservoirs, well production declines rapidly due to the permeability reduction, which is a consequence of reservoir stress-sensitivity. The rapid phase change in condensate gas reservoir and pressure decline significantly affect the recovery of condensate oil. Innovative development methods such as gravity drive through water and natural gas injection, and natural gas drive through top injection and bottom production for ultra-deep fault-controlled condensate gas reservoirs are proposed. By adopting the hierarchical geological modeling and the fluid-solid-thermal coupled numerical simulation, the accuracy of producing performance prediction in oil and gas reservoirs has been effectively improved.

In the traditional well log depth matching tasks, manual adjustments are required, which means significantly labor-intensive for multiple wells, leading to low work efficiency. This paper introduces a multi-agent deep reinforcement learning (MARL) method to automate the depth matching of multi-well logs. This method defines multiple top-down dual sliding windows based on the convolutional neural network (CNN) to extract and capture similar feature sequences on well logs, and it establishes an interaction mechanism between agents and the environment to control the depth matching process. Specifically, the agent selects an action to translate or scale the feature sequence based on the double deep Q-network (DDQN). Through the feedback of the reward signal, it evaluates the effectiveness of each action, aiming to obtain the optimal strategy and improve the accuracy of the matching task. Our experiments show that MARL can automatically perform depth matches for well-logs in multiple wells, and reduce manual intervention. In the application to the oil field, a comparative analysis of dynamic time warping (DTW), deep Q-learning network (DQN), and DDQN methods revealed that the DDQN algorithm, with its dual-network evaluation mechanism, significantly improves performance by identifying and aligning more details in the well log feature sequences, thus achieving higher depth matching accuracy.

Coal measures are significant hydrocarbon source rocks and reservoirs in petroliferous basins. Many large gas fields and coalbed methane fields globally are originated from coal-measure source rocks or accumulated in coal rocks. Inspired by the discovery of shale oil and gas, and guided by “the overall exploration concept of considering coal rock as reservoir”, breakthroughs in the exploration and development of coal-rock gas have been achieved in deep coal seams with favorable preservation conditions, thereby opening up a new development frontier for the unconventional gas in coal-rock reservoirs. Based on the data from exploration and development practices, a systematic study on the accumulation mechanism of coal-rock gas has been conducted. The mechanisms of “three fields” controlling coal-rock gas accumulation are revealed. It is confirmed that the coal-rock gas is different from CBM in accumulation process. The whole petroleum systems in the Carboniferous-Permian transitional facies coal measures of the eastern margin of the Ordos Basin and in the Jurassic continental facies coal measures of the Junggar Basin are characterized, and the key research directions for further developing the whole petroleum system theory of coal measures are proposed. Coal rocks, compared to shale, possess intense hydrocarbon generation potential, strong adsorption capacity, dual-medium reservoir properties, and partial or weak oil and gas self-sealing capacity. Additionally, unlike other unconventional gas such as shale gas and tight gas, coal-rock gas exhibits more complex accumulation characteristics, and its accumulation requires a certain coal-rock play form lithological and structural traps. Coal-rock gas also has the characteristics of conventional fractured gas reservoirs. Compared with the basic theory and model of the whole petroleum system established based on detrital rock formations, coal measures have distinct characteristics and differences in coal-rock reservoirs and source-reservoir coupling. The whole petroleum system of coal measures is composed of various types of coal-measure hydrocarbon plays with coal (and dark shale) in coal measures as source rock and reservoir, and with adjacent tight layers as reservoirs or cap or transport layers. Under the action of source-reservoir coupling, coal-rock gas is accumulated in coal-rock reservoirs with good preservation conditions, tight oil/gas is accumulated in tight layers, or conventional oil/gas is accumulated in traps far away from sources, and coalbed methane is accumulated in coal-rock reservoirs damaged by later geological processes. The proposed whole petroleum system of coal measures represents a novel type of whole petroleum system.

Based on new data from cores, drilling and logging, combined with extensive rock and mineral testing analysis, a systematic analysis is conducted on the characteristics, diagenesis types, genesis and controlling factors of deep to ultra-deep abnormally high porosity clastic rock reservoirs in the Oligocene Linhe Formation in the Hetao Basin. The reservoir space of the deep to ultra-deep clastic rock reservoirs in the Linhe Formation is mainly primary pores, and the coupling of three favorable diagenetic elements, namely the rock fabric with strong compaction resistance, weak thermal compaction diagenetic dynamic field, and diagenetic environment with weak fluid compaction-weak cementation, is conducive to the preservation of primary pores. The Linhe Formation clastic rocks have a superior preexisting material composition, with an average total content of 90% for quartz, feldspar, and rigid rock fragments, and strong resistance to compaction. The geothermal gradient in Linhe Depression in the range of (2.0-2.6) ℃/100 m is low, and together with the burial history of long-term shallow burial and late rapid deep burial, it forms a weak thermal compaction diagenetic dynamic field environment. The diagenetic environment of the saline lake basin is characterized by weak fluid compaction. At the same time, the paleosalinity has zoning characteristics, and weak cementation in low salinity areas is conducive to the preservation of primary pores. The hydrodynamic conditions of sedimentation, salinity differentiation of ancient water in saline lake basins, and sand body thickness jointly control the distribution of high-quality reservoirs in the Linhe Formation.

The Bohai Bay Basin, as a super oil-rich basin in the world, is characterized by cyclic evolution and complex regional tectonic stress field, and its lifecycle tectonic evolution controls the formation of regional source rocks. The main pre-Cenozoic stratigraphic system and lithological distribution are determined through geological mapping, and the dynamics of the pre-Cenozoic geotectonic evolution of the Bohai Bay Basin are investigated systematically using the newly acquired high-quality seismic data and the latest exploration results in the study area. The North China Craton where the Bohai Bay Basin is located in rests at the intersection of three tectonic domains: the Paleo-Asian Ocean, the Tethys Ocean, and the Pacific Ocean. It has experienced the alternation and superposition of tectonic cycles of different periods, directions and natures, and experienced five stages of the tectonic evolution and sedimentary building, i.e. Middle-Late Proterozoic continental rift trough, Early Paleozoic marginal-craton depression carbonate building, Late Paleozoic marine-continental transitional intracraton depression, Mesozoic intracontinental strike-slip-extensional tectonics, and Cenozoic intracontinental rifting. The cyclic evolution of the basin, especially the multi-stage compression, strike-slip and extensional tectonics processes in the Hercynian, Indosinian, Yanshan and Himalayan since the Late Paleozoic, controlled the development, reconstruction and preservation of several sets of high-quality source rocks, represented by the Late Paleozoic Carboniferous-Permian coal-measure source rocks and the Paleogene world-class extra-high-quality lacustrine source rocks, which provided an important guarantee for the hydrocarbon accumulation in the super oil-rich basin.

Based on the geological and geophysical data of Mesozoic oil-gas exploration in the sea area of Bohai Bay Basin and the discovered high-yield volcanic oil and gas wells since 2019, this paper methodically summarizes the formation conditions of large- and medium-sized Cretaceous volcanic oil and gas reservoirs in the Bohai Sea. Research shows that the Mesozoic large intermediate-felsic lava and intermediate-felsic composite volcanic edifices in the Bohai Sea are the material basis for the formation of large-scale volcanic reservoirs. The upper subfacies of effusive facies and cryptoexplosive breccia subfacies of volcanic conduit facies of volcanic vent-proximal facies belts are favorable for large-scale volcanic reservoir formation. Two types of efficient reservoirs, characterized by high porosity and medium to low permeability, as well as medium porosity and medium to low permeability, are the core of the formation of large- and medium-sized volcanic reservoirs. The reservoir with high porosity and medium to low permeability is formed by intermediate-felsic vesicular lava or the cryptoexplosive breccia superimposed by intensive dissolution. The reservoir with medium porosity and medium to low permeability is formed by intense tectonism superimposed by fluid dissolution. Weathering and tectonic transformation are main formation mechanisms for large and medium-sized volcanic reservoirs in the study area. The “source-reservoir draping type” at the low source is the optimum source-reservoir configuration relationship for large- and medium-sized volcanic reservoirs. There exists favorable volcanic facies, efficient reservoirs and source-reservoir draping configuration relationship on the periphery of Bozhong Sag, and the large intermediate-felsic lava and intermediate-felsic composite volcanic edifices close to strike-slip faults and their branch faults are the main directions of future exploration.

Based on the observation and analysis of cores and thin sections, and combined with cathodoluminescence, laser Raman, fluid inclusions, and in-situ LA-ICP-MS U-Pb dating, the genetic mechanism and petroleum geological significance of calcite veins in shales of the Cretaceous Qingshankou Formation in the Songliao Basin were investigated. Macroscopically, the calcite veins are bedding parallel, and show lenticular, S-shaped, cone-in-cone and pinnate structures. Microscopically, they can be divided into syntaxial blocky or columnar calcite veins and antitaxial fibrous calcite veins. The aqueous fluid inclusions in blocky calcite veins have a homogenization temperature of 132.5-145.1 ℃, the in-situ U-Pb dating age of blocky calcite veins is (69.9±5.2) Ma, suggesting that the middle maturity period of source rocks and the conventional oil formation period in the Qingshankou Formation are the sedimentary period of Mingshui Formation in Late Cretaceous. The aqueous fluid inclusions in fibrous calcite veins with the homogenization temperature of 141.2-

157.4 ℃, yields the U-Pb age of (44.7±6.9) Ma, indicating that the middle-high maturity period of source rocks and the Gulong shale oil formation period in the Qingshankou Formation are the sedimentary period of Paleocene Yi’an Formaiton. The syntaxial blocky or

columnar calcite veins were formed sensitively to the diagenetic evolution and hydrocarbon generation, mainly in three stages (fracture opening, vein-forming fluid filling, and vein growth). Tectonic extrusion activities and fluid overpressure are induction factors for the formation of fractures, and vein-forming fluid flows mainly as diffusion in a short distance. These veins generally follow a competitive growth mode. The antitaxial fibrous calcite veins were formed under the driving of the force of crystallization in a non-competitive growth environment. It is considered that the calcite veins in organic-rich shale of the Qingshankou Formation in the study area has important implications for local tectonic activities, fluid overpressure, hydrocarbon generation and expulsion, and diagenesis-hydrocarbon accumulation dating of the Songliao Basin.

In addition to the organic matter type, abundance, thermal maturity, and shale reservoir space, the preservation conditions of source rocks play a key factor in affecting the quantity and quality of retained hydrocarbons in source rocks of lacustrine shale, yet this aspect has received little attention. This paper, based on the case analysis, explores how preservation conditions influence the enrichment of mobile hydrocarbons in shale oil. The following findings are obtained: (1) Optimal preservation conditions ensure the retention of sufficient light hydrocarbons (C₁-C₁₃), medium hydrocarbons (C₁₄-C₂₅) and small molecular aromatics (including 1-2 benzene rings) in the formation, which enhances the fluidity and flow of shale oil; (2) Good preservation conditions also maintain a high energy field (abnormally high pressure), facilitating the maximum outflow of shale oil; (3) Good preservation conditions ensure that the retained hydrocarbons have the miscible flow condition of multi-component hydrocarbons (light hydrocarbons, medium hydrocarbons, heavy hydrocarbons, and heteroatomic compounds), so that the heavy hydrocarbons (∑C₂₅₊) and heavy components (non-hydrocarbons and asphaltenes) have improved fluidity and maximum flow capacity. In conclusion, in addition to the advantages of organic matter type, abundance, thermal maturity, and reservoir space, good preservation conditions of shale layers are essential for the formation of economically viable shale oil reservoirs, which should be incorporated into the evaluation criteria of shale oil-rich areas/segments and considered a necessary factor when selecting favorable exploration targets.

An optimization method of fracturing fluid volume strength was introduced taking well X-1 in Biyang Sag of Nanxiang Basin as an example. The characteristic curves of capillary pressure and relative permeability were obtained from history matching between forced imbibition experimental data and core-scale reservoir simulation results and taken into a large scale reservoir model to mimic the forced imbibition behavior during the well shut-in period after fracturing. The optimization of the stimulated reservoir volume (SRV) fracturing fluid volume strength should meet the requirements of estimated ultimate recovery (EUR), increased oil recovery by forced imbibition and enhancement of formation pressure and the fluid volume strength of fracturing fluid should be controlled around a critical value to avoid either insufficiency of imbibition displacement caused by insufficient fluid amount or increase of costs and potential formation damage caused by excessive fluid amount. Reservoir simulation results showed that SRV fracturing fluid volume strength positively correlated with single-well EUR and a optimal fluid volume strength existed, above which the single-well EUR increase rate kept decreasing. An optimized increase of SRV fracturing fluid volume and shut-in time would effectively increase the formation pressure and enhance well production. Field test results of well X-1 proved the practicality of established optimization method of SRV fracturing fluid volume strength on significant enhancement of shale oil well production.

Based on petroleum exploration and new progress of oil and gas geology study in the Qiongdongnan Basin, combined with seismic, logging, drilling, core, sidewall coring, 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 water 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, and dominated by thermogenic gas. (2) The reservoirs are mainly composed of the Quaternary deep-water 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 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 and submarine fan composite migration, deep-sea mudstone-mass flow mudstone-hydrate-bearing strata ternary sealing, late dynamic accumulation, and large-scale enrichment at ridges. The new understanding obtained from the research has reference and enlightening significance for the next step of deepwater and ultra-shallow layers, as well as oil and gas exploration in related fields or regions.

The basic geological characteristics of the Qiongzhusi Formation reservoirs and conditions for shale gas enrichment and high-yield 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 acritarch, with high maturity and high hydrocarbon generation potential. (5) Deep- and shallow-water shale gas exhibit in-situ and mixed gas generation characteristics, respectively. (6) The basic law of shale gas enrichment in the Qiongzhusi Formation was proposed as “TOC controlled accumulation 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 “two highs, one medium and one low” (high felsic content, high formation pressure, medium inorganic pore content, low TOC) for organic-poor 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.

Based on the waterflooding development in carbonate reservoirs in the Middle East, in order to solve the problem of the poor development effects caused by commingled injection and production, taking the thick bioclastic limestone reservoirs of Cretaceous in Iran-Iraq as an example, this paper proposes a balanced waterflooding development technology for thick and complex carbonate reservoirs. This technology is based on the fine division of development units by concealed baffles and barriers, the combination of multi well type and multi well pattern, and the construction of balanced water injection and recovery system. For the thick carbonate reservoirs in Iran and Iraq, which are extremely heterogeneous vertically with ultra-high permeability zones of various genesis, and highly concealed baffles and barriers, based on the technologies of identification characterization and sealing evaluation for concealed baffles and barriers, the balanced waterflooding development technology is proposed, and three types of balanced waterflooding development modes/techniques are formed, namely, conventional stratigraphic framework, fine stratigraphic framework, and deepened stratigraphic framework. Numerical simulations show that this technology is able to realize a fine and efficient waterflooding development to recover, in a balanced manner, the reserves of thick and complex carbonate reservoirs in Iran and Iraq. The proposed technology provides a reference for the development optimization of similar reservoirs.

Based on a large number of newly added deep well data in recent years, the subsidence of the Ordos Basin in the Mid-Late Triassic is systematically studied, and it is proposed that the Ordos Basin experienced two important subsidence events during this depositional period. Through contrastive analysis of the two stages of tectonic subsidence, including stratigraphic characteristics, lithology combination, location of catchment area and sedimentary evolution, it is proposed that both of them are responses to the Indosinian Qinling tectonic activity on the northern edge of the craton basin. The early subsidence occurred in the Chang 10 Member was featured by high amplitude, large debris supply and fast deposition rate, with coarse debris filling and rapid subsidence accompanied by rapid accumulation, resulting in strata thickness increasing from northeast to southwest in wedge-shape. The subsidence center was located in Huanxian-Zhenyuan-Qingyang-Zhengning areas of southwestern basin with the strata thickness of 800-1 300 m. The subsidence center deviating from the depocenter developed multiple catchment areas, until then, unified lake basin has not been formed yet. Under the combined action of subsidence and Carnian heavy rainfall event during the deposition period of Chang 7 Member, a large deep-water depression was formed at slow deposition rate, with the subsidence center coincided with the depocenter basically in the Mahuangshan-Huachi-Huangling areas. The deep-water sediments were 120-320 m thick in the subsidence center, characterized by fine grain. There are differences in the mechanism between the two stages of subsidence. The early one was the response to the northward subduction of the MianLüe Ocean and intense depression under compression in Qinling during Mid-Triassic. The later subsidence is controlled by the weak extensional tectonic environment of the post-collision stage during Late Triassic.

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, upstream oil and gas production landscape is expanding, and the number of oil and gas fields in production is increasing significantly; oil and gas recoverable 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 recoverable 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 petroleum 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 fields are 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.

Based on the data of outcrop, core, logging, gas testing, and experiments, the natural gas accumulation and aluminous rock mineralization integrated research was adopted to analyze the controlling factors of aluminous rock series effective reservoirs in the Ordos Basin, NW China, as well as the configuration of coal-measure source rocks and aluminous rock series reservoirs. A natural gas accumulation model was constructed to evaluate the gas exploration potential of aluminous rock series under coal seam in the basin. The effective reservoirs of aluminous rock series in the Ordos Basin is composed of honeycomb-shaped bauxites with porous residual pisolitic and detrital structures, with the diasporite content of greater than 80% and dissolved pores as the main storage space. The bauxite reservoirs are formed under a model that planation controls the material supply, karst paleogeomorphology controls diagenesis, and land surface leaching improves reservoir quality. The hot humid climate and sea level changes in the Late Carboniferous-Early Permian dominated the development of a typical coal-aluminum-iron three-stage stratigraphic structure. The natural gas generated by the extensive hydrocarbon generation of coal-measure source rocks was accumulated in aluminous rock series under the coal seam, indicating a model of hydrocarbon accumulation under the source. During the Upper Carboniferous-Lower Permian, the relatively low-lying area on the edge of an ancient land or island in the North China landmass was developed. The gas reservoirs of aluminous rock series, which are clustered at multiple points in lenticular shape, are important new natural gas exploration fields with great potential in the Upper Paleozoic of North China Craton.

To reveal the enrichment conditions and resource potential of coal-rock gas in the Ordos Basin, this paper presents a systematic research on the sedimentary environment, distribution, physical properties, reservoir characteristics, gas-bearing characteristics and gas accumulation play of deep coals. The results show that thick coals are widely distributed in the Carboniferous-Permian of the Ordos Basin. The main coal seams 5^# and 8^# in the Carboniferous-Permian have strong hydrocarbon generation capacity and high thermal evolution degree, which provide abundant materials for the formation of coal-rock gas. Deep coal reservoirs have good physical properties, especially porosity and permeability. Coal seams 5^# and 8^# exhibit the average porosity of 4.1% and 6.4%, and the average permeability of 8.7×10^-3 μm² and 15.7×10^-3 μm², respectively. Cleats and fissures are developed in the coals, and together with the micropores, constitute the main storage space. With the increase of evolution degree, the micropore volume tends to increase. The development degree of cleats and fissures has a great impact on permeability. The coal reservoirs and their industrial compositions exhibit significantly heterogeneous distribution in the vertical direction. The bright coal seam, which is in the middle and upper section, less affected by ash filling compared with the lower section, and contains well-developed pores and fissures, is a high-quality reservoir interval. The deep coals present good gas-bearing characteristics in Ordos Basin, with the gas content of 7.5-20.0 m³/t, and the proportion of free gas (greater than 10%, mostly 11.0%-55.1%) in coal-rock gas significantly higher than that in shallow coals. The enrichment degree of free gas in deep coals is controlled by the number of macropores and microfractures. The coal rock pressure testing shows that the coal-limestone and coal-mudstone combinations for gas accumulation have good sealing capacity, and the mudstone/limestone (roof)-coal-mudstone (floor) combination generally indicates high coal-rock gas values. The coal-rock gas resources in the Ordos Basin were preliminarily estimated by the volume method to be 22.38×10¹² m³, and the main coal-rock gas prospects in the Ordos Basin were defined. In the central-east of the Ordos Basin, Wushenqi, Hengshan-Suide, Yan’an, Zichang, and Yichuan are coal-rock gas prospects for the coal seam #8 of the Benxi Formation, and Linxian West, Mizhi, Yichuan-Huangling, Yulin, and Wushenqi-Hengshan are coal-rock gas prospects for the coal seam #5 of the Shanxi Formation, which are expected to become new areas for increased gas reserves and production.

Based on the geochemical parameters and analytical data, the heat conservation equation, mass balance law, Rayleigh fractionation model and other methods were used to quantify the in-situ yield and external flux of crust-derived helium, and the initial He concentration and thermal driving mechanism of mantle-derived helium, in the Ledong Diapir area, the Yinggehai Basin, in order to understand the genetic source and migration & accumulation mechanisms of helium under deep hydrothermal fluid activities. The helium in the Ledong diapir area is primarily derived from the crust and a small amount from the mantle. For mantle-derived helium, the ³He/⁴He values are (0.002-2.190)×10^-6, the R/R_a values are 0.01-1.52, and the contribution is estimated to be 0.09%-19.84%, suggesting a relatively small percentage. In contrast, the contribution of crust-derived helium is more than 80%. For crust-sourced helium, the in-situ ⁴He yield is only (4.10-4.25)×10^-4 cm³/g, while the external ⁴He flux is significantly high, being (5.84-9.06)×10^-2 cm³/g, indicating that crust-sourced helium is dominated by external input, which is speculated to be related to atmospheric recharge of formation fluids and deep rock-water interaction. Deep hydrothermal fluid in the diapir area significantly affects the geothermal field. The ratio of the initial mass volume of ³He to the corresponding enthalpy (W) is (0.006-0.018)×10^?11 cm³/J, and the thermal contribution from the deep mantle (X_M) is between 7.63% and 36.18%, suggesting that the diapir thermal fluid plays a certain role in driving the migration of mantle-sourced ³He. The primary migration of helium in the study area is dominated by advection, and the secondary migration is controlled by hydrothermal degassing and gas-liquid separation. During the migration of helium from deep to shallow, the CO₂/³He value increases from 1.34×10⁹ to 486×10⁹, indicating the large-scale precipitation of CO₂ and apparent escape of ³He due to the effect of crust-mantle mixing and degassing. Under the influence of deep hydrothermal fluid, the migration and accumulation mechanisms of helium include: deep heat driven diffusion, advection release, vertical hydrothermal degassing; shallow lateral migration, accumulation in traps far from faults; partial pressure balance, complete cover sealing; and so on.

Acoustic reflection imaging logging technology can detect and evaluate the development of reflection anomalies, such as fractures, caves and faults, within a range of tens of meters from the wellbore, greatly expanding the application scope of well logging technology. This article reviews the development history of the technology and focuses on introducing key methods, software, and on-site applications of acoustic reflection imaging logging technology. Based on the analyses of major challenges faced by existing technologies, and in conjunction with the practical production requirements of oilfields, the further development directions of acoustic reflection imaging logging are proposed. Following the current approach that utilizes the reflection coefficients, derived from the computation of acoustic slowness and density, to perform seismic inversion constrained by well logging, the next frontier is to directly establish the forward and inverse relationships between the downhole measured reflection waves and the surface seismic reflection waves. It is essential to advance research in imaging of fractures within shale reservoirs, the assessment of hydraulic fracturing effectiveness, the study of geosteering while drilling, and the innovation in instruments of acoustic reflection imaging logging technology.

This paper systematically reviews the current applications of various spatial information technologies in CO₂ sequestration monitoring, analyzes the challenges faced by spatial information technologies in CO₂ sequestration monitoring, and prospects the development of spatial information technologies in CO₂ sequestration monitoring. Currently, the spatial information technologies applied in CO₂ sequestration monitoring mainly include five categories: eddy covariance method, remote sensing technology, geographic information system, Internet of Things technology, and global navigation satellite system. These technologies are involved in three aspects: monitoring data acquisition, positioning and data transmission, and data management and decision support. Challenges faced by the spatial information technologies in CO₂ sequestration monitoring include: selecting spatial information technologies that match different monitoring purposes, different platforms, and different monitoring sites; establishing effective data storage and computing capabilities to cope with the broad sources and large volumes of monitoring data; and promoting collaborative operations by interacting and validating spatial information technologies with mature monitoring technologies. In the future, it is necessary to establish methods and standards for designing spatial information technology monitoring schemes, develop collaborative application methods for cross-scale monitoring technologies, integrate spatial information technologies with artificial intelligence and high-performance computing technologies, and accelerate the application of spatial information technologies in carbon sequestration projects in China.

Based on the displacement discontinuity method and the discrete fracture unified pipe network model, a sequential iterative numerical method was used to construct a fracturing-production integrated numerical model of shale gas well considering the two-phase flow of gas and water. The model accounts for the influence of natural fractures and matrix properties on the fracturing process and directly applies post-fracturing formation pressure and water saturation distribution to subsequent well shut-in and production simulation, allowing for a more accurate fracturing-production integrated simulation. The results show that the reservoir physical properties have great impacts on fracture propagation, and the reasonable prediction of formation pressure and reservoir fluid distribution after the fracturing is critical to accurately predict the gas and fluid production of the shale gas wells. Compared with the conventional method, the proposed model can more accurately simulate the water and gas production by considering the impact of fracturing on both matrix pressure and water saturation. The established model is applied to the integrated fracturing-production simulation of actual horizontal shale gas wells, yielding the simulation results in good agreement with the actual production data, thus verifying the accuracy of the model.

Based on the situation and progress of marine oil/gas exploration in the Sichuan Basin, the whole petroleum system is divided for marine carbonate rocks of the basin according to the combinations of hydrocarbon accumulation elements, especially the source rock. The hydrocarbon accumulation characteristics of each whole petroleum system are analyzed, the patterns of integrated conventional and unconventional hydrocarbon accumulation are summarized, and the favorable exploration targets are proposed. Under the control of multiple extensional-convergent tectonic cycles, the marine carbonate rocks of the Sichuan Basin contain three sets of regional source rocks and three sets of regional cap rocks, and can be divided into the Cambrian, Silurian and Permian whole petroleum systems. These whole petroleum systems present mainly independent hydrocarbon accumulation, containing natural gas of affinity individually. Locally, large fault zones run through multiple whole petroleum systems, forming a fault-controlled complex whole petroleum system. The hydrocarbon accumulation sequence of continental shelf facies shale gas accumulation, marginal platform facies-controlled gas reservoirs, and intra-platform fault- and facies-controlled gas reservoirs is common in the whole petroleum system, with a stereoscopic accumulation and orderly distribution pattern. High-quality source rock is fundamental to the formation of large gas fields, and natural gas in a whole petroleum system is generally enriched near and within the source rocks. The development and maintenance of large-scale reservoirs are essential for natural gas enrichment, multiple sources, oil and gas transformation, and dynamic adjustment are the characteristics of marine petroleum accumulation, and good preservation conditions are critical to natural gas accumulation. Large-scale marginal-platform reef-bank facies zones, deep shale gas, and large-scale lithological complexes related to source-connected faults are future marine hydrocarbon exploration targets in the Sichuan Basin.

Fiber is highly escapable in conventional slickwater, making it difficult to form fiber-proppant agglomerate with propppant and exhibit limited effectiveness. To solve these problems, a novel structure stabilizer (SS) is developed. Through microscopic structural observations and performance evaluations in indoor experiments, the mechanism of proppant placement under the action of the SS and the effects of the SS on proppant placement dimensions and fracture conductivity were elucidated. The SS facilitates the formation of robust fiber-proppant agglomerates by polymer, fiber, and quartz sand. Compared to bare proppants, these agglomerates exhibit reduced density, increased volume, and enlarged contact area with the fluid during settlement, leading to heightened buoyancy and drag forces, ultimately resulting in slower settling velocities and enhanced transportability into deeper regions of the fracture. Co-injecting the fiber and the SS alongside the proppant into the reservoir effectively reduces the fiber escape rate, increases the proppant volume in the slickwater, and boosts the proppant placement height, conveyance distance and fracture conductivity, while also decreasing the proppant backflow. Experimental results indicate an optimal SS mass fraction of 0.3%. The application of this SS in over 80 wells targeting tight gas, shale oil, and shale gas reservoirs has substantiated its strong adaptability and general suitability for meeting the production enhancement, cost reduction, and sand control requirements of such wells.

A large language model (LLM) is constructed to address the sophisticated demands of data retrieval and analysis, detailed well profiling, computation of key technical indicators, and the solutions to complex problems in reservoir performance analysis (RPA). The LLM is constructed for RPA scenarios with incremental pre-training, fine-tuning, and functional subsystems coupling. Functional subsystem and efficient coupling methods are proposed based on named entity recognition (NER), 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 PK3 Block 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.

A new pore type, nano-scale organo-clay complex pore-fracture, was first discovered based on argon ion polishing-field emission scanning electron microscopy, energy dispersive spectroscopy and three-dimensional reconstruction by focused ion-scanning electron in combination with analysis of TOC, R_o values, X-ray diffraction etc. in the Cretaceous Qingshankou Formation shale in the Songliao Basin, NE China. Such pore characteristics and evolution study show that: (1) Organo-clay complex pore-fractures are developed in the shale matrix and in the form of spongy and reticular aggregates. Different from circular or oval organic pores discovered in other shales, a single organo-clay complex pore is square, rectangular, rhombic or slaty, with the pore diameter generally less than 200 nm. (2) With thermal maturity increasing, the elements (C, Si, Al, O, Mg, Fe, etc.) in organo-clay complex change accordingly, showing that organic matter shrinkage due to hydrocarbon generation and clay mineral transformation both affect organo-clay complex pore-fractures formation. (3) At high thermal maturity, the Qingshankou Formation shale is dominated by nano-scale organo-clay complex pore-fractures with the percentage reaching more than 70% of total pore space. The spatial connectivity of organo-clay complex pore-fractures is significantly better than that of organic pores. It is suggested that organo-complex pore-fractures are the main pore space of laminar shale at high thermal maturity and are the main oil and gas accumulation space in the core area of continental shale oil. The discovery of nano-scale organo-clay complex pore-fractures changes the conventional view that inorganic pores are the main reservoir space and has scientific significances for the study of shale oil formation and accumulation laws.

With drilling and seismic data of Transtensional (strike-slip) Fault System in the Ziyang area of the central Sichuan Basin, through plane-section integrated structural interpretation, 3-D fault framework model building, fault throw analyzing, and balanced profile restoration, it is pointed out that the transtensional fault system in the Ziyang 3-D seismic survey consists of the northeast-trending F_I19 and F_I20 fault zones dominated by extensional deformation, as well as 3 sets of northwest-trending en echelon normal faults experienced dextral shear deformation. Among them, the F_I19 and F_I20 fault zones cut through the Neoproterozoic to Middle-Lower Triassic Jialingjiang Formation, presenting a 3-D structure of an “S”-shaped ribbon. And before Permian and during the Early Triassic, the F_I19 and F_I20 fault zones underwent at least two periods of structural superimposition. Besides, the 3 sets of northwest-trending en echelon normal faults are composed of small normal faults arranged in pairs, with opposite directions and partially left-stepped arrangement. And before Permian, they had formed almost, restricting the eastward growth and propagation of the F_I19 fault zone. The F_I19 and F_I20 fault zones communicate multiple sets of source rocks and reservoirs from deep to shallow, and the timing of fault activity matches well with oil and gas generation peaks. If there were favorable Cambrian-Triassic sedimentary facies and reservoirs developing on the local anticlinal belts of both sides of the F_I19 and F_I20 fault zones, the major reservoirs in this area are expected to achieve breakthroughs in oil and gas exploration.

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, including the following three aspects. (1) In terms of geological elements, the traditional petroleum system 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 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-drived 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.

The shale of the ancient Cambrian Qiongzhusi Formation in Sichuan Basin is characterized by large burial depth and high maturity, but the shale gas enrichment pattern is still unclear. Based on the detailed characterization of Deyang-Anyue aulacogen, analysis of its depositional environments, together with reconstruction of shale gas generation and enrichment evolution against the background of the Leshan-Longnüsi paleouplift, the enrichment patterns of aulacogen-uplift system have been elucidated. 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. Meanwhile, 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 oil-gas adjustment stage, which also 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 its combination relationship, 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 new geological insights into the enrichment patterns of aulacogen-uplift system provide a significant theoretical basis for the exploration and breakthrough of deep to ultra-deep Cambrian shale gas, highlighting the promising exploration prospect in this domain.

The Santos Basin in Brazil has witnessed significant oil and gas discoveries in deepwater pre-salt since the 21st century. Currently, the waters in eastern Brazil stand out as a hot area of deepwater exploration and production worldwide. Based on a review of the petroleum exploration and production history in Brazil, the challenges, researches and practices, strategic transformation, significant breakthroughs, and key theories and technologies for exploration from onshore to offshore and from shallow waters to deep-ultra-deep waters and then to pre-salt strata are systematically elaborated. Within 15 years since its establishment in 1953, Petrobras explored onshore paleozoic cratonic and marginal rift basins, and obtained some small to medium petroleum discoveries in fault-block traps. In the 1970s, Petrobras developed seismic exploration technologies and several hydrocarbon accumulation models, for example, turbidite sandstones, allowing important discoveries in shallow waters, e.g. the Namorado Field and Enchova fields. Guided by these models/technologies, significant discoveries, e.g. the Marlim and Roncador fields, were made in deepwater post-salt in the Campos Basin. In the early 21^st century, the advancements in theories and technologies for pre-salt petroleum system, carbonate reservoirs, hydrocarbon accumulation and nuclear magnetic resonance (NMR) logging stimulated a succession of valuable discoveries in the Lower Cretaceous lacustrine carbonates in the Santos Basin, including the world-class ultra-deepwater super giant fields such as Tupi (Lula), Mero and Buzios. Petroleum development in complex deep water environments is extremely challenging. By establishing the Technological Capacitation Program in Deep Waters (PROCAP), Petrobras developed and implemented key technologies including managed pressure drilling (MPD) with narrow pressure window, pressurized mud cap drilling (PMCD), multi-stage intelligent completion, development with Floating Production Storage and Offloading units (FPSO), and flow assurance, which remarkably improved the drilling, completion, field development and transportation efficiency and safety. Additionally, under the limited FPSO capacity, Petrobras promoted the world-largest CCUS-EOR project, which contributed effectively to the reduction of greenhouse gas emissions and the enhancement of oil recovery. Development and application of these technologies provide valuable reference for deep and ultra-deepwater petroleum exploration and production worldwide. The petroleum exploration in Brazil will consistently focus on ultra-deep water pre-salt carbonates and post-salt turbidites, and seek new opportunities in Paleozoic gas. Technical innovation and strategic cooperation will be held to promote the sustainable development of Brazil's oil and gas industry.

There are various issues for CO₂ flooding and storage in Shengli Oilfield, which are characterized by low light hydrocarbon content of oil and high miscible pressure, strong reservoir heterogeneity and low sweep efficiency, gas channeling and difficult whole-process control. Through laboratory experiments, technical research and field practice, the theory and technology of CO₂ high pressure miscible flooding and storage are established. By increasing the formation pressure to 1.2 times the minimum miscible pressure, the miscibility of the medium-heavy components can be improved, the degree of oil production in small pores can be increased, the displacing front developed evenly, and the swept volume expanded. Rapid high-pressure miscibility is realized through advanced pressure drive and energy replenishment, and technologies of cascade gas-water alternating, injection and production coupling and multistage chemical plugging are used for dynamic control of flow resistance, so as to obtain the optimum of oil recovery factor and CO₂ storage factor. The research results have been applied to the Gao89-Fan142 in CCUS (carbon capture, utilization and storage) demonstration site, where the daily oil production of the block has increased from 254.6 t to 358.2 t, and the recovery degree is expected to increase by 11.6 percentage points in 15 years, providing theoretical and technical support for the large-scale development of CCUS.

Based on the oil and gas exploration in western depression of the Qaidam Basin, NW China, combined with the geochemical, seismic, logging and drilling data, the basic geological conditions, oil and gas distribution characteristics, reservoir-forming dynamics, and hydrocarbon accumulation model of the Paleogene whole petroleum system (WPS) in the western depression of the Qaidam Basin are systematically studied. A globally unique ultra-thick mountain-style WPS is found in the western depression of the Qaidam Basin. Around the source rocks of the upper member of the Paleogene Lower Ganchaigou Formation, the structural reservoir, lithological reservoir, shale oil and shale gas are laterally distributed in an orderly manner and vertically overlapped from the edge to the central part of the lake basin. The Paleogene WPS in the western depression of the Qaidam Basin is believed unique in three aspects. First, the source rocks with low organic matter abundance are characterized by low carbon and rich hydrogen, showing a strong hydrocarbon generating capacity per unit mass of organic carbon. Second, the saline lake basinal deposits are ultra-thick, with mixed deposits dominating the center of the depression, and strong vertical and lateral heterogeneity of lithofacies and storage spaces. Third, the strong transformation induced by strike-slip compression during the Himalayan resulted in the heterogeneous enrichment of oil and gas in the mountain-style WPS. As a result of the coordinated evolution of source-reservoir-caprock assemblage and conducting system, the Paleogene WPS has the characteristics of “whole process” hydrocarbon generation of source rocks which are low-carbon and hydrogen-rich, “whole depression” ultra-thick reservoir sedimentation, “all direction” hydrocarbon adjustment by strike-slip compressional fault, and “whole succession” distribution of conventional and unconventional oil and gas. Due to the severe Himalayan tectonic movement, the western depression of the Qaidam Basin evolved from depression to uplift. Shale oil is widely distributed in the central lacustrine basin. In the sedimentary system deeper than 2 000 m, oil and gas are continuous in the laminated limy-dolomites within the source rocks and the alga limestones neighboring the source kitchen, with intercrystalline pores, lamina fractures in dolomites and fault-dissolution bodies serving as the effective storage space. All these findings are helpful to supplement and expand the WPS theory in the continental lake basins in China, and provide theoretical guidance and technical support for oil and gas exploration in the Qaidam Basin.