Using the theories of multi-field coupling within a multi-sphere interaction framework and the Whole Petroleum System, this study investigates the formation, distribution and enrichment of hydrocarbon resources, promoting a shift in exploration philosophy from a singular to an integrated approach. By integrating disciplines such as geochemistry, geodynamics and structural geology, it systematically analyzes the coupling effects of tectonic stress, thermal, pressure and fluid potential fields in sedimentary basins and their controlling mechanisms on hydrocarbon generation, migration and accumulation. Combined with typical case studies from various basins, the distribution patterns of conventional, tight and shale oil and gas are revealed. The results demonstrate that multi-sphere interactions govern the ordered distribution of different hydrocarbon types by influencing the accumulation process, thereby establishing a hydrocarbon accumulation model described as “Spheres control Fields, then Fields control Thresholds, and Thresholds define Distribution”. This theoretical framework aids in enhancing exploration efficiency and optimizing resource development strategies, providing novel insights and perspectives for future petroleum exploration.

This study aims to delve into the ordered distribution and the mechanisms underlying differential hydrocarbon enrichment of conventional and unconventional hydrocarbon reservoirs in the whole petroleum system (WPS) of a petroliferous basin. Focusing on the Dongpu Sag of the Bohai Bay Basin, we analyze the ordered distribution characteristics of hydrocarbon reservoirs in the WPS of the Paleogene Shahejie Formation, and delineate the dynamic fields for hydrocarbon accumulation and reveal the mechanisms behind differential hydrocarbon enrichment. The results indicate that the hydrocarbon reservoirs in the WPS of the Shahejie Formation exhibit an ordered distribution pattern, with conventional oil reservoirs, conventional volatile oil reservoirs, and tight gas reservoirs distributed sequentially from the structural high to the slope zone and then to the sub-sag zone. The buoyancy-driven hydrocarbon accumulation depth (BHAD) in the Shahejie Formation corresponds to average porosities ranging from 10.0% and 12.0% and an average burial depth of 3580 m. In contrast, the hydrocarbon accumulation depth limit (HADL) in this formation is associated with an average porosity of 1.9% and an average burial depth of 5580 m. Based on their genetic mechanisms, hydrocarbon reservoirs in the Shahejie Formation can be categorized into three types: (1) conventional hydrocarbon reservoirs formed in free dynamic field dominated by buoyancy; (2) tight and reformed hydrocarbon reservoirs formed in confined dynamic field dominated by non-buoyancy such as hydrocarbon generation-induced expansion force; and (3) shale hydrocarbon reservoirs formed in bound dynamic field. The hydrocarbon accumulation pattern varies across different structural locations. In the structural highs, hydrocarbon accumulation patterns include “early generation-single source (dominant)-upper accumulation,” “late generation-mixed sources (dominant)-middle accumulation,” and “late generation-self-sourced reservoir-lower accumulation.” In the slope zone, the hydrocarbon accumulation pattern proves to be of “early generation-transport along fault-slope-salt-mud sealing-mixed accumulation of crude oils with the same source but varying maturities.” In contrast, the sub-sag zone is dominated by self-sourced gas reservoirs.

The Yangchungou area is a key replacement area for shale gas exploration in eastern Sichuan in China. Its main control fault, the Yangchungou fault, is an important structure affecting shale gas accumulation in the area, but there are few previous studies, resulting in a low degree of overall research. In order to clarify the structural deformation characteristics of the Yangchungou fault and its geological significance, based on the latest interpretation of three-dimensional seismic data, the geometric characteristics of the Yangchungou fault are described. And we analyze its formation mechanism through fault properties and activity period. Based on this, the relationship between the Yangchungou and Zunyi faults and its influence on shale gas accumulation are discussed. The results show that: (1) The Yangchungou fault is mainly characterized by a planar thrust structure from east to west. The surface outcrop data show characteristics of sinistral compression and torsion. In addition, the Yangchungou fault is characterized by multiple superimposed and nearly parallel thrust slip fault zones along the Silurian and Cambrian, which control the fault development anticline of the middle and shallow deformation layers. (2) The Yangchungou fault is not a part of the Zunyi fault. The structural deformation characteristics of the Yangchungou and Zunyi faults are very different. They show completely different structural styles in seismic profiles. Therefore, the Yangchungou fault and the Zunyi fault are not two parts of the same fault. (3) The Yangchungou fault formed a small fault in a nearly north-south direction during the early Xuefeng orogeny, which caused the Zunyi fault to undergo left lateral reverse washing and sliding. The current form of the Yangchungou fault was formed in the late stage by the reverse compression torsion of the arc-shaped folded wing from east to west. Therefore, the Yangchungou fault has undergone uneven contraction from the Late Jurassic to the Late Cretaceous and reverse sliding from east to west in the Late Cretaceous. (4) The Yangchungou fault has formed the Yangchungou anticline and a complex fracture network. The Yangchungou anticline reduces the depth of shale burial, slows down the evolution of shale maturity, and the complex fracture network increases the storage space, but does not seriously damage the preservation conditions. Both are conducive to the migration and accumulation of shale gas into reservoirs. The development of high and steep strata and compressional and torsional faults can have a destructive effect on shale gas reservoirs. The results of this study can help for better understanding the basin-mountain coupling process and shale gas exploration.

Alkaline lacustrine shale is highly heterogeneous, and the complex relationship between the organic-inorganic porosity network and hydrocarbon occurrence restricts the effectiveness of shale oil exploration and development. Herein, we investigated the Fengcheng Formation (P₁f) in Mahu Sag. This study integrated geochemistry, Soxhlet extraction, scanning electron microscopy, gas adsorption, and nuclear magnetic resonance T₁-T₂ spectroscopy to elucidate the microscopic oil occurrence mechanisms in shales. Results indicate the presence of felsic shale, dolomitic shale, lime shale, and mixed shale within the P₁f. Matrix pores and microfractures associated with inorganic minerals are the predominant pore types in P₁f. Adsorbed oil primarily resides on the surfaces of organic matter and clay minerals, while free oil predominantly occupies inorganic pores and microfractures with larger pore sizes. Variations exist in the quantity and distribution of shale oil accumulation across different scales, where free oil and adsorbed oil are governed by dominant pores with diameters exceeding 10 nm and ineffective pores with diameters below 10 nm, respectively. Shale oil occurrence characteristics are influenced by organic matter, pore structure, and mineral composition. Felsic shale exhibits a high abundance of dominant pores, possesses the highest oil content, predominantly harbors free oil within these dominant pores, and demonstrates good mobility. Fluid occurrence in dolomitic shale and lime shale is intricate, with low oil content and a free oil to adsorbed oil ratio of 1:1. Mixed shale exhibits elevated clay mineral content and a scarcity of dominant pores. Moreover, ineffective pores contain increased bound water, resulting in medium oil content and limited mobility predominantly due to adsorption. Presently, shale oil mainly occurs in the dominant pores with a diameter larger than 10 nm in a free state. During the exploration and development of alkaline lacustrine shale oil resources, emphasis should be placed on identifying sweet spots within the felsic shale characterized by dominant pores.

Research has identified and increasingly explored the micro-migration phenomenon in shaly strata, which is currently one of the key scientific issues affecting shale oil accumulation and efficient development. Recently, qualitative and quantitative methods for characterizing hydrocarbon fractionation related to shale oil micro-migration have been proposed, which brought promising prospects to oil micro-migration research. Three key techniques in this field are summarized in this minireview, and the outlook for shale oil micro-migration characterization is prospected. Fourier transform ion cyclotron resonance mass spectrometry can be employed to distinguish subtle composition differences related to short-distance migration; core-flooding extraction experiments can be utilized for the quantitative characterization of micro-migration in organic-rich shale; and semi-open thermal simulation experiments are useful to analyze the chemical composition and structural evolution of expelled and retained oil. These three methods have different focus and advantages, while they provide different viewpoints and means for the characterization of shale oil micro-migration and have all achieved good results in different regions. Studies regarding the latest technologies deepen our understanding of the short-distance migration of shale oil, as well as improve our knowledge of the mechanisms of shale oil micro-migration, which is of great practical significance to the evaluation of shale oil content and mobility and further optimizes the identification of sweet spots and the effects of fracturing development.

A comprehensive understanding of the characteristics and mechanisms underlying hydrocarbon generation from organic matter has emerged as a pivotal challenge in deciphering the “life mystery” of oil and gas, thereby guiding strategic planning for the global petroleum industry. The swift advancements in materials science, drilling engineering, computer technology, big data, and artificial intelligence have furnished robust methodologies and tools for research into organic hydrocarbon generation. This perspective offers an analysis and synthesis of three distinct research paradigms pertinent to organic hydrocarbon generation: Theoretical analysis, experimental exploration, and numerical simulation. These three research modalities probe the mechanisms of organic hydrocarbon generation across varied scales, with their findings mutually reinforcing and validating each other. This synergy provides invaluable insights that contribute to a holistic understanding of organic hydrocarbon generation, facilitating a comprehensive assessment of the potential of subterranean oil and gas resources.

As the global petroleum exploration domain gradually shifts from conventional to unconventional hydrocarbon resources, the classical petroleum system theory faces new challenges in terms of guiding the deepening exploration practices in the petroleum industry. After years of research, Chengzao Jia proposed the whole petroleum system concept and established an orderly distribution model for the coexistence of conventional and unconventional petroleum, which provides a new theoretical framework for the joint assessment and integrated exploration of conventional and unconventional petroleum resources. In this context, the 1^st International Symposium on Whole Petroleum System Theory and New Directions for Petroleum Geology Development was held in Beijing in October 2-3, 2023. The theme was “Whole petroleum system theory and new frontiers in petroleum exploration”. Experts engaged in in-depth discussions on the progress of whole petroleum system theory and development directions of petroleum geology; they systematically reviewed the new theory developments and advances in sequence stratigraphy, tight oil and gas, shale oil and gas reservoir characteristics, genetic mechanisms, and development mechanisms. The conference also proposed unified genetic models for conventional and unconventional petroleum resources, and novel methods and technologies for joint assessment. Furthermore, it also included case studies on the whole petroleum system in clastic and carbonate formations in oil and gas basins, challenges, opportunities, and new directions in the development of petroleum geology. This symposium provided a valuable opportunity for the petroleum geology community to gain a deep understanding of the “whole petroleum system theory” and to summarize and refine the development directions of petroleum geology. Undoubtedly, this event contributes to the advancement of the whole petroleum system theory, guiding the development of petroleum geology theory and further promoting the joint assessment and integrated future development and utilization of conventional and unconventional petroleum resources.

Conventional and tight unconventional oil and gas resources in the Huizhou Depression have shown broad exploration prospects, which mainly originate from Wenchang Formation source rocks. Thus far, studies on Wenchang Formation source rocks mainly focused on the geochemical characteristics and conventional petroleum resource evaluation; however, the correlation of conventional, tight, and shale oil and gas, and their resources are still unknown. In fact, the formation of conventional, tight, and shale oil and gas are intrinsically related, which allows for a more objective evaluation to consider the three types of oil and gas resources simultaneously in the whole dynamic process of both hydrocarbon generation and expulsion, as well as reservoir tightness history. In this work, based on geological and geochemical analyses, the improved hydrocarbon generation potential method was utilized to establish a hydrocarbon generation and expulsion model of the Wenchang Formation source rocks. Then, combined with the reservoir tightness history, the conventional, tight, and shale oil and gas resources were evaluated. The results show that the Wenchang Formation source rocks are distributed in the whole depressions, with a thickness of 50-1850 m and an average total organic carbon content of 2.2%. The organic matter is mainly type II and is mature-high maturity. The Wenchang Formation source rocks reached hydrocarbon generation threshold and expulsion threshold at a vitrinite reflectivity of 0.43% and 0.65%, respectively, and the reservoir evolved completely tight at 2.3 Ma. Overall, the Lower and Upper Wenchang Formation contain a large amount of conventional, tight, and shale oil and gas resources.