For mixed shales occurring in the Jiyang Depression, Bohai Bay Basin, the controlling mechanisms of their diagenetic evolution over pore development remain poorly understood, and their diagenetic differentiation and corresponding pore response mechanisms have yet to be revealed. In this study, we investigate the mixed shales in the Minfeng Sub-sag, Jiyang Depression. Using multiple experimental methods, including petrographic and mineralogical analysis, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and low-temperature nitrogen adsorption, we investigate the diagenetic and reservoir-formation processes of carbonate, felsic, and clay minerals. The results indicate that primary pores in the mixed shales include intergranular pores of quartz, intercrystalline pores of calcites and dolomites, and clay interlayer pores. Four evolutionary stages for the formation of high-quality reservoirs are proposed: framework building, authigenic mineral-supported pore preservation, dissolution-induced porosity enhancement, and overpressure-preserved porosity. Specifically, during the early diagenetic stages A₁-A₂, the weak dissolution and recrystallization of micritic calcites contribute to the formation of millimeter-scale lamellar frameworks, providing a structural basis for pore preservation. Subsequently, from the early diagenetic stage A₂ to the middle diagenetic stage A₁, K⁺ released from the dissolution of K-feldspars facilitates the transformation of mixed illite-montmorillonite into illite, leading to the release of SiO₂ and the precipitation of authigenic quartz. Consequently, rigid frameworks supported by authigenic quartz are formed locally. During the middle diagenetic stages A₁-A₂, calcites and feldspars are dissolved by organic acids, contributing to increased pore sizes and improved reservoir properties. Afterward, during the middle diagenetic stages B₁-B₂, overpressured fluids sustain pores and induce microfractures, thereby connecting isolated pore throats. These four progressive stages, namely rigid framework building, pore support and enhancement, dissolution-induced porosity enhancement, and overpressure-preserved porosity, completely reveal the mechanisms behind the diagenetic evolution of reservoirs, pore development, and reservoir property enhancement for shales in the study area.

The expansion toward deep-to-ultra-deep oil and gas exploration is strategically vital for reserve growth and production addition in the Junggar Basin. Well Zheng 10 drilled in the Zhengshacun area in the hinterland of the Junggar Basin underscores the significant potential of the basin’s central part for ultra-deep oil and gas exploration. This study first presents the characteristics of hydrocarbon reservoirs in the area, emphasizing the elements of pertroleum system, such as source rocks, reservoirs, and migration pathways, that contribute to hydrocarbon accumulation. Accordingly, it identifies the determinants of hydrocarbon accumulation in the area and establishes the hydrocarbon accumulation mode. Furthermore, this study presents the implications of these factors for deep-to-ultra-deep oil and gas exploration in the area. The results reveal three major factors influencing the hydrocarbon accumulation therein: (1) A mechanism driven by low geothermal gradients and overpressure for hydrocarbon-generating evolution. This mechanism extends the oil window and elevates the transformation ratio, thereby significantly enriching hydrocarbon resources; (2) A four element (including low geothermal gradient, overpressure, chlorite coating, and zeolite dissolution) -controlled reservoir formation. This pattern redefines the lower depth limit for the development of conventional clastic reservoirs, thus broadening the scope for hydrocarbon exploration. (3) A migration mechanism governed by both faults and overpressure. This mechanism provides high-energy pathways for hydrocarbon migration and determines the vertical differential hydrocarbon migration, thus ensuring efficient hydrocarbon charging in ultra-deep reservoirs. By integrating superimposed factors including ultra-deep source rock evolution, pressure changes, tectonic shifts, diagenetic sequences, and hydrocarbon accumulation periods, we establish a hydrocarbon accumulation mode for the study area. This mode incorporates the temperature-pressure control over hydrocarbon-generating evolution, four element-controlled reservoir formation, and hydrocarbon migration governed by both faults and overpressure. This study aims to provide theoretical guidance and a scientific basis for new exploratory well emplacement and the delineation of potential new play fairways in the area.

Shales in the lower sub-member of the 3^rd member of the Paleogene Shahejie Formation (Es^3l section) in prolific shale-oil well BYP5 in the Jiyang Depression are of typical carbonate-rich type with high maturity. Research on their geological characteristics is of analogy and reference significance for the exploration of similar shales. We delve into the basic characteristics of these shales in terms of mineral composition, thin layer structure, hydrocarbon-generating condition, hydrocarbon fluid property, and reservoir space type. Based on the anomalies of geochemical parameters, we discuss the micro-migration adjustment and accumulation mechanism of shale oil, determine the lower limit of the oil saturation index (OSI), total organic carbon (TOC) content, and porosity for shale oil mobility. Therefore, the geological conditions favorable for high shale oil production are concluded. As revealed by this study, shales in the Es^3l section in well BYP5 is predominantly of carbonate-rich type, characterized by thin layer structure dominated by argillaceous and micritic calcite thin layers. With TOC content ranging from 0.58 % to 7.98 % (average: 4.52 %) and Type Ⅰ organic matter predominating, the shales in the study area are at the stage of light oil and condensate gas generation. With porosity between 2.2 % and 6.9 % (average: 3.22 %), the dominant storage spaces are matrix pores, followed by inter-layer and cross-cutting fractures. The lower limit of the shales’ OSI for oil prodution is less than 50 mg/g, while that of their TOC content and porosity for oil prodution is 1 % and 2.2 %, respectively. The geological conditions favorable for high shale oil production are as follows: (1) High organic matter abundance and high hydrocarbon-generating potential as a result serve to lay a solid material foundation for oil enrichment and flow; (2) High hydrocarbon mobility significantly reduces the lower limit of effective reservoir properties for hydrocarbon storage; (3) Abnormally high pressures provide sufficient natural energy for oil production; (4) The lamellar/layered structures of shales determine the high efficiency of hydrocarbon generation, storage, and permeability of the reservoir; (5) Multiple types of fractures like inter-layer and cross-cutting fractures can effectively connect matrix pores on both sides of the fractures, facilitating the oil recovery from the matrix pores.

Geochemical parameters serve as important indicators for shale oil enrichment and mobility evaluation. Using pyrolysis experiments of minerals/post-extraction shale residues mixed with oil/alkanes, as well as the comparison and forward modeling of pyrolysis parameters of oil-generating shales before and after shale extraction using organic reagents, we perform a case study of the oil-generating shales in the Bakken Formation of the Williston Basin and the Paleogene Shahejie Formation of the Jiyang Depression in the Bohai Bay Basin. Accordingly, the characteristics of shale oil enrichment and corresponding responses of geochemical parameters are analyzed to investigate the lower limits of the oil saturation index(OSI) and productivity index(PI) as indicators of shale oil enrichment and mobility. The results reveal that conventional Rock-Eval pyrolysis on oil in rock generates both free hydrocarbons(S₁) and pyrolyzed hydrocarbons (S₂), affecting the S₂ curve's peak style and peak temperature for hydrocarbon pyrolysis (T_max). Crude oil enrichment in shales, thereby, leads to anomalously high values of OSI and PI and anomalously low T_max values, with these three parameters in coordinated variation. Oil-rich shales with a low organic matter content exhibit more pronounced anomalies in pyrolysis parameters. In contrast, for organic-rich shales, their OSI and PI values tend to stabilize after the total organic carbon (TOC) content reaches a specific threshold. The liquid-solid interactions in shales affect the lower limits of indicators for hydrocarbon mobility. A systematic analysis of the Bakken Formation in one well in the Williston Basin and the Shahejie Formation in three wells in the Jiyang Depression indicates that the lower limits of OSI for the enriched shale oil and its mobility fall below 50 ~ 75 mg/g, corresponding to PI values of 0.12 ~ 0.20. The lower limit of OSI for the enriched shale oil and its mobility is closely associated with shale lithology and crude oil properties, with carbonate-rich shales exhibiting lower limits of OSI for shale oil mobility.