Reservoir Characteristics and Evolution Mechanisms of the Shale, 2nd Edition

Topic Information

Dear Colleagues,

Over the past two decades, with the development and application of horizontal drilling and hydraulic stimulation, oil and gas production from shale with disparate depositional environments has increased rapidly in many countries (e.g., North America and China). Advanced evaluation theories and development techniques have been well established and tested in laboratories and applications in various fields. However, in the face of the general phenomenon of low productivity and rapid decline in oil/gas production, there are still numerous scientific issues implicating the sustainable development of these unconventional resources, including the quantitative characterization of reservoirs, hydrocarbon occurrence, reservoir evolution mechanisms, and reservoir evaluation methods/technologies. The practice of exploration and development shows that factors such as lithofacies and lithofacies combinations, mineral composition and structure, burial depth, formation pressure, and wettability have significant impacts on the formation and evolution of shale reservoirs, the types and characteristics of reservoir spaces, oil and gas occurrence, fracturing potential, and productivity, etc. Therefore, we would like to announce a Topic on “Reservoir Characteristics and Evolution Mechanisms of the shale” to present the up-to-date advances in the theories and methodologies of reservoir characteristics and evolution mechanisms of shale in an attempt to improve our fundamental understanding, in order to enhance our basic understanding, reveal the mechanisms of shale oil and gas occurrence and enrichment, and achieve sustainable oil and gas development with high single well productivity and low cost. Original research and review articles are welcome.

Dr. Ruyue Wang
Prof. Dr. Mengdi Sun
Prof. Dr. Shang Xu
Dr. Jianhua He
Dr. Cunhui Fan
Prof. Dr. Rui Yang
Dr. Chao Liang
Dr. Yahao Huang
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Participating Journals

Journal Name	Impact Factor	CiteScore	Launched Year	First Decision (median)	APC
Energies energies	3.9	8.3	2008	16.7 Days	CHF 2600	Submit
Eng eng	3.5	4.1	2020	18.8 Days	CHF 1400	Submit
Geosciences geosciences	2.3	4.4	2011	22.7 Days	CHF 1800	Submit
Journal of Marine Science and Engineering jmse	3.2	5.6	2013	15 Days	CHF 2600	Submit
Minerals minerals	2.7	4.9	2011	17 Days	CHF 2400	Submit

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All Energies Minerals Geosciences JMSE Eng

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20 pages, 14687 KB  

Open AccessArticle

Stress-Dependent Permeability of Artificially Fractured Siliceous Rocks from Southern Sakhalin

by Mikhail S. Turbakov, Alexander A. Shcherbakov, Evgenii P. Riabokon, Zakhar G. Ivanov, Pavel A. Kamenev, Konstantin P. Kazymov, Elena M. Tomilina, Miroslav A. Pshevlodskii, Yuliia S. Shcherbakova and Evgenii V. Kozhevnikov

Geosciences 2026, 16(9), 358; https://doi.org/10.3390/geosciences16090358 - 7 Sep 2026

Viewed by 212

Abstract

Large hydrocarbon fields are being developed in northern Sakhalin, whereas southern Sakhalin contains prospective resources hosted in unconventional, low-permeability siliceous source rocks. Their development requires stimulation to create conductive fracture networks, whose long-term integrity is critical for production feasibility. This study investigates permeability [...] Read more.

Large hydrocarbon fields are being developed in northern Sakhalin, whereas southern Sakhalin contains prospective resources hosted in unconventional, low-permeability siliceous source rocks. Their development requires stimulation to create conductive fracture networks, whose long-term integrity is critical for production feasibility. This study investigates permeability changes in four artificially fractured specimens subjected to cyclic confining pressure; the specimens are treated as case studies rather than as a statistically representative formation-scale data set. Cylindrical cores, 30 mm in diameter and approximately 30 mm long, containing an induced axial fracture were hydraulically tested under biaxial cyclic confinement. The tests showed irreversible loss of fracture conductivity, with residual permeability after unloading amounting to 7.1–37.4% of the initial value. Direct application of laboratory data to field scale fracture longevity models is inappropriate because cylindrical specimens develop nonuniform circumferential stresses and heterogeneous closure. A procedure is proposed to transfer core scale measurements to a planar fracture subjected to uniform normal stress in the rock mass. Fracture aperture was quantified by X-ray computed tomography (CT) and incorporated into a cell-based contact–hydraulic model accounting for geometric and hydraulic aperture. A nonuniform closure function was used to reconstruct the closure field and correct the laboratory results. At maximum pressure, Kmass/Klab ranged from 0.034 to 0.93 for the three specimens reproduced with acceptable fit; sample 3–4 was retained only as a diagnostic case because of its high root-mean-square error (RMSE). These values are model-based single-fracture scenario estimates pending direct-normal-loading validation. Full article

(This article belongs to the Topic Reservoir Characteristics and Evolution Mechanisms of the Shale, 2nd Edition)

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23 pages, 15439 KB  

Open AccessArticle

Pore Development Characteristics of Shales in the Dalong Formation, Western Hubei, Under the Coupled Control of Authigenic Quartz–Clay Minerals–Organic Matter

by Xing Niu, Yin Gong and Yan Ling

Minerals 2026, 16(5), 546; https://doi.org/10.3390/min16050546 - 19 May 2026

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Abstract

The upper Permian Dalong Formation in western Hubei Province is a crucial strategic successor for shale gas development in South China. However, the geological controls on reservoir pore development, particularly the influence of organic–inorganic interactions on the pore system, remain poorly understood. This [...] Read more.

The upper Permian Dalong Formation in western Hubei Province is a crucial strategic successor for shale gas development in South China. However, the geological controls on reservoir pore development, particularly the influence of organic–inorganic interactions on the pore system, remain poorly understood. This restricts the precise optimization of shale gas exploration targets in this formation. To investigate the pore development characteristics and main controlling factors of the Dalong Formation shale reservoirs, this study takes the DFS from the Shuanghe section in western Hubei as the research object. X-ray diffraction (XRD), argon-ion polishing-scanning electron microscopy (SEM), and N₂/CO₂ gas adsorption–desorption technologies were integrated to achieve qualitative characterization and quantitative assessment of the pore network, with analyses of pore size distribution. The results show that the pores of the DFSs are dominated by interparticle pores and organic matter pores, and the pore structures of organic-rich and organic-lean shales exhibit significant differentiation characteristics. The quartz in the DFSs are mainly of diagenetic origin, and authigenic quartz cementation blocks primary intergranular pores, exerting a significant negative effect on pore development. In contrast, the smectite-to-illite transformation promotes the development of interlayer micropores, leading to a good positive correlation between clay mineral content and micropore volume, as well as specific surface area. Organic matter abundance is the core controlling factor for the construction of micro–nano pore networks. This study clarifies the dominant mechanisms of pore development driven by organic–inorganic interactions in the DFS. Authigenic diagenetic quartz impedes pore development, while smectite-to-illite transformation promotes micropore formation. Organic matter abundance is the dominant control on the micro-nanopore system. This study lays a critical geological theoretical foundation for the exploration evaluation and target selection of shale gas in the Dalong Formation. Full article

(This article belongs to the Topic Reservoir Characteristics and Evolution Mechanisms of the Shale, 2nd Edition)

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19 pages, 16712 KB  

Open AccessArticle

Petrological and Geochemical Characteristics of the Lower Cambrian Shuijingtuo Formation in the Middle Yangtze Block, South China: Implications for Organic Matter Accumulation on Carbonate Platform

by Baomin Zhang, Quansheng Cai, Guotao Zhang, Oumar Ibrahima Kane, Lin Chen, An Liu, Peng Zhou and Ruyue Wang

J. Mar. Sci. Eng. 2026, 14(9), 762; https://doi.org/10.3390/jmse14090762 - 22 Apr 2026

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Abstract

Understanding the development characteristics and controlling factors of organic-rich shales in carbonate platform settings is essential for predicting their distribution and assessing their natural gas exploration potential. However, the mechanisms governing the accumulation of such shales in these specific sedimentary environments remain poorly [...] Read more.

Understanding the development characteristics and controlling factors of organic-rich shales in carbonate platform settings is essential for predicting their distribution and assessing their natural gas exploration potential. However, the mechanisms governing the accumulation of such shales in these specific sedimentary environments remain poorly constrained, and the lack of integrated petrological and geochemical studies limits accurate evaluation of their resource potential. The key objective of this study is to investigate the development characteristics and formation mechanisms of organic-rich shales within intraplatform depressions. To address this objective, we conducted a comprehensive petrological and geochemical analysis of the Cambrian Shuijingtuo Formation organic-rich shale deposits deposited in a carbonate platform setting, particularly from Well EYY3 in Western Hubei, Central Yangtze region. The obtained results indicate that total organic carbon (TOC) contents in the Shuijingtuo Formation can reach up to 4.77%, with a thickness of approximately 9.5 m for shales containing over 2% TOC. Vertically, TOC content exhibits a rapid increase at the base, followed by a gradual decline toward the top, reflecting the evolution of depositional environments. The characteristics of organic-rich shale indicate a significant presence of carbonate minerals, which increase in concentration, alongside tuff lenticular bodies and lithological transition surfaces between tuff and shale. While the longitudinal variation of SiO₂ content in shale is subtle, there is a slight increase in land-sourced clasts and excess silica, and TOC has a significant positive correlation. At the base of the Shuijingtuo Formation, redox parameters, including U-EF and Mo-EF, display a rapid increase followed by a gradual decrease. Conversely, changes in Ni-EF, which indicate paleoproductivity, are less pronounced, and their correlation with TOC is relatively poor. These findings suggest that rapid sea-level rise associated with Cambrian transgressions was the main factor influencing organic matter enrichment in the carbonate platform depressions. This rise supplied nutrients and silica-rich organisms, altering the biological landscape and fostering anoxic conditions in the intraplatform depressions, promoting organic-rich shale formation. As sea levels declined, water circulation became restricted, leading to oxidation of shallow water bodies, decreased paleoproductivity, and shale deposits transitioned to tuff. Therefore, organic-rich shale can also be developed on carbonate platforms, with its formation primarily controlled by fluctuations in sea level. During highstand periods, intraplatform depressions may serve as favorable zones for shale gas exploration. Full article

(This article belongs to the Topic Reservoir Characteristics and Evolution Mechanisms of the Shale, 2nd Edition)

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11 pages, 6346 KB  

Open AccessArticle

The Anisotropic Permeability Insights of Nano-Scale Pore Networks Evolution in the Overmature Shales

by Yanshuai Tang, Tianguo Tang, Xiaohang Bao, Xiujiang Fan and Lei Zhou

Minerals 2026, 16(3), 315; https://doi.org/10.3390/min16030315 - 17 Mar 2026

Viewed by 452

Abstract

Permeability is affected by nanopores and pore structure, and anisotropic permeability is the result of shale lamination, orientation, and stratification of minerals. To understand the reasons for permeability anisotropy, the pore networks of over-mature shale has been studied. The mineral compositions, petrophysical properties, [...] Read more.

Permeability is affected by nanopores and pore structure, and anisotropic permeability is the result of shale lamination, orientation, and stratification of minerals. To understand the reasons for permeability anisotropy, the pore networks of over-mature shale has been studied. The mineral compositions, petrophysical properties, and pore structures of the Lower Cambrian Niutitang Formation shales were analyzed using subcritical gas adsorption, field-emission scanning electron microscopic, and X-ray micro-computed tomographic methods. Quartz, clay minerals, and carbonate are the dominant minerals in the shales. The bedding-parallel and bedding-perpendicular permeabilities are 1.25–46.21 × 10⁻² and 1.38–6.62 × 10⁻² mD, respectively. The anisotropy of permeability, which is the ratio between the bedding-parallel and bedding-perpendicular permeability, is 0.21–26.87. The micropore and Barrett–Joyner–Halenda pore volumes are 0.54–3.62 and 0.05–0.69 mL/100 g, respectively. The bedding-parallel permeability is correlated positively with the micropore and Barrett–Joyner–Halenda pore volumes. Thin-section observations indicate the shales exhibit a bedding-parallel alignment of phyllosilicate minerals and planar deformation bands. The scanning electron microscopy shows deformation of the lamination and parallel alignment of the clay minerals due to compaction or differential compaction over coarser-grained quartz grains. The scanning electron microscopy images and subcritical gas adsorption data indicate that the pore fracture system is parallel to bedding and formed after diagenesis. Furthermore, X-ray micro-computed tomographic analysis shows that the micro-fractures are also preferentially oriented, parallel to bedding. Full article

(This article belongs to the Topic Reservoir Characteristics and Evolution Mechanisms of the Shale, 2nd Edition)

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