Formation Mechanism and Quantitative Evaluation of Deep to Ultra-Deep High-Quality Reservoirs

Topic Information

Dear Colleagues,

Major breakthroughs have been made in recent years in the exploration and development of deep/ultra deep oil–gas reservoirs (e.g., shale gas, coal bed methane, and carbonate reservoirs). These reservoirs, often characterized by complex geological structures, extreme conditions, and unique formation mechanisms, pose significant challenges to researchers and engineers alike. A better understanding of the formation mechanisms and accurately characterizing the properties of these reservoirs is crucial for efficient resource recovery and sustainable energy development. The understanding of the physical properties of deep reservoirs, pore structure, and fluid properties has been expanded by the application of new technologies, and research has made great progress from conventional to nano and pore scale, extending from low porosity and low permeability to ultra-low-permeability reservoirs. Thus, we can better understand the main controlling factors of high-quality reservoir formation and the mechanism of reservoir formation.

Therefore, we would like to announce a Topic on “Formation Mechanism and Quantitative Evaluation of Deep to Ultra-Deep High-Quality Reservoirs” to update the recent advances in the theories and methodologies of deep reservoir geology fundamentals and characterization. This issue will present a comprehensive collection of research articles and reviews that delve into the intricate aspects of reservoir geology and the methodologies employed for reservoir characterization. The articles in this issue cover a wide range of topics, including the structural and stratigraphic controls on deep reservoir quality; the role of diagenesis in reservoir evolution; the influence of organic–inorganic interaction on reservoir quality; the application of advanced geophysical and geochemical techniques for reservoir characterization; and the integration of geological experiments and geophysical and petrophysical data for reservoir modeling. The issue also explores the challenges and opportunities in reservoir characterization and modeling, such as the use of machine learning and artificial intelligence for improved high-quality reservoir prediction.

This issue highlights the significance of understanding the geological properties and behavior of reservoirs in the context of hydrocarbon exploration and production. It showcases the latest advancements in reservoir characterization techniques and their potential to enhance the efficiency and sustainability of hydrocarbon production.

In summary, this Topic provides a valuable resource for researchers, practitioners, and students in the field of reservoir geology and characterization, offering insights into the latest research trends, methodologies, and applications for better understanding and managing hydrocarbon reservoirs.

Dr. Jianhua He
Dr. Andrew D. La Croix
Prof. Dr. Jim Underschultz
Prof. Dr. Hucheng Deng
Dr. Hao Xu
Dr. Ruyue Wang
Dr. Rui Liu
Topic Editors

Keywords

Participating Journals

Journal Name	Impact Factor	CiteScore	Launched Year	First Decision (median)	APC
Applied Sciences applsci	2.5	5.3	2011	18.4 Days	CHF 2400	Submit
Energies energies	3.0	6.2	2008	16.8 Days	CHF 2600	Submit
Geosciences geosciences	2.4	5.3	2011	23.5 Days	CHF 1800	Submit
Journal of Marine Science and Engineering jmse	2.7	4.4	2013	16.4 Days	CHF 2600	Submit
Minerals minerals	2.2	4.1	2011	18 Days	CHF 2400	Submit

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Published Papers (7 papers)

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19 pages, 4412 KiB  

Open AccessArticle

Pore Structure and Its Controlling Factors of Cambrian Highly Over-Mature Marine Shales in the Upper Yangtze Block, SW China

by Dadong Liu, Mingyang Xu, Hui Chen, Yi Chen, Xia Feng, Zhenxue Jiang, Qingqing Fan, Li Liu and Wei Du

J. Mar. Sci. Eng. 2025, 13(5), 1002; https://doi.org/10.3390/jmse13051002 - 21 May 2025

Abstract

Highly over-mature marine shales are distributed worldwide with substantial resource potential, yet their pore structure characteristics and controlling mechanisms remain poorly understood, hindering accurate shale gas resource prediction and efficient development. This study focuses on the Cambrian Niutitang Formation shales in the Upper [...] Read more.

Highly over-mature marine shales are distributed worldwide with substantial resource potential, yet their pore structure characteristics and controlling mechanisms remain poorly understood, hindering accurate shale gas resource prediction and efficient development. This study focuses on the Cambrian Niutitang Formation shales in the Upper Yangtze region of South China. To decipher the multiscale pore network architecture and its genetic constraints, we employ scanning electron microscopy (SEM) pore extraction and fluid intrusion methods (CO₂ and N₂ adsorption, and high-pressure mercury intrusion porosimetry) to systematically characterize pore structures in these reservoirs. The results demonstrate that the shales exhibit high TOC contents (average 4.78%) and high thermal maturity (average Ro 3.64%). Three dominant pore types were identified: organic pores, intragranular pores, and intergranular pores. Organic pores are sparsely developed with diameters predominantly below 50 nm, displaying honeycomb, slit-like, or linear morphologies. Intragranular pores are primarily feldspar dissolution voids, while intergranular pores exhibit triangular or polygonal shapes with larger particle sizes. CO₂ adsorption isotherms (Type I) and low-temperature N₂ adsorption curves (H3-H4 hysteresis) indicate wedge-shaped and slit-like pores, with pore size distributions concentrated in the 0.5–50 nm range, showing strong heterogeneity. Pore structure shows weak correlations with TOC and quartz content but a strong correlation with feldspar abundance. This pattern arises from hydrocarbon generation exhaustion and graphitization-enhanced organic pore collapse under high compaction stress, which reduces pore preservation capacity. The aulacogen tectonic setting engenders proximal sediment provenance regimes that preferentially preserve labile minerals such as feldspars. This geological configuration establishes optimal diagenetic conditions for the subsequent development of meso- and macro-scale of dissolution pores. Our findings demonstrate that feldspar-rich shales, formed in a proximal depositional system with well-developed inorganic pores, serve as favorable reservoirs for the exploration of highly over-mature marine shale gas. Full article

(This article belongs to the Topic Formation Mechanism and Quantitative Evaluation of Deep to Ultra-Deep High-Quality Reservoirs)

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17 pages, 6045 KiB  

Open AccessArticle

Formation Mechanism of Granitic Basement Reservoir Linked to Felsic Minerals and Tectonic Stress in the Qiongdongnan Basin, South China Sea

by Qianwei Hu, Tengfei Zhou, Xiaohu He, Zhihong Chen, Youyuan Que, Anqing Chen and Wenbo Wang

Minerals 2025, 15(5), 457; https://doi.org/10.3390/min15050457 - 28 Apr 2025

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Abstract

Recent exploration efforts in the Qiongdongnan Basin have revealed hydrocarbon resources within granitic basement rocks in buried hill traps. However, the formation mechanisms and primary controlling factors of these reservoirs remain poorly understood. In this study, we utilized data from six wells in [...] Read more.

Recent exploration efforts in the Qiongdongnan Basin have revealed hydrocarbon resources within granitic basement rocks in buried hill traps. However, the formation mechanisms and primary controlling factors of these reservoirs remain poorly understood. In this study, we utilized data from six wells in the Qiongdongnan Basin, including sidewall cores, thin sections, imaging logging, and seismic reflection profiles, to analyze the petrological characteristics, pore systems, and fracture networks of the deep basement reservoir. The aim of our study was to elucidate the reservoir formation mechanisms and identify the key controlling factors. The results indicate that the basement lithology is predominantly granitoid, intruded during the late Permian to Triassic. These rocks are characterized by high felsic mineral content (exceeding 90% on average), with them possessing favorable brittleness and solubility properties. Fractures identified from sidewall cores and interpreted from image logging can be categorized into two main groups: (1) NE-SW trending conjugate shear fractures with sharp dip angles and (2) NW-SE trending conjugate shear fractures with sharp angles. An integrated analysis of regional tectonic stress fields suggests that the NE-trending fractures and associated faults were formed by compressional stresses related to the Indosinian closure of the ancient Tethys Ocean. In contrast, the NW-trending fractures and related faults resulted from southeast-directed compressional stresses during the Yanshanian subduction event. During the subsequent Cenozoic extensional phase, these fractures were reactivated, creating effective storage spaces for hydrocarbons. The presence of calcite and siliceous veins within the reservoir indicates the influence of meteoric water and magmatic–hydrothermal fluid activities. Meteoric water weathering exerted a depth-dependent dissolution effect on feldspathoid minerals, leading to the formation of fracture-related pores near the top of the buried hill trap during the Mesozoic exposure period. Consequently, the combination of high-density fractures and dissolution pores forms a vertically layered reservoir within the buried hill trap. The distribution of potential hydrocarbon targets in the granitic basement is closely linked to the surrounding tectonic framework. Full article

(This article belongs to the Topic Formation Mechanism and Quantitative Evaluation of Deep to Ultra-Deep High-Quality Reservoirs)

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15 pages, 2733 KiB  

Open AccessArticle

The Range and Evolution Model of the Xiang-E Submarine Uplifts at the Ordovician–Silurian Transition: Evidence from Black Shale Graptolites

by Zhi Zhou, Hui Zhou, Zhenxue Jiang, Shizhen Li, Shujing Bao and Guihong Xu

J. Mar. Sci. Eng. 2025, 13(4), 739; https://doi.org/10.3390/jmse13040739 - 8 Apr 2025

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Abstract

Accurately delineating the range of the Xiang-E submarine uplifts is the key to the exploration and development of Silurian shale gas in the Western Hunan–Hubei region. Based on the graptolite stratigraphic division of Well JD1 in Jianshi area, Hubei Province, and combined with [...] Read more.

Accurately delineating the range of the Xiang-E submarine uplifts is the key to the exploration and development of Silurian shale gas in the Western Hunan–Hubei region. Based on the graptolite stratigraphic division of Well JD1 in Jianshi area, Hubei Province, and combined with the GBDB online database (Geobiodiversity Database), the study compared the shale graptolite sequences of the Wufeng Formation and Longmaxi Formation from 23 profile points and 11 wells which cross the Ordovician–Silurian boundary. The range of the Xiang-E submarine uplift was delineated, and its evolution model and formation mechanism at the Ordovician–Silurian transition were discussed. The graptolite stratigraphic correlation results of drillings and profiles confirmed the development of submarine uplifts in the Western Hunan–Hubei region at the Ordovician–Silurian transition–Xiang-E submarine uplift. Under the joint control of the Guangxi movement and the global sea-level variation caused by the condensation and melting of polar glaciers, the overall evolution of the Xiang-E submarine uplift is characterized by continuous uplift from the Katian Age to the early Rhuddanian Age, with the influence gradually expanding, and then gradually shrinking back in the middle and late Rhuddanian Age. The initial form of the Xiang-E submarine uplift may have originated from the Guangxi movement, and the global sea-level variation caused by polar glacier condensation and melting is the main controlling factor for the changes in its influence range. Within the submarine uplifts range, the Wufeng–Longmaxi Formations generally lack at least two graptolite zone organic-rich shales in the WF2-LM4, and the shale gas reservoir has a poor hydrocarbon generation material foundation, posing a high risk for shale gas exploration. The Silurian in Xianfeng, Lichuan, Yichang of Hubei and Wushan of Chongqing has good potential for shale gas exploration and development. Full article

(This article belongs to the Topic Formation Mechanism and Quantitative Evaluation of Deep to Ultra-Deep High-Quality Reservoirs)

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29 pages, 12050 KiB  

Open AccessArticle

Quantitative Classification of Shale Lithofacies and Gas Enrichment in Deep-Marine Shale of the Late Ordovician Wufeng Formation and Early Silurian Longyi₁ Submember, Sichuan Basin, China

by Liyu Fang, Fanghao Xu, Guosheng Xu, Jiaxin Liu, Haoran Liang and Xin Gong

Energies 2025, 18(7), 1835; https://doi.org/10.3390/en18071835 - 4 Apr 2025

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Abstract

The classification of shale lithofacies, pore structure characteristics, and controlling factors of gas enrichment in deep-marine shale are critical for deep shale gas exploration and development. This study investigates the Late Ordovician Wufeng Formation (448–444 Ma) and Early Silurian Longyi₁ submember (444–440 [...] Read more.

The classification of shale lithofacies, pore structure characteristics, and controlling factors of gas enrichment in deep-marine shale are critical for deep shale gas exploration and development. This study investigates the Late Ordovician Wufeng Formation (448–444 Ma) and Early Silurian Longyi₁ submember (444–440 Ma) in the western Chongqing area, southern Sichuan Basin, China. Using experimental data from deep-marine shale samples, including total organic carbon (TOC) content analysis, X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), low-pressure N₂ and CO₂ adsorption, gas content measurement, and three-quartile statistical analysis, a lithofacies classification scheme for deep-marine shale was established. The differences between various global marine shale formations were compared, and the main controlling factors of gas enrichment and advantageous lithofacies for deep shale were identified. The results show that six main lithofacies were identified: organic-rich siliceous shale (S¹), organic-rich mixed shale (M¹), medium-organic siliceous shale (S²), medium-organic mixed shale (M²), organic-lean siliceous shale (S³), and organic-lean mixed shale (M³). Deep-marine shale gas mainly occurs in micropores, and the development degree of micropores determines the gas content. Micropore development is jointly controlled by the TOC content, felsic mineral content, and clay mineral content. TOC content directly controls the development degree of micropores, whereas the felsic and clay mineral contents control the preservation and destruction of micropores during deep burial. The large-scale productivity of siliceous organisms during the Late Ordovician Wufeng period to the Early Silurian Longmaxi period had an important influence on the formation of S¹. By comparing the pore structure parameters and gas contents of different lithofacies, it is concluded that S¹ should be the first choice for deep-marine shale gas exploration, followed by S². Full article

(This article belongs to the Topic Formation Mechanism and Quantitative Evaluation of Deep to Ultra-Deep High-Quality Reservoirs)

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17 pages, 3824 KiB  

Open AccessArticle

Machine Learning-Based Mineral Quantification from Lower Cambrian Shale in the Sichuan Basin: Implications for Reservoir Quality

by Xin Ye, Yan Liu, Tianyu Huang, Ting Chen, Chenglin Liu, Sibing Liu and Siding Jin

Minerals 2025, 15(3), 286; https://doi.org/10.3390/min15030286 - 12 Mar 2025

Viewed by 520

Abstract

In this study, cores from Well S1 in the Sichuan Basin were investigated to quantify mineral composition. A neural network analysis was employed to apply machine learning to X-ray fluorescence (XRF) datasets for predicting the mineralogical characteristics of Well S1. A total of [...] Read more.

In this study, cores from Well S1 in the Sichuan Basin were investigated to quantify mineral composition. A neural network analysis was employed to apply machine learning to X-ray fluorescence (XRF) datasets for predicting the mineralogical characteristics of Well S1. A total of 77 sample points were divided into training, validation, and test sets at a ratio of 6:2:2. After training and fine-tuning the model using the training and validation sets, the performance of the neural network model was evaluated with the test set. The best result was achieved for calcite prediction, reaching an R-squared (R²) value of 95%. Predictions for the seven minerals, except quartz, all exhibited R² values of 80% or higher. Quantitative laboratory-measured X-ray diffraction (XRD) mineralogy was used for training to develop a high-resolution semi-quantitative model, and the resulting mineralogical model shows promising potential. The modeled mineralogy represents continuous relative abundance, which provides more meaningful insights compared to discrete single-point XRD measurements. The significance of this research lies in its ability to utilize relatively inexpensive and non-destructive XRF logging analysis, requiring minimal sample preparation, to construct high-resolution mineral abundance profiles. With modern technological advancements, operators can adopt the proposed method to build semi-quantitative mineralogical models for evaluating potential lateral drilling intervals and designing completion strategies accordingly. Full article

(This article belongs to the Topic Formation Mechanism and Quantitative Evaluation of Deep to Ultra-Deep High-Quality Reservoirs)

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21 pages, 6342 KiB  

Open AccessArticle

Characteristics of Fluid Inclusions and Hydrocarbon Accumulation Stages of Carbonate Rock Reservoir: A Case Study from the Majiagou Formation Ordovician, Central and Eastern Ordos Basin

by Yanzhao Liu, Zhanli Ren, Kai Qi, Xinyun Yan, Beile Xiong, Jian Liu, Junfeng Ren, Guangyuan Xing, Mingxing Jia, Juwen Yao and Hongwei Tian

Minerals 2025, 15(2), 139; https://doi.org/10.3390/min15020139 - 30 Jan 2025

Viewed by 735

Abstract

The Ordovician carbonate formations in the Ordos Basin provide a crucial stratigraphic unit for prospective oil and gas exploration. Significant progress has been made in the exploration of natural gas within the Ordovician subsalt formations. Nonetheless, understanding its accumulating properties requires additional investigation. [...] Read more.

The Ordovician carbonate formations in the Ordos Basin provide a crucial stratigraphic unit for prospective oil and gas exploration. Significant progress has been made in the exploration of natural gas within the Ordovician subsalt formations. Nonetheless, understanding its accumulating properties requires additional investigation. Clarifying the formation periods of the carbonate rock reservoirs in the Majiagou Formation of the basin can furnish a theoretical foundation for advanced exploration of carbonate rock oil and gas. This study uses fluid inclusion petrography, laser Raman spectroscopy, and microscopic temperature measurement methods, along with information about the basin’s history of burial and thermal evolution, to look at the oil and gas charging periods of Majiagou Formation reservoir in the central-eastern basin. The results show that there are two stages of hydrocarbon inclusions. The first stage has blue fluorescence and temperature peaks between 85 and 95 °C in the central basin and between 105 and 115 °C in the eastern basin. For the second stage, no fluorescence can be observed. Meanwhile, the temperature peaks are between 175 and 185 °C in the central basin, and between 165 and 175 °C in the eastern basin. In the central part of the basin, oil charging began in the Late Triassic (231–203 Ma) and reached the gas generation stage in the Late Early Cretaceous (121–112 Ma), peaking in natural gas charging. In contrast, the reservoirs in the eastern part of the basin experienced a primary oil charging stage in the Early Jurassic (196–164 Ma) and entered the gas generation stage in the Late Early Cretaceous (110–101 Ma). The hydrocarbon charging process in the study area is mainly controlled by the thermal evolution history of the basin. The study determines that the central basin enters the threshold of hydrocarbon generation earlier than the eastern basin, leading to earlier oil and gas charging. Full article

(This article belongs to the Topic Formation Mechanism and Quantitative Evaluation of Deep to Ultra-Deep High-Quality Reservoirs)

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21 pages, 5790 KiB  

Open AccessArticle

Sealing Effects on Organic Pore Development in Marine Shale Gas: New Insights from Macro- to Micro-Scale Analyses

by Qiumei Zhou, Hao Xu, Wen Zhou, Xin Zhao, Ruiyin Liu and Ke Jiang

Energies 2025, 18(1), 193; https://doi.org/10.3390/en18010193 - 5 Jan 2025

Viewed by 668

Abstract

The physics of how organic pores change under high thermal evolution conditions in overmature marine shale gas formations remains unclear. In this study, systematic analyses at the macro- to micro-scales were performed to reveal the effects of the sealing capacity on organic pore [...] Read more.

The physics of how organic pores change under high thermal evolution conditions in overmature marine shale gas formations remains unclear. In this study, systematic analyses at the macro- to micro-scales were performed to reveal the effects of the sealing capacity on organic pore development. Pyrolysis experiments were conducted in semi-closed and open systems which provided solid evidence demonstrating the importance of the sealing capacity. Low-maturity marine shale samples from the Dalong Formation were used in the pyrolysis experiments, which were conducted at 350 °C, 400 °C, 450 °C, 500 °C, 550 °C, and 600 °C. The pore characteristics and geochemical parameters of the samples were examined after each thermal simulation stage. The results showed that the TOC of the semi-closed system decreased gradually, while the TOC of the open system decreased sharply at 350 °C and exhibited almost no change thereafter. The maximum porosity, specific surface area, and pore volume of the semi-closed system (10.35%, 2.99 m²/g, and 0.0153 cm³/g) were larger than those of the open system (3.87%, 1.97 m²/g, and 0.0059 cm³/g). In addition, when the temperature was 600 °C, the pore diameter distribution in the open system was 0.001–0.1 μm, while the pore diameter distribution in the semi-closed system was 0.001–10 μm. The pore volumes of the macropores and mesopores in the semi-closed system remained larger than those in the open system. The pore volumes of the micropores in the semi-closed and open systems were similar. The pyrolysis results indicated that (1) the pressure difference caused by the sealing capacity controls organic pore development; (2) organic pores developed in the semi-closed system, and the differences between the two systems mainly occurred in the overmature stage; and (3) the differences were caused by changes in the macropore and mesopore volumes, not the micropore volume. It was concluded that the sealing capacity is the key factor for gas pore generation in the overmature stage of marine shale gas reservoirs when the organic matter (OM) type, volume, and thermal evolution degree are all similar. The macropores and mesopores are easily affected by the sealing conditions, but the micropores are not. Finally, the pyrolysis simulation results were validated with the Longmaxi shale and Qiongzhusi shale properties. The Longmaxi shale is similar to semi-closed system, and the Qiongzhusi shale is similar to open system. Two thermal evolution patterns of organic pore development were proposed based on the pyrolysis results. This study provides new insights into the evolution patterns of organic pores in marine shale gas reservoirs. Full article

(This article belongs to the Topic Formation Mechanism and Quantitative Evaluation of Deep to Ultra-Deep High-Quality Reservoirs)

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