Advances in Integrated Geological, Mineralogical, and Engineering Research on Unconventional Oil and Gas

Topic Information

Dear Colleagues,

The efficient development of unconventional hydrocarbon resources critically depends on closely integrating geological understanding and engineering practices. This Topic aims to showcase cutting-edge research and innovative methodologies that bridge this gap, enhancing recovery and optimizing operations.

We invite contributions addressing advances in geology–engineering integration. Topics of interest include, but are not limited to, the following:

1. Geological Fundamentals and Resource Evaluation​:

• Geological controls on hydrocarbon generation, migration, and accumulation in unconventional reservoirs (e.g., lithofacies heterogeneity, fracture networks, and fluid–rock interactions)​;

• Sweet-spot identification and prediction: Integrating seismic, logging, core analysis, and geomechanical data​;

• Reservoir quality assessment and geological modeling for unconventional plays (shale, tight formations, coal seams, gas hydrate-bearing sediments)​;

• Geochemical characterization and resource potential evaluation of unconventional hydrocarbons​.

2. Reservoir Characterization and Petrophysical Analysis​:

• Advanced petrophysical evaluation techniques for low-permeability, multi-mineral unconventional reservoirs​;

• Fracture characterization: Microseismic monitoring, image logging, core imaging, and numerical simulation of fracture networks​;

• Fluid behavior in unconventional reservoirs (adsorption/desorption, diffusion, flow in nano/micro-pores)​;

• Geomechanical modeling and its integration with reservoir characterization (stress distribution, rock mechanical properties, and fracture propagation potential)​.

3. Drilling and Completion Engineering Innovations​:

• Optimized drilling technologies for unconventional plays: Horizontal drilling, extended-reach drilling, and ultra-deep drilling​;

• Novel completion designs: Multi-stage fracturing, sliding sleeve completion, and intelligent completion systems​;

• Drilling fluid and completion fluid technologies for minimizing formation damage in unconventional reservoirs​;

• Cost-effective drilling and completion strategies for low-quality unconventional resources​.

4. Hydraulic Fracturing and Reservoir Stimulation​:

• Advanced hydraulic fracturing techniques: Refracturing, foam fracturing, slickwater fracturing, and proppant selection optimization​;

• Numerical simulation and optimization of hydraulic fracturing (fracture geometry, proppant transport, and stimulation efficiency)​;

• Reservoir stimulation beyond hydraulic fracturing: Chemical stimulation, thermal stimulation, and microbial stimulation for unconventional resources​;

• Environmental considerations in fracturing operations: Water management, chemical additive safety, and carbon footprint reduction​.

5. Production Optimization and Enhanced Recovery​:

• Production performance analysis and prediction for unconventional reservoirs (decline curve analysis, numerical simulation, and data-driven modeling)​;

• Enhanced oil/gas recovery (EOR/EGR) technologies for unconventional plays: Gas injection, chemical flooding, and thermal recovery​;

• Smart production technologies: Real-time monitoring, data analytics, and machine learning applications for production optimization​;

• Integrated reservoir management: Coupling geological updates, engineering adjustments, and production performance feedback.​

6. Cross-Disciplinary Integration and Emerging Technologies​:

• Machine learning, artificial intelligence, and big data analytics in geology–engineering integration for unconventional resources​;

• Digital twin technology for unconventional reservoir development (virtual reservoir modeling, real-time operation optimization)​;

• Multi-physics coupling simulation (geology, geomechanics, fluid flow, and engineering operations)​;

• Environmental and sustainability aspects of unconventional hydrocarbon development (carbon capture, utilization, and storage (CCUS) integration, and ecological protection).​

We welcome original research and review articles. Manuscripts should be submitted online via the journal's submission system.

We look forward to receiving your valuable contributions.

Prof. Dr. Shu Tao
Dr. Shida Chen
Dr. Zhengguang Zhang
Dr. Yu Song
Dr. Qiong Wang
Topic Editors

Keywords

Participating Journals

Journal Name	Impact Factor	CiteScore	Launched Year	First Decision (median)	APC
Applied Sciences applsci	2.5	5.5	2011	16 Days	CHF 2400	Submit
Energies energies	3.2	7.3	2008	16.8 Days	CHF 2600	Submit
Minerals minerals	2.2	4.4	2011	17.7 Days	CHF 2400	Submit
Processes processes	2.8	5.5	2013	14.9 Days	CHF 2400	Submit
Sci sci	-	5.2	2019	26.7 Days	CHF 1400	Submit

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Published Papers (8 papers)

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14 pages, 3707 KB  

Open AccessArticle

Early Cambrian Hydrothermal Activity in Southern Anhui, South China: Evidence and Geochemical Implications

by Lei Huang, Yufei Liang, Anna Tong, Haijiang Zhao, Hezheng Dong, Xiaowei Huang and Dongsheng Zhou

Minerals 2026, 16(5), 525; https://doi.org/10.3390/min16050525 (registering DOI) - 14 May 2026

Abstract

Hydrothermal activity plays a critical role in ancient oceanic environments, organic matter accumulation, and metallic ore deposit formation. During the Early Cambrian, the development of hydrothermal systems in the southern Anhui Province of the Lower Yangtze Block has long attracted geological attention. This [...] Read more.

Hydrothermal activity plays a critical role in ancient oceanic environments, organic matter accumulation, and metallic ore deposit formation. During the Early Cambrian, the development of hydrothermal systems in the southern Anhui Province of the Lower Yangtze Block has long attracted geological attention. This study focuses on the Lower Cambrian black shales of the Hongtaocun (HTC) section in the southern Anhui Province, employing major- and trace-element analyses, rare earth element (REE) geochemistry, and field-emission scanning electron microscopy (FE-SEM) observations to identify evidence for Early Cambrian hydrothermal activity on the Yangtze Platform and its controls on mineralization. Our results demonstrate that major-element proxies classify the HTC samples as biogenic, but this classification is demonstrably incorrect given the mineralogical and REE evidence, which highlights the limitations of major-element discrimination alone. Hyalophane (Hy) occurrence records Ba-rich hydrothermal fluids, while positive Eu anomalies in the REE patterns further corroborate hydrothermal influence. We, therefore, emphasize that major-element chemistry alone is insufficient to reliably identify hydrothermal processes. These findings substantially advance the discrimination criteria for ancient seafloor hydrothermal activity. Full article

(This article belongs to the Topic Advances in Integrated Geological, Mineralogical, and Engineering Research on Unconventional Oil and Gas)

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22 pages, 3171 KB  

Open AccessArticle

Research on In Situ Gas Resource Characteristics in the Xinzhuangzi Closed Coal Mine, Huainan Mining Area, Anhui Province, China

by Zhigen Zhao, Aozhong Li, Jiajie Zhang and Mo Chen

Appl. Sci. 2026, 16(9), 4502; https://doi.org/10.3390/app16094502 - 3 May 2026

Viewed by 190

Abstract

China hosts a large number of closed coal mines containing abundant residual resources. Driven by resource recycling, mine safety, environmental protection, and the dual-carbon goals, research on gas resources in closed coal mines has expanded rapidly. In some closed mines, substantial unmined coal [...] Read more.

China hosts a large number of closed coal mines containing abundant residual resources. Driven by resource recycling, mine safety, environmental protection, and the dual-carbon goals, research on gas resources in closed coal mines has expanded rapidly. In some closed mines, substantial unmined coal resources remain with high gas content, making in situ gas resources a key focus of investigation. Given the Xinzhuangzi closed coal mine as a case study, this study analyzed the distribution of coal resources based on the monitoring results of coal extraction and remaining reserves, and the distribution of gas content based on regression equation. Furthermore, it applied a volumetric calculation method to estimate the gas resources of any a certain unit, all units, and summarize the gas resources across different coal seams, structural divisions, mining levels and the entire coal mine, thereby characterizing the in situ gas resources. The results indicated that the area below −412 m in the closed Xinzhuangzi coal mine was favorable for in situ gas resource development, containing 20,061.1 × 10⁴ t of coal resource and 2250.32 × 10⁶ m³ of gas resources, with a gas resource abundance of 1.96 × 10⁸ m³/km². C13, B11b, B4, B7a, B6, and B8 were favorable targets for in situ gas resources, each containing over 100 × 10⁶ m³ of gas resources, and these seams were thick and stable. Levels 6 and 7 were favorable zones for in situ gas resources, each containing abundant coal resources with high gas content, holding 644.94 × 10⁶ and 1407.77 × 10⁶ m³ of gas resources, respectively. These findings provided not only a scientific basis for the future evaluation and development of gas resources in this coal mine, but also important references for the study of in situ gas resources in other abandoned mines. And, several suggestions were given about the development prospects of gas resources. Full article

(This article belongs to the Topic Advances in Integrated Geological, Mineralogical, and Engineering Research on Unconventional Oil and Gas)

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22 pages, 16192 KB  

Open AccessArticle

Pore Permeability Cycling Characteristics of Coal-Bearing Strata in the Agong Syncline, Western Guizhou, South China: Implications for Superposed Gas Systems

by Lingling Lu, Chen Guo, Chao Deng and Yan Ji

Appl. Sci. 2026, 16(9), 4178; https://doi.org/10.3390/app16094178 - 24 Apr 2026

Viewed by 166

Abstract

The Late Permian coal-bearing strata in western Guizhou Province, South China, are developed with multiple coal seams and rich in coalbed methane (CBM) resources. Controlled by the sealing layers within the coal-bearing strata, multiple vertically superposed independent CBM systems were formed, which complicates [...] Read more.

The Late Permian coal-bearing strata in western Guizhou Province, South China, are developed with multiple coal seams and rich in coalbed methane (CBM) resources. Controlled by the sealing layers within the coal-bearing strata, multiple vertically superposed independent CBM systems were formed, which complicates the CBM accumulation characteristics and limits CBM development. Through systematic sampling of the main coal seams and different lithologic strata in Borehole 101 on the southeastern limb of the Agong Syncline in western Guizhou, mercury intrusion porosimetry (MIP) and Klinkenberg permeability experiments were conducted on coal and rock samples. The results show that the coal samples have an average pore volume of 0.0417 mL/g, an average porosity of 5.37%, an average mercury withdrawal efficiency of 69.79%, and an average well test permeability of 0.3743 mD; the rock samples have an average pore volume of 0.0064 mL/g, an average porosity of 1.43%, an average mercury withdrawal efficiency of 7.88%, and an average Klinkenberg permeability of 0.0128 mD. The pore and permeability conditions of rock layers are significantly poorer than those of coal seams, which favorably contributes to the formation of effective sealing layers between coal seams and facilitates the CBM preservation. Mudstone and argillaceous siltstone in the coal-bearing strata, characterized by their low porosity and permeability, are suitable as effective gas and water barriers between coal seams. Based on a comprehensive analysis of the vertical variations in permeability, porosity, and gas-bearing characteristics of Borehole 101, the Upper Permian coal-bearing strata are preliminarily divided into four independent CBM-bearing systems. These systems are separated by tight rock layers with extremely low permeability and porosity, and their division aligns closely with the third-order sequence stratigraphic framework. The findings can provide a theoretical basis for deepening the understanding of CBM accumulation mechanisms in multi-seam regions and optimizing the orderly CBM development models. Full article

(This article belongs to the Topic Advances in Integrated Geological, Mineralogical, and Engineering Research on Unconventional Oil and Gas)

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30 pages, 68906 KB  

Open AccessArticle

Fracture Development in Alkaline Lacustrine Shales: Insights from Multi-Stage Fluid–Rock Interactions in the Permian Fengcheng Formation, Mahu Sag, Junggar Basin

by Kuan Lu, Jiakai Hou, Zhenkai Huang, Guangyou Zhu, Jianyong Liu, Jiangna Fu and Heting Gao

Minerals 2026, 16(4), 430; https://doi.org/10.3390/min16040430 - 21 Apr 2026

Viewed by 279

Abstract

The Mahu Sag, a hydrocarbon-rich depression within the Junggar Basin, hosts significant petroleum resources. Here, the Permian Fengcheng Formation shale oil reservoirs have emerged as a primary exploration target. This study investigates fracture development within these alkaline lacustrine shales, a critical factor governing [...] Read more.

The Mahu Sag, a hydrocarbon-rich depression within the Junggar Basin, hosts significant petroleum resources. Here, the Permian Fengcheng Formation shale oil reservoirs have emerged as a primary exploration target. This study investigates fracture development within these alkaline lacustrine shales, a critical factor governing hydrocarbon migration and accumulation. Through integrated petrographic and geochemical analyses, we elucidate a multifactorial fracture formation mechanism driven by the interplay of alkaline minerals, stress, and fluids. Two distinct fracture types were identified: bedding-complex fracture veins (BCFVs) and Y-shaped high-angle fracture veins (Y-HFVs). Both fracture types result from alkaline fluid–rock interactions, which induce fracture opening along specific orientations, alter fracture angles, and control aperture width and final morphology. Alkaline mineral assemblages further influence fracture evolution via dissolution–precipitation cycles. Concurrently, these assemblages preserve hydrocarbons by inhibiting the thermal maturation of organic matter, as evidenced by variations in fluid inclusion fluorescence. The fracture networks act as crucial migration pathways, with the BCFV containing higher-maturity hydrocarbons (indicated by blue-green fluorescence) and the Y-HFV retaining less mature fluids (indicated by yellow-green fluorescence). This study presents the first systematic characterization of the multifactorial controls on fractures in alkaline lake environments, proposing a cooperative “alkaline minerals–stress–fluids” mechanism. These findings provide a new framework for understanding fracture development in alkaline lacustrine shales and offer valuable insights for shale oil exploration in analogous depositional settings. Full article

(This article belongs to the Topic Advances in Integrated Geological, Mineralogical, and Engineering Research on Unconventional Oil and Gas)

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15 pages, 1727 KB  

Open AccessArticle

Mathematical Model Establishment for the Multi-Scale Permeability of Coal Reservoirs and Its Engineering Significance

by Zhigang Du, Feilong Xiong, Yingying Li, Guiyang Ren, Jianggen He, Yongyan Yan, Qi Liu and Hongyang Bai

Energies 2026, 19(8), 2006; https://doi.org/10.3390/en19082006 - 21 Apr 2026

Viewed by 236

Abstract

Permeability is a critical parameter governing the gas flow behavior of the coalbed methane (CBM) reservoir during the exploration and exploitation of CBM, as well as the geological storage of CO₂ in the coalbeds. It is strongly associated with the multi-scale fractures [...] Read more.

Permeability is a critical parameter governing the gas flow behavior of the coalbed methane (CBM) reservoir during the exploration and exploitation of CBM, as well as the geological storage of CO₂ in the coalbeds. It is strongly associated with the multi-scale fractures developed in coal. Based on the distribution characteristics of micro-fractures, a multi-scale permeability model for coal reservoirs was established by introducing the permeability tensor, which comprehensively considers adsorption-induced coal swelling, pore pressure, effective stress, and micro-fractures. Further, the dynamic evolution law and mechanism of multi-scale permeability of coal reservoirs under different adsorption pressures were discussed. The results indicate that the increase in effective stress on the coal caused by adsorption-induced swelling essentially leads to a decrease in the equivalent multi-scale permeability of coal. Two key indicators, namely equilibrium pressure and rebound pressure, were defined to quantitatively characterize the evolution law of the equivalent multi-scale permeability during gas adsorption or desorption processes. The effective stress generated by the CO₂ adsorption-induced swelling effect in the low-rank coal is 1.47 times that in the middle-rank coal and 2.51 times that in the high-rank coal. Additionally, the effective stress generated by the CO₂ adsorption-induced swelling effect in the low-rank coal is 5.15 times that generated by N₂, while this level is 4.32 times higher than that in the middle-rank coal. Therefore, compared with the low- and middle-rank coal, the high-rank coal exhibits a smaller decrease in multi-scale permeability due to its weaker adsorption-induced swelling effect. During N₂ adsorption, the pore pressure effect dominates over the adsorption-induced swelling effect, resulting in a decrease in the effective stress on the coal with increasing gas pressure. Consequently, the equivalent multi-scale permeability of coal will increase much more significantly with an increase in injected N₂ pressure than with an increase in CO₂ pressure. By accounting for the differences between the effects of adsorption-induced swelling and pore compression on the equivalent multi-scale permeability of coal reservoir, the injectivity of CO₂ can be improved by mixing it with N₂. Full article

(This article belongs to the Topic Advances in Integrated Geological, Mineralogical, and Engineering Research on Unconventional Oil and Gas)

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18 pages, 6288 KB  

Open AccessArticle

Discussion on Reservoir Characteristics and Hydraulic Fracturing Transformation Mechanism of Tectonic Coal

by Wenping Jiang and Siqing Sun

Energies 2026, 19(7), 1631; https://doi.org/10.3390/en19071631 - 26 Mar 2026

Viewed by 389

Abstract

To investigate the mechanisms of coal seam reservoir modification and the efficient development of surface coalbed methane (CBM), the coal with different structural formations in the 13-1 coal seam of Huainan Mining Area was selected as the research object. Fracturing numerical simulation technology [...] Read more.

To investigate the mechanisms of coal seam reservoir modification and the efficient development of surface coalbed methane (CBM), the coal with different structural formations in the 13-1 coal seam of Huainan Mining Area was selected as the research object. Fracturing numerical simulation technology was employed to analyze the effect of hydraulic fracturing on tectonic coal reservoirs and explore the mechanism of fracturing-induced gas production. The results show that fragmented coal contains well-developed face and butt cleats, and distinct fracture models were constructed for the three tectonic coal types. Granulated and mylonitic structural coals exhibit larger total pore volumes and higher proportions of pores larger than 10 nm than fragmented coal. Both tectonic coal types exhibit a high proportion of methane flow space, with rapid methane desorption and diffusion under high pressure and stable behavior under low pressure. Pore volume compressibility calculations indicate that tectonic coal exhibits poor compressibility. Numerical simulations indicate that direct horizontal well fracturing produces short, wide fractures, whereas roof-strata horizontal well fracturing generates longer, more effective fractures, primarily due to large-scale depressurization and induced fracturing associated with horizontal well drilling and staged fracturing. Full article

(This article belongs to the Topic Advances in Integrated Geological, Mineralogical, and Engineering Research on Unconventional Oil and Gas)

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28 pages, 6909 KB  

Open AccessArticle

Identification of Dominant Controlling Factors on Coalbed Methane Well Productivity in the Weizhou Syncline Based on Numerical Simulation and Multiple Machine Learning Methods

by Yupeng Wang, Shu Tao, Feilong Yu, Xiujun Ma, Xufeng Zheng and Chao Zhang

Energies 2026, 19(5), 1331; https://doi.org/10.3390/en19051331 - 6 Mar 2026

Viewed by 378

Abstract

To address the pronounced productivity heterogeneity among different well intervals of coalbed methane (CBM) wells in the Weizhou Syncline, as well as the lack of quantitative clarity regarding the respective contributions of geological and engineering factors to well productivity, a systematic analysis of [...] Read more.

To address the pronounced productivity heterogeneity among different well intervals of coalbed methane (CBM) wells in the Weizhou Syncline, as well as the lack of quantitative clarity regarding the respective contributions of geological and engineering factors to well productivity, a systematic analysis of the main productivity-controlling factors of CBM wells was conducted based on geological data from producing wells, hydraulic fracturing treatment parameters, and production dynamic data in the study area. On this basis, a coupled coal reservoir–fracture numerical simulation model was established to quantitatively evaluate the response of CBM productivity to key geological parameters, including porosity, permeability, coal seam thickness, and Langmuir parameters, as well as fracture geometric and flow parameters. Furthermore, multiple machine learning methods were employed to rank and cross-validate the relative importance of factors influencing CBM well productivity. The results indicate that within the parameter ranges representative of the study area, coal seam thickness, permeability, and Langmuir pressure exert a dominant control on cumulative gas production, constituting the primary controlling factors for CBM well productivity. The number of fractures and porosity are secondary influencing factors, and, under the combined effects of multiple factors, fracture geometry, fracture flow parameters, and reservoir pressure make relatively limited contributions to well productivity. These findings provide a quantitative basis and methodological reference for favorable target selection, fracturing parameter optimization, and efficient development of CBM blocks in the Weizhou Syncline and other regions with similar geological conditions. Full article

(This article belongs to the Topic Advances in Integrated Geological, Mineralogical, and Engineering Research on Unconventional Oil and Gas)

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16 pages, 11741 KB  

Open AccessArticle

Organic Geochemical Characteristics and Quantitative Evaluation of Hydrocarbon Generation Potential of Source Rocks in the First Member of the Qingshankou Formation, Songliao Basin

by Junhui Li, Xiuli Fu, Fangju Chen, Qiang Zhen, Bo Song, Guowei Yan and Shuangfang Lu

Processes 2026, 14(5), 814; https://doi.org/10.3390/pr14050814 - 2 Mar 2026

Viewed by 443

Abstract

Hydrocarbon resource potential evaluation represents the primary and core component of whole petroleum system studies. However, compared with the substantial progress achieved in understanding hydrocarbon generation mechanisms, quantitative assessments of hydrocarbon generation amounts from source rocks in the Songliao Basin remain relatively limited. [...] Read more.

Hydrocarbon resource potential evaluation represents the primary and core component of whole petroleum system studies. However, compared with the substantial progress achieved in understanding hydrocarbon generation mechanisms, quantitative assessments of hydrocarbon generation amounts from source rocks in the Songliao Basin remain relatively limited. Given that the genetic method is capable of comprehensively reflecting both the intrinsic hydrocarbon generation potential and conversion efficiency of source rocks and is supported by robust geological principles, this study was conducted within a genetic framework. Stratigraphic data and lithological descriptions from more than 2000 wells in the northern Songliao Basin, logging data from 387 wells, and measured basic geochemical data from 201 wells were integrated. Combined with the ΔlogR method, original hydrocarbon generation potential restoration techniques, and results from thermal simulation experiments, the planar distributions of key geochemical parameters of the first member of the Qingshankou Formation were systematically characterized. On this basis, the hydrocarbon generation potential and total hydrocarbon generation amounts of different structural units within the Songliao Basin were quantitatively evaluated. The results indicate that the cumulative hydrocarbon generation of the first member of the Qingshankou Formation reached approximately 506.55 × 10⁸ t. Among the structural units, the Qijia–Gulong Sag contributed 266.13 × 10⁸ t, the Sanzhao Sag 132.71 × 10⁸ t, the Longhupao Terrace 66.81 × 10⁸ t, and the Daqing Placanticline 40.90 × 10⁸ t. These results demonstrate significant heterogeneity in hydrocarbon generation capacity among different structural units, with the Qijia–Gulong Sag identified as the most important hydrocarbon generation center in the study area. This study provides a critical quantitative foundation for whole petroleum system research in the northern Songliao Basin. It not only supplies essential data support for subsequent resource apportionment of conventional and shale hydrocarbons but also offers important constraints for analyses of reservoir-type distribution and hydrocarbon accumulation mechanisms. Full article

(This article belongs to the Topic Advances in Integrated Geological, Mineralogical, and Engineering Research on Unconventional Oil and Gas)

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