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Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs

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A special issue of Processes (ISSN 2227-9717). This special issue belongs to the section "Energy Systems".

Deadline for manuscript submissions: 30 July 2026 | Viewed by 10624

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Special Issue Editors

Prof. Dr. Haichao Wang

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Guest Editor

School of Geological and Mining Engineering, Xinjiang University, Urumqi 830047, China
Interests: coalbed methane; underground coal gasification; resource evaluation
Special Issues, Collections and Topics in MDPI journals

Dr. Zhenzhi Wang

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Guest Editor

School of Resources and Environment, Henan Polytechnic University, Jiaozuo 454003, China
Interests: coalbed methane geology; carbon dioxide geological storage; gas injected for enhanced coalbed methane recovery
Special Issues, Collections and Topics in MDPI journals

Dr. Qinghe Niu

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Guest Editor

School of Civil Engineering, Shijiazhuang Tiedao University, Shijiazhuang 050043, China
Interests: exploration and development of deep coalbed methane; CO₂-enhanced coalbed methane recovery

Dr. Boyang Wang

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Guest Editor

Institute of Unconventional Oil & Gas, Northeast Petroleum University, Daqing 163318, China
Interests: shale oil and gas; coalbed methane; fractal characterization; reservoir sensitivity; hydrocarbon accumulation mechanism

Special Issue Information

Dear Colleagues,

China is reshaping the global energy landscape through its deep energy revolution, creating a new paradigm for unconventional resource development via three-dimensional synergy of technological breakthroughs, management innovation, and strategic planning. In strategic replacement zones below 1,500 meter depths, China has not only shattered the theoretical constraints of the "coalbed methane (CBM) extraction forbidden zone" but also established a comprehensive cost-reduction system across the entire industrial chain. This drives CBM production to exceed 11.7 billion cubic meters in 2024 with a year-on-year growth rate of 20.5%, and is projected to achieve 30 billion cubic meters production capacity by 2030—equivalent to adding a cluster of medium-sized gas fields. Simultaneously, this revolutionary practice forms strategic resonance with breakthroughs in continental shale oil development. Compared with marine shale oil, continental shale oil formed in complex geological environments exhibits strong reservoir heterogeneity, with significantly different enrichment patterns and extraction technologies that demand innovations in hydrocarbon generation mechanisms and mobility evaluation systems.

Looking forward, the following three certain trends will define the global energy landscape: (1) Technological leaps driving deeper resource extraction. (2) Unconventional resources becoming primary energy suppliers. (3) Low-carbon constraints catalyzing development model transformations. Under carbon neutrality goals, deep energy development demonstrates new technological convergences: CO₂ displacement technology enhances CBM recovery while achieving carbon sequestration; waterless fracturing processes dramatically conserve water resources; and underground gasification technology converts coal into syngas in situ. These innovations form a "geological modification-energy extraction-carbon sequestration" trinity technology matrix, reducing comprehensive development costs for deep CBM, shale gas, and hot dry rock resources by 30%, providing a transformative model for global deep-Earth resource exploitation.

Based on the above, the current topic will explore the following discussion directions (including but not limited to):

(1) Impact of major geological events on organic matter enrichment;

(2) Hydrocarbon generation mechanisms and kinetic mechanisms of organic matter;

(3) Fine characterization of reservoir heterogeneity structures and their evolutionary patterns;

(4) Highly integrated energy geology–engineering sweet spot evaluation technology;

(5) Physical and chemical reservoir stimulation techniques;

(6) Solutions for technical bottlenecks in deep CBM/shale oil–gas development;

(7) CO₂ geological storage technologies.

Prof. Dr. Haichao Wang
Dr. Zhenzhi Wang
Dr. Qinghe Niu
Dr. Boyang Wang
Guest Editors

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Keywords

deep energy
coalbed methane
shale oil
CO₂ displacement technology
geological carbon dioxide storage technology

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Published Papers (13 papers)

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Research

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14 pages, 1331 KB

Open AccessArticle

Fracture Conductivity and Its Effects on Production Estimation in Shale

by Raymond Cozby, Ismaeel Ibrahim, Jin Xue, Nnaemeka Okeke, Syed Muhammad Abdullah Safdar, Haithem Trabelsi, Racha Trabelsi and Fathi Boukadi

Processes 2026, 14(2), 338; https://doi.org/10.3390/pr14020338 - 18 Jan 2026

Viewed by 255

Abstract

This study investigates the impact of fracture conductivity on hydraulically fractured wells in the Eagle Ford Shale using commercial simulation software. Motivated by recent findings on conductivity degradation and the proven reliability of sensitivity analyses in shale reservoirs, a 17-stage horizontal well was modeled to evaluate productivity optimization. The methodology involved holding fracture fluid volume constant while analyzing conductivity variations across both single-fracture and full-well models. Production simulations were validated against real-time field data. Results indicate that the simulation models accurately represent the reservoir, with single-fracture scenarios yielding similar cumulative production and full-well models showing only minor deviations. Ultimately, the observed differences do not justify a significant deviation from current completion techniques under the modeling assumptions considered, as infinite-acting flow remains the dominant regime due to the reservoir’s low permeability. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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20 pages, 8678 KB

Open AccessArticle

Effect of Structural and Wettability Differences Between Low-Rank Vitrain and Durain on Methane Adsorption and Desorption

by Jinbo Shi, Dongmin Ma, Yue Chen, Huaichang Wang, Changjiang Ji, Chao Zheng, Pengpeng Guan, Yuan Cao and Yaqi Ji

Processes 2026, 14(2), 207; https://doi.org/10.3390/pr14020207 - 7 Jan 2026

Viewed by 229

Abstract

The wettability differences among macroscopic coal lithotypes constitute a critical issue requiring in-depth investigation in the development of low-rank coalbed methane. To elucidate the impact of wettability variation on methane adsorption/desorption, this study employed vitrain and durain samples from Jurassic low-rank coals in the Huanglong Coalfield. We analyzed changes in adsorption/desorption characteristics before and after wettability modification and conducted coal seam desorption experiments under simulated extraction conditions to explore the influence of wettability on methane adsorption/desorption behavior. The results indicate that vitrain exhibits greater full-scale pore volume (0.04073–0.07975 cm³/g) and specific surface area (132.302–170.919 m²/g) compared to durain (0.03646–0.05187 cm³/g and 114.572–122.827 m²/g, respectively). The coal–water interface contact angles of the low-rank coals are below 90°, indicating a weakly hydrophilic nature. Both cationic (CTAC) and zwitterionic (BS-12) surfactants effectively improved coal wettability. Following wettability modification, the maximum reduction in saturated adsorption capacity reached 48.24%, while the maximum increases in desorption ratio and recovery efficiency were 35.56% and 24.39%, respectively. Durain, due to its stronger inherent hydrophilicity, exhibited greater changes than vitrain. Under simulated extraction conditions, the combined effects of pore structure and wettability differences between the lithotypes led to preferential methane production along the vitrain–durain interfaces. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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18 pages, 2811 KB

Open AccessArticle

Research and Application of Intensive-Stage Fracturing Technology for Shale Oil in ZN Oilfield

by Lin-Peng Zhang, Bin Li, Yi-Fei Wang, Si-Bo Wang, Peng Zheng and Zong-Rui Wu

Processes 2026, 14(1), 131; https://doi.org/10.3390/pr14010131 - 30 Dec 2025

Viewed by 380

Abstract

The ZN Oilfield shale reservoir is characterized by thin sand–shale interbeds, strong lateral and vertical heterogeneity, poor porosity–permeability, low formation pressure coefficient, and low brittleness, which together limit fracture propagation and suppress production after conventional hydraulic fracturing. To overcome these constraints, we propose an intensive-stage, closely spaced volumetric fracturing technology that couples energy-replenishment pressurization with differentiated parameter design. Numerical simulations were used to quantify how injected fluid volume affects the post-fracturing formation pressure coefficient and estimated ultimate recovery (EUR), and to determine economically optimal energy-replenishment scales. Guided by a “dual sweet spot” evaluation (geological + engineering), field designs reduced stage spacing from 80–100 m to 30–50 m and cluster spacing from 10–20 m to 6–10 m, and increased proppant and fluid intensities to ~5.0 t/m and 22.0 m³/m, respectively. Field monitoring and production data show average fracture half-length increased to 193 m, and average initial oil production per well rose from 8.8 t/d to 12.9 t/d (≈46% increase). These results demonstrate that the proposed approach effectively enlarges fracture-controlled reservoir volume, enhances formation energy, and substantially improves single-well performance in low-pressure shale oil systems. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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30 pages, 20127 KB

Open AccessArticle

Enrichment Law and Controlling Factors of CBM in the Xishanyao Formation of the Hedong Mining Area, Urumqi

by Xiang Zhou, Xinyue Wen, Liyuan Wang, Haichao Wang, Xin Li, Shuxun Sang, Shuguang Yang, Yibing Wang, Na Zhang, Peng Lai and Yongyong Feng

Processes 2026, 14(1), 21; https://doi.org/10.3390/pr14010021 - 20 Dec 2025

Viewed by 332

Abstract

The enrichment laws and key controlling factors of coalbed methane (CBM) in the Xishanyao Formation of the Hedong mining area remain unclear, restricting exploration progress. Based on well data and experimental analyses, this study investigates CBM enrichment characteristics and geological controls using genetic identification diagrams. Results demonstrate that CBM exhibits a “high in northwest and low in southeast” planar distribution. Vertically, CBM content is extremely low above 360 m due to weathering oxidation and burnt zone effects, increases within the 360–950 m interval (peaking at 750–950 m), and declines from 950 to 1200 m because of limited gas contribution. Genetic analysis indicates predominantly primary biogenic gas, with a minor component of early thermogenic gas. Enrichment is controlled by structure and hydrogeology: the medium-depth range (358–936 m) on the northern syncline limb and western part of the northern monoclinal zone forms a high-efficiency enrichment zone due to compressive stress from reverse faults and high mineralization groundwater (TDS > 8000 mg/L). While the southern limb, characterized by high-angle tensile fractures and active groundwater runoff, suffers gas loss and generally low gas content (<3.5 m³/t). This study clarifies CBM enrichment laws and enrichment mechanisms, supporting exploration of low-rank CBM in the Hedong mining area. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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20 pages, 17604 KB

Open AccessArticle

Controls of Fault System on Hydrocarbon Accumulation: A Case Study from the Carboniferous Reservoir of the Hongche Fault Zone in the Junggar Basin

by Cheng Huang, Yonghe Sun, Huafeng Zhou, Xiaofan Yang, Junwei Han, Jian Fu, Mengyuan Hao and Yulin Song

Processes 2025, 13(12), 4054; https://doi.org/10.3390/pr13124054 - 15 Dec 2025

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Abstract

The Hongche Fault Zone in the Junggar Basin exhibits significant spatiotemporal variations in the relationship between fault systems and hydrocarbon accumulation across different structural belts. Two key factors contribute to this phenomenon: frequent tectonic activities and well-developed Paleozoic fault systems. To date, no detailed studies have been conducted on the fault systems in the Paleozoic strata of the Hongche Fault Zone. In this study, the fault systems in the Paleozoic strata of the Hongche Fault Zone were systematically sorted out for the first time. Furthermore, the controlling effects of active faults in different geological periods on hydrocarbon charging were clarified. Firstly, basing on the 3D seismic and well-log data, the structural framework and fault activity, fault systems, source-contacting faults were characterized. Vertically, the Hongche Fault Zone experienced three major thrusting episodes followed by one weak extensional subsidence Stage, forming four principal tectonic layers: Permian (Thrusting Episode I), Triassic (Thrusting Episode II), Jurassic (Thrusting Episode III), and Cretaceous–Quaternary (Post-Thrusting Subsidence). Laterally, six fault systems are identified: Middle Permian (Stage I), Late Triassic (Stage II), Jurassic (Stage III), post-Cretaceous (Stage IV), as well as composite systems from Middle Permian–Jurassic (Stages I–III) and Late Triassic–Jurassic (Stages II–III). These reveal multi-stage, multi-directional composite structural characteristics in the study area. According to the oil–source correlation, the Carboniferous reservoir is primarily sourced by Permian Fengcheng Formation source rocks in the Shawan Sag. Hydrocarbon migration tracing shows that oil migrates along faults, progressively charging from depression zones to thrust belts and uplifted areas. In this process, fault systems exert hierarchical controls on accumulation: Stage I faults dominate trap formation, Stages II and III faults regulate hydrocarbon migration, accumulation, and adjustment, while Stage IV faults influence hydrocarbon conduction in Mesozoic–Cenozoic reservoirs. By clarifying the fault-controlled hydrocarbon accumulation mechanisms in the Hongche Fault Zone, this study provides theoretical guidance for two key aspects of the Carboniferous reservoirs in the study area: the optimization of favorable exploration zones and the development of reserves. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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17 pages, 4253 KB

Open AccessArticle

Effects of High-Pressure Water Injection on Surface Functional Groups and Wettability in Different Rank Coals: Implications for Hydraulic Fracturing in CBM Wells

by Yanjun Meng, Jiawei Liu, Kunjie Li, Wei Li, Xinlu Yan and Huimin Hu

Processes 2025, 13(11), 3718; https://doi.org/10.3390/pr13113718 - 18 Nov 2025

Viewed by 542

Abstract

Hydraulic fracturing is a widely used stimulation technology in coalbed methane (CBM) fields. However, the coal reservoir damage caused by high-pressure hydraulic fracturing seriously affects the production effects, and the mechanism is not clear. Therefore, based on high-pressure water injection (HPWI), Fourier transform infrared spectroscopy (FTIR), and contact angle tests, the effects of HPWI on surface chemical properties and wettability of different rank coals were studied. The FTIR results show that surface functional groups of different rank coals have changed to varying degrees after HPWI. After HPWI, the content of Ash in Shaqu and Yonghong coal decreases by 2.29% and 27.91%, while it increases by 297.87% in Shaping coal. The C–O bond content in Shaping and Yonghong coal decreases by 6.32% and 15.19%, while the C–O bond content in Shaqu coal increases by 50.96%. The content of C=O in Shaping and Yonghong coal increases by 2.44% and 27.84%, respectively. The R₂CH₂ contents increase by 19.75% and 12.5% in Shaping and Shaqu coal, while decreasing by 6.48% in Yonghong coal. The RCH₃ content increases by 21.11% in Yonghong coal, while it decreases by 19.09% and 24.01% in Shaping and Shaqu coal. The content of cyclic associated hydroxy–hydrogen bond decreases by 41.25%, 63.92% and 65.86% in Shaping, Shaqu, and Yonghong coals, and the content of free hydroxyl group increases by 57.92%, 58.42%, and 93.71%. The f_ar^c of coal remains almost unchanged, the DOC increases by 20.21%, 126.77% and 0.24% in Shaping, Shaqu, and Yonghong coals, and the I decreases by 16.67% and 51.46% in Shaping and Yonghong coals, indicating that the ordering of coal becomes better, and the content of methylene carbon in the form of long straight chain increases after HPWI. The complexity and differences of changes in functional groups are mainly due to differences in coal structures caused by coalification. The contact angle tests show that the wetting contact angle of different rank coals decreased by 2.30% to 14.50%, revealing that the hydrophilicity of coals increases after HPWI. The decline rate of wetting angles in medium and high-rank coals was significantly higher than that of low-rank coal. This phenomenon discovered that the increase in hydrophilic functional groups caused by HPWI action leads to an increase in the hydrophilicity of coal samples, which is not conducive to the drainage efficiency in CBM development. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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17 pages, 4446 KB

Open AccessArticle

Study on Production System Optimization and Productivity Prediction of Deep Coalbed Methane Wells Considering Thermal–Hydraulic–Mechanical Coupling Effects

by Sukai Wang, Yonglong Li, Wei Liu, Siyu Zhang, Lipeng Zhang, Yan Liang, Xionghui Liu, Quan Gan, Shiqi Liu and Wenkai Wang

Processes 2025, 13(10), 3090; https://doi.org/10.3390/pr13103090 - 26 Sep 2025

Viewed by 705

Abstract

Deep coalbed methane (CBM) resources possess significant potential. However, their development is challenged by geological characteristics such as high in situ stress and low permeability. Furthermore, existing production strategies often prove inadequate. In order to achieve long-term stable production of deep coalbed methane reservoirs and increase their final recoverable reserves, it is urgent to construct a scientific and reasonable drainage system. This study focuses on the deep CBM reservoir in the Daning-Jixian Block of the Ordos Basin. First, a thermal–hydraulic–mechanical (THM) multi-physics coupling mathematical model was constructed and validated against historical well production data. Then, the model was used to forecast production. Finally, key control measures for enhancing well productivity were identified through production strategy adjustment. The results indicate that controlling the bottom-hole flowing pressure drop rate at 1.5 times the current pressure drop rate accelerates the early-stage pressure drop, enabling gas wells to reach the peak gas production earlier. The optimized pressure drop rates for each stage are as follows: 0.15 MPa/d during the dewatering stage, 0.057 MPa/d during the gas production rise stage, 0.035 MPa/d during the stable production stage, and 0.01 MPa/d during the production decline stage. This strategy increases peak daily gas production by 15.90% and cumulative production by 3.68%. It also avoids excessive pressure drop, which can cause premature production decline during the stable phase. Consequently, the approach maximizes production over the entire life cycle of the well. Mechanistically, the 1.5× flowing pressure drop offers multiple advantages. Firstly, it significantly shortens the dewatering and production ramp-up periods. This acceleration promotes efficient gas desorption, increasing the desorbed gas volume by 1.9%, and enhances diffusion, yielding a 39.2% higher peak diffusion rate, all while preserving reservoir properties. Additionally, this strategy synergistically optimizes the water saturation and temperature fields, which mitigates the water-blocking effect. Furthermore, by enhancing coal matrix shrinkage, it rebounds permeability to 88.9%, thus avoiding stress-induced damage from aggressive extraction. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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24 pages, 2965 KB

Open AccessArticle

Research and Application of Dynamic Monitoring Technology for Fracture Stimulation Optimization in Unconventional Reservoirs of the Sichuan Basin Using the Wide-Field Electromagnetic Method

by Changheng Yu, Wenliang Zhang, Zongquan Liu, Heng Ye and Zhiwen Gu

Processes 2025, 13(9), 3025; https://doi.org/10.3390/pr13093025 - 22 Sep 2025

Cited by 1 | Viewed by 715

Abstract

This study addresses the key technical challenges in monitoring hydraulic fracturing within unconventional reservoirs through an innovative wide-field electromagnetic (WEM) monitoring technique. The method employs a 5A AC-excited wellbore-fracturing fluid system to establish a conductor antenna effect, coupled with a surface electrode array (100–250 m offset) to detect millivolt-level time-lapse potential anomalies, enabling real-time dynamic monitoring of 142 fracturing stages. A line current source integral model was developed to achieve quantitative fracture network inversion with less than 12% error, attaining 10 m spatial resolution and dynamic updates every 10 min (80% faster than conventional methods). Optimal engineering parameters were identified, including fluid intensity ranges of 25–30 m³/m for tight sandstone and 30–35 m³/m for shale, with particulate diverters achieving 93.1% diversion efficiency (significantly outperforming chemical diverters at 35%). Application in deep reservoirs maintained signal attenuation rates below 5% per kilometer. Theoretically, a nonlinear relationship model between fluid intensity and stimulated area was established, while practical implementation through real-time adjustments in 142 stages enhanced single-well production by 15–20% and reduced diverter costs, advancing the paradigm shift from empirical to scientific fracturing in unconventional reservoir development. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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15 pages, 3992 KB

Open AccessArticle

Characteristics of Organisms and Origin of Organic Matter in Permian Shale in Western Hubei Province, South China

by Yuying Zhang, Baojian Shen, Dongjun Feng, Bo Gao, Pengwei Wang, Min Li, Yifei Li and Yang Liu

Processes 2025, 13(9), 2673; https://doi.org/10.3390/pr13092673 - 22 Aug 2025

Viewed by 822

Abstract

Permian shale gas is a kind of energy resource with commercial development potential. The characteristics of its organic source and enrichment have received extensive attention in recent years. This study systematically analyzed the variations in types and assemblages of hydrocarbon-forming organisms across different stratigraphic layers of Permian shale in western Hubei through scanning electron microscopy (SEM) and microscopic observations. Moreover, the source characteristics and enrichment mechanisms of organic matter in Permian shale were identified. Hydrocarbon generation in Permian shale is primarily attributed to planktonic algae-derived acritarchs, supplemented by higher plants and green algae, based on the observation under the SEM and microscope. The hydrocarbon-forming microorganisms in the Gufeng Formation are predominantly characterized by acritarchs. A notable decrease in acritarch content is observed at the bottom of the Wujiaping Formation, accompanied by a significant increase in higher plant constituents and a slight rise in green algae abundance. Subsequently, from the middle-upper members of the Wujiaping Formation through the Dalong Formation, acritarch concentrations rebound while higher plants and green algae contributions diminish. The organic matter in the studied layer is predominantly generated from planktonic algae (acritarchs and green algae), with subordinate contributions from terrestrial higher plants. During the sedimentary stage of the Gufeng Formation, rising sea levels sustained a deep siliceous shelf environment in the E’xi Trough, where organic matter was primarily sourced from acritarchs, with limited terrigenous input. The regressive phase at the bottom of the Wujiaping Formation resulted in coastal marsh throughout the E’xi Trough, creating a mixed organic matter assemblage of aquatic planktonic algae and enhanced terrestrial higher plant material. As sedimentation progressed into the middle-upper Wujiaping Formation and Dalong Formation, the E’xi Trough evolved into a deep siliceous shelf and platform-margin slope environment. During this stage, organic matter was again predominantly supplied by planktonic algae (mainly acritarchs), with reduced terrestrial organic input. These findings provide valuable theoretical insights for guiding Permian shale gas exploration and development strategies. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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21 pages, 7884 KB

Open AccessArticle

Multi-Objective Optimization Inverse Analysis for Characterization of Petroleum Geomechanical Properties During Hydraulic Fracturing

by Shike Zhang, Zhongliang Ru, Lihong Zhao, Bangxiang Li, Hongbo Zhao and Xianglong Wang

Processes 2025, 13(8), 2587; https://doi.org/10.3390/pr13082587 - 15 Aug 2025

Cited by 1 | Viewed by 747

Abstract

To address the difficulty in the characterization of the geomechanical properties of reservoirs in petroleum engineering using the traditional formula, due to the complexity of the reservoir, this study proposes a framework of inverse analysis to characterize the geomechanical properties of reservoirs formed through hydraulic fracturing by combining the XGBoost, multi-objective particle swarm optimization (MOPSO), and numerical models. XGBoost was used to generate a surrogate model to approximate the physical model, and the numerical model was used to generate a dataset for XGBoost. MOPSO is regarded as an optimal technology to deal with the conflict between multi-objective functions in inverse analysis. On comparing the results between the actual geomechanical properties and those obtained by using traditional inverse analysis, the proposed framework accurately characterizes the geomechanical parameters of reservoirs obtained through hydraulic fracturing. This provides a feasible, scientific, and promising way to characterize reservoir formation in petroleum engineering, as well as a reference for other fields of engineering. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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26 pages, 21628 KB

Open AccessArticle

Key Controlling Factors of Deep Coalbed Methane Reservoir Characteristics in Yan’an Block, Ordos Basin: Based on Multi-Scale Pore Structure Characterization and Fluid Mobility Research

by Jianbo Sun, Sijie Han, Shiqi Liu, Jin Lin, Fukang Li, Gang Liu, Peng Shi and Hongbo Teng

Processes 2025, 13(8), 2382; https://doi.org/10.3390/pr13082382 - 27 Jul 2025

Cited by 1 | Viewed by 1080

Abstract

The development of deep coalbed methane (buried depth > 2000 m) in the Yan’an block of Ordos Basin is limited by low permeability, the pore structure of the coal reservoir, and the gas–water occurrence relationship. It is urgent to clarify the key control mechanism of pore structure on gas migration. In this study, based on high-pressure mercury intrusion (pore size > 50 nm), low-temperature N₂/CO₂ adsorption (0.38–50 nm), low-field nuclear magnetic resonance technology, fractal theory and Pearson correlation coefficient analysis, quantitative characterization of multi-scale pore–fluid system was carried out. The results show that the multi-scale pore network in the study area jointly regulates the occurrence and migration process of deep coalbed methane in Yan’an through the ternary hierarchical gas control mechanism of ‘micropore adsorption dominant, mesopore diffusion connection and macroporous seepage bottleneck’. The fractal dimensions of micropores and seepage are between 2.17–2.29 and 2.46–2.58, respectively. The shape of micropores is relatively regular, the complexity of micropore structure is low, and the confined space is mainly slit-like or ink bottle-like. The pore-throat network structure is relatively homogeneous, the difference in pore throat size is reduced, and the seepage pore shape is simple. The bimodal structure of low-field nuclear magnetic resonance shows that the bound fluid is related to the development of micropores, and the fluid mobility mainly depends on the seepage pores. Pearson’s correlation coefficient showed that the specific surface area of micropores was strongly positively correlated with methane adsorption capacity, and the nanoscale pore-size dominated gas occurrence through van der Waals force physical adsorption. The specific surface area of mesopores is significantly positively correlated with the tortuosity. The roughness and branch structure of the inner surface of the channel lead to the extension of the migration path and the inhibition of methane diffusion efficiency. Seepage porosity is linearly correlated with gas permeability, and the scale of connected seepage pores dominates the seepage capacity of reservoirs. This study reveals the pore structure and ternary grading synergistic gas control mechanism of deep coal reservoirs in the Yan’an Block, which provides a theoretical basis for the development of deep coalbed methane. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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Review

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17 pages, 1033 KB

Open AccessFeature PaperEditor’s ChoiceReview

Towards Carbon-Neutral Hydrogen: Integrating Methane Pyrolysis with Geothermal Energy

by Ayann Tiam, Marshall Watson and Talal Gamadi

Processes 2025, 13(10), 3195; https://doi.org/10.3390/pr13103195 - 8 Oct 2025

Viewed by 1024

Abstract

Methane pyrolysis produces hydrogen (H₂) with solid carbon black as a co-product, eliminating direct CO₂ emissions and enabling a low-carbon supply when combined with renewable or low-carbon heat sources. In this study, we propose a hybrid geothermal pyrolysis configuration in which an enhanced geothermal system (EGS) provides base-load preheating and isothermal holding, while either electrical or solar–thermal input supplies the final temperature rise to the catalytic set-point. The work addresses four main objectives: (i) integrating field-scale geothermal operating envelopes to define heat-integration targets and duty splits; (ii) assessing scalability through high-pressure reactor design, thermal management, and carbon separation strategies that preserve co-product value; (iii) developing a techno-economic analysis (TEA) framework that lists CAPEX and OPEX, incorporates carbon pricing and credits, and evaluates dual-product economics for hydrogen and carbon black; and (iv) reorganizing state-of-the-art advances chronologically, linking molten media demonstrations, catalyst development, and integration studies. The process synthesis shows that allocating geothermal heat to the largest heat-capacity streams (feed, recycle, and melt/salt hold) reduces electric top-up demand and stabilizes reactor operation, thereby mitigating coking, sintering, and broad particle size distributions. High-pressure operation improves the hydrogen yield and equipment compactness, but it also requires corrosion-resistant materials and careful thermal-stress management. The TEA indicates that the levelized cost of hydrogen is primarily influenced by two factors: (a) electric duty and the carbon intensity of power, and (b) the achievable price and specifications of the carbon co-product. Secondary drivers include the methane price, geothermal capacity factor, and overall conversion and selectivity. Overall, geothermal-assisted methane pyrolysis emerges as a practical pathway to turquoise hydrogen, if the carbon quality is maintained and heat integration is optimized. The study offers design principles and reporting guidelines intended to accelerate pilot-scale deployment. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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27 pages, 5201 KB

Open AccessReview

Geomechanical and Geochemical Considerations for Hydrogen Storage in Shale and Tight Reservoirs

by Sarath Poda and Gamadi Talal

Processes 2025, 13(8), 2522; https://doi.org/10.3390/pr13082522 - 11 Aug 2025

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Abstract

Underground hydrogen storage (UHS) in shale and tight reservoirs offers a promising solution for large-scale energy storage, playing a critical role in the transition to a hydrogen-based economy. However, the successful deployment of UHS in these low-permeability formations depends on a thorough understanding of the geomechanical and geochemical factors that affect storage integrity, injectivity, and long-term stability. This review critically examines the geomechanical aspects, including stress distribution, rock deformation, fracture propagation, and caprock integrity, which govern hydrogen containment under subsurface conditions. Additionally, it explores key geochemical challenges such as hydrogen-induced mineral alterations, adsorption effects, microbial activity, and potential reactivity with formation fluids, to evaluate their impact on storage feasibility. A comprehensive analysis of experimental studies, numerical modeling approaches, and field applications is presented to identify knowledge gaps and future research directions. Full article

(This article belongs to the Special Issue Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs)

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Recent Developments in Low-Carbon and Efficient Extraction Technologies of Deep Unconventional Reservoirs

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