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Exploration and Development of Unconventional Oil and Gas Resources: Latest Advances and Prospects: 3rd Edition

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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: closed (25 February 2026) | Viewed by 8546

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Prof. Dr. Shu Tao

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Department of Energy and Environment, School of Energy Resources, China University of Geosciences, Beijing 100083, China
Interests: exploration and development of unconventional oil and gas resources such as coalbed methane, shale gas, shale oil, oil shale, and tight sandstone gas
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Dr. Wei Ju

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School of Resources and Geosciences, China University of Mining and Technology, Xuzhou 221116, China
Interests: reservoir geomechanics; unconventional oil and gas geology; basin analysis
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Dr. Shida Chen

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School of Energy, China University of Geosciences (Beijing), Beijing 10083, China
Interests: unconventional resource exploration and exploitation, especially for resource of deep coalbed methane
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Dr. Zhengguang Zhang

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General Prospecting Institute of China National Administration of Coal Geology, Beijing, China
Interests: coalbed methane geology; coal body structure; hydrogeochemistry; favorable area optimization; well site deployment; in-situ stress; reservoir stimulation technology; dynamic permeability
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Dr. Jiang Han

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School of Vehicle And Energy, Yanshan University, Qinhuangdao 066004, China
Interests: unconventional resource exploration and exploitation; nanofluidics and nanorobotics for enhanced oil and gas recovery
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Special Issue Information

Dear Colleagues,

Fossil fuels are important to both the global and Chinese economies, and “unconventional” oil and gas resources—resources that cannot be produced, transported, or refined using traditional techniques—are expected to play a larger role in helping the U.S. and China meet future energy needs. With rising energy prices, unconventional oil and gas resources have received renewed domestic attention in recent years. The efficient exploration and development of unconventional oil and gas needs the support of a series of geological and engineering studies, including those focused on exploration, evaluation, drilling, completion, and production. The aim of this Special Issue is to introduce the latest progress in unconventional oil and gas geology and engineering, especially for reservoir evaluation, geological enrichment factors, enrichment model, permeability integrated evaluation, and mechanism analysis.

You may choose our Joint Special Issue in Applied Sciences.

Prof. Dr. Shu Tao
Dr. Wei Ju
Dr. Shida Chen
Dr. Zhengguang Zhang
Dr. Jiang Han
Guest Editors

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Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2600 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

unconventional oil and gas
exploration and development
reservoir evaluation
seepage mechanism
hydrocarbon enrichment model
reservoir petrophysics

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Exploration and Development of Unconventional Oil and Gas Resources: Latest Advances and Prospects in Energies (12 articles)

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Research

17 pages, 1530 KB

Open AccessArticle

Compatibility for Large-Region Gas Extraction Technology in the Baode Coal Mine

by Xinjiang Luo, Lijun Jiang and Huazhou Huang

Energies 2026, 19(5), 1272; https://doi.org/10.3390/en19051272 - 4 Mar 2026

Viewed by 283

Abstract

To address the challenges of designing geologically compatible, large-scale gas drainage strategies in gassy coal mines, this study introduces an integrated workflow combining detailed gas-geological unit subdivision with the Analytic Hierarchy Process (AHP) for the Baode Coal Mine. This approach aims to transform gas drainage technology selection from empirical judgment to a systematic, quantitative decision-making process, thereby enhancing control precision and mine safety. First, the No. 8 coal seam was refined into ten distinct gas-geological units (II-i to II-x), forming the foundation for a targeted management strategy. For these units, a quantitative evaluation index system was constructed, integrating key factors such as permeability, structural characteristics, and unit area. The AHP was then employed to assess the adaptability of four primary drainage technologies: ULB-uni/bi (underground long borehole unidirectional/bidirectional drainage), UULB (underground ultra-long directional borehole drainage), UDLB-SHF (underground directional long borehole drainage with staged hydraulic fracturing), and FHWS (fractured horizontal wells drilled from the surface). The decision analysis reveals significant regional differentiation in technical suitability. FHWS ranks highest in structurally complex and water-rich zones. UDLB-SHF and UULB serve as viable, cost-effective alternatives to FHWS in various scenarios, with UULB being particularly advantageous for “large-area pre-drainage” in extensive panels with relatively simple geology. ULB-uni/bi is confirmed as the most economical option but is suitable only for minor blocks with simple conditions. Consequently, the study proposes a hierarchical, zone-specific strategy: prioritizing surface-based FHWS for high-risk zones, employing UDLB-SHF for active permeability enhancement in low-permeability resource-rich areas, utilizing UULB for efficient large-area drainage, and restricting ULB-uni/bi to small, geologically normal blocks. Ultimately, this research establishes a robust technical selection system that integrates fine geological subdivision, AHP-based multi-criteria evaluation, and targeted technology matching. It provides a scientific basis for balancing risk control and cost optimization in gas drainage design for the Baode Coal Mine. In summary, the methodological framework proposed in this study provides a systematic approach for coal mine gas control under complex geological conditions. Its core value lies in achieving the unity of scientificity and practicality in gas control technology decisions through standardized analysis logic and differentiated adaptation mechanisms, thereby providing support for the precise and efficient development of coal mine gas control. Full article

(This article belongs to the Special Issue Exploration and Development of Unconventional Oil and Gas Resources: Latest Advances and Prospects: 3rd Edition)

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28 pages, 19390 KB

Open AccessArticle

Characteristics and Controlling Factors of Carboniferous Tight Bioclastic Limestone Reservoirs in the Shiqiantan Sag, Junggar Basin

by Yong Wang, Haifang Cao, Jialing Chen, Yijia Zhang, Yue Wang, Jing Li, Dongxia Chen, Mingliang Peng, Yuchao Wang, Yuechang Dong, Changling Cheng, Yunhai Wang, Peng Zhou, Na Li and Hongda Qu

Energies 2026, 19(5), 1149; https://doi.org/10.3390/en19051149 - 25 Feb 2026

Viewed by 437

Abstract

Despite the promising exploration potential of the tight bioclastic limestone in the Carboniferous Shiqiantan Formation (Shiqiantan Sag, Junggar Basin), its reservoir characteristics remain poorly constrained. In particular, the macro and microscopic features and the key factors controlling reservoir development are still not well understood. We combined core observation, cast thin-section analysis, scanning electron microscopy (SEM), X-ray diffraction (XRD), high-pressure mercury intrusion, nitrogen adsorption, and nuclear magnetic resonance (NMR) to systematically characterize the Carboniferous bioclastic limestone reservoirs and identify the factors controlling their development in the Shiqiantan Sag. This study develops a multi-scale quantitative framework that integrates mercury intrusion–withdrawal behavior, nitrogen adsorption, and NMR T₂ spectra to constrain pore connectivity and the contribution of microfractures in tight carbonate reservoirs, providing a transferable approach for reservoir evaluation beyond the study area. The results categorize three rock microfacies in the study area: Bioclastic micrite, Micritic bioclastic limestone, and Sparry Bioclastic Limestone. The reservoir space is predominantly composed of secondary pores, including intragranular dissolution pores, intercrystalline clay pores, and microfractures. The pore structures exhibit a marked contrast across the lithofacies: the sparry bioclastic limestone develops the most optimal pore-fracture composite system, The pore structures exhibit a marked contrast across the lithofacies, directly correlating with hydrocarbon accumulation. Specifically, the sparry bioclastic limestone develops a pore-fracture composite system characterized by 25–100 nm pore throats, corresponding to the primary oil-bearing intervals observed in drilling. In contrast, the bioclastic micrite limestone and micritic bioclastic limestone, despite exhibiting localized nanoscale pores, lack effective connectivity (pore throats < 25 nm) and predominantly act as tight, dry layers with poor or no oil and gas shows, which endow them with the anomalous characteristic of relatively low porosity yet high permeability. This study reveals an integrated control on the development of tight bioclastic limestone reservoirs, in which sedimentary microenvironment and paleogeomorphology jointly determine the initial reservoir framework, while subsequent structural fractures and associated diagenetic dissolution play a critical role in modifying pore structures and enhancing reservoir quality. Sedimentary microfacies distribution, controlled by paleogeomorphologic variations, dictated the initial reservoir fabric. Subsequently, fracture systems generated by tectonic uplift, coupled with dissolution from meteoric freshwater leaching and organic acids, facilitated the development of secondary pores. Ultimately, the resulting optimization of the pore structure governs the final reservoir quality. The sparry bioclastic limestone is identified as the most promising exploration target in the study area. Its favorable reservoir quality is mainly attributed to its development on palaeogeomorphic and structural highs, where enhanced hydrodynamic energy and subsequent fracture-related dissolution significantly improved pore connectivity. These high-quality reservoirs are widely developed on gentle slope profiles and similar high-quality reservoirs may also locally occur at isolated palaeogeomorphic highs within steep-slope settings, as demonstrated by individual wells. Full article

(This article belongs to the Special Issue Exploration and Development of Unconventional Oil and Gas Resources: Latest Advances and Prospects: 3rd Edition)

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21 pages, 10533 KB

Open AccessArticle

Differential Mechanisms of Tight Sandstone Reservoirs and Their Impact on Gas-Bearing Characteristics in the Shaximiao Formation, Southwestern Sichuan Basin

by Xiaojuan Wang, Ke Pan, Zaiquan Yang, Xu Guan, Shuangling Chen, Dongxia Chen, Lan Li, Yilin Liang, Maosen Wang, Kaijun Tan and Qiaochu Wang

Energies 2025, 18(24), 6501; https://doi.org/10.3390/en18246501 - 11 Dec 2025

Viewed by 474

Abstract

To identify the principal controls on gas-bearing property heterogeneity in tight reservoirs of the Shaximiao Formation in the southwestern Sichuan Basin, this study systematically examines pore structure characteristics and their influence on reservoir quality through an integrated approach incorporating cast thin sections, X-ray diffraction (XRD), high-pressure mercury injection (HPMI), and parameters such as homogeneity and variation coefficients. The research has indicated that the following findings: (1) The reservoir lithology in the study area is predominantly lithic arkose, with pore types dominated by residual intergranular pores and intragranular dissolution pores, and pore-throat radii ranging from 5 nm to 1 μm. (2) The disparity in reservoir quality is attributed to two primary factors. Firstly, diverse sediment provenance directions and varying mineral compositions directly influence the internal pore structure of the reservoirs. Secondly, differences in diagenetic minerals lead to heterogeneity in pore space development. Specifically, early carbonate cementation in the Pingluoba reservoir occluded porosity, resulting in poor physical properties. In the Yanjinggou reservoir, clay mineral cementation and pore-filling activities significantly reduced reservoir quality. In contrast, the presence of chlorite coatings in the Baimamiao and Guanyinsi reservoirs helped preserve primary porosity, contributing to superior reservoir properties. (3) The variation in gas content between different gas reservoirs is primarily attributed to differences in reservoir heterogeneity on a planar scale, whereas the gas content variation within different intervals of the same gas reservoir is controlled by differences in pore structure among various sand units. Furthermore, gas content heterogeneity within the same interval of a single reservoir results from variations in sand body thickness and connectivity. Full article

(This article belongs to the Special Issue Exploration and Development of Unconventional Oil and Gas Resources: Latest Advances and Prospects: 3rd Edition)

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24 pages, 14995 KB

Open AccessArticle

A Novel Method for Predicting Oil and Gas Resource Potential Based on Ensemble Learning BP-Neural Network: Application to Dongpu Depression, Bohai Bay Basin, China

by Zijie Yang, Dongxia Chen, Qiaochu Wang, Sha Li, Fuwei Wang, Shumin Chen, Wanrong Zhang, Dongsheng Yao, Yuchao Wang and Han Wang

Energies 2025, 18(21), 5562; https://doi.org/10.3390/en18215562 - 22 Oct 2025

Cited by 1 | Viewed by 753

Abstract

Assessing and forecasting hydrocarbon resource potential (HRP) is of great significance. However, due to the complexity and uncertainty of geological conditions during hydrocarbon accumulation, it is challenging to accurately establish HRP models. This study employs machine learning methods to construct a HRP assessment model. First, nine primary controlling factors were selected from the five key conditions for HRP: source rock, reservoir, trap, migration, and accumulation. Subsequently, three prediction models were developed based on the backpropagation (BP) neural network, BP-Bagging algorithm, and BP-AdaBoost algorithm, with hydrocarbon resources abundance as the output metric. These models were applied to the Dongpu Depression in the Bohai Bay Basin for performance evaluation and optimization. Finally, this study examined the importance of various variables in predicting HRP and analyzed model uncertainty. The results indicate that the BP-AdaBoost model outperforms the others. On the test dataset, the BP-AdaBoost model achieved an R² value of 0.77, compared to 0.73 for the BP-Bagging model and only 0.64 for the standard BP model. Variable importance analysis revealed that trap area, sandstone thickness, sedimentary facies type, and distance to faults significantly contribute to HRP. Furthermore, model accuracy is influenced by multiple factors, including the selection and quantification of geological parameters, dataset size and distribution characteristics, and the choice of machine learning algorithm models. In summary, machine learning provides a reliable method for assessing HRP, offering new insights for identifying high-quality exploration blocks and optimizing development strategies. Full article

(This article belongs to the Special Issue Exploration and Development of Unconventional Oil and Gas Resources: Latest Advances and Prospects: 3rd Edition)

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16 pages, 3568 KB

Open AccessArticle

Delineation and Application of Gas Geological Units for Optimized Large-Scale Gas Drainage in the Baode Mine

by Shuaiyin He, Xinjiang Luo, Jinbo Zhang, Zenghui Zhang, Peng Li and Huazhou Huang

Energies 2025, 18(19), 5237; https://doi.org/10.3390/en18195237 - 2 Oct 2025

Cited by 1 | Viewed by 545

Abstract

Addressing the challenge of efficient gas control in high-gas coal mines with ultra-long panels, this study focuses on the No. 8 coal seam in the Baode Mine. A multi-parameter integrated methodology was developed to establish a hierarchical classification system of Gas Geological Units (GGUs), aiming to identify regions suitable for large-scale gas extraction. The results indicate that the overall structure of the No. 8 coal seam is a simple monocline. Both gas content (ranging from 2.0 to 7.0 m³/t) and gas pressure (ranging from 0.2 to 0.65 MPa) generally increase with burial depth. However, local anomalies in these parameters, caused by geological structures and hydrogeological conditions, significantly limit the effectiveness of large-scale drainage using ultra-long boreholes. Based on key criteria, the seam was classified into three Grade I and ten Grade II GGUs, distinguishing anomalous zones from homogeneous units. Among the Grade II units, eight (II-i to II-viii) were identified as anomalous zones with distinct geological constraints, while two (II-ix and II-x) exhibited homogeneous gas geological parameters. Practical implementation of large-scale gas extraction strategies—including underground ultra-long boreholes and a U-shaped surface well—within the homogeneous Unit II-x demonstrated significantly improved gas drainage performance, characterized by higher methane concentration, greater flow rate, enhanced temporal stability, and more favorable decay characteristics compared to conventional boreholes. These findings confirm the critical role of GGU delineation in guiding efficient regional gas control and ensuring safe production in similar high-gas coal mines. Full article

(This article belongs to the Special Issue Exploration and Development of Unconventional Oil and Gas Resources: Latest Advances and Prospects: 3rd Edition)

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16 pages, 10290 KB

Open AccessArticle

Integrated Experimental and Numerical Investigation on CO₂-Based Cyclic Solvent Injection Enhanced by Water and Nanoparticle Flooding for Heavy Oil Recovery and CO₂ Sequestration

by Yishu Li, Yufeng Cao, Yiming Chen and Fanhua Zeng

Energies 2025, 18(17), 4663; https://doi.org/10.3390/en18174663 - 2 Sep 2025

Viewed by 1016

Abstract

Cyclic solvent injection (CSI) with CO₂ is a promising non-thermal enhanced oil recovery (EOR) method for heavy oil reservoirs that also supports CO₂ sequestration. However, its effectiveness is limited by short foamy oil flow durations and low CO₂ utilization. This study explores how waterflooding and nanoparticle-assisted flooding can enhance CO₂-CSI performance through experimental and numerical approaches. Three sandpack experiments were conducted: (1) a baseline CO₂-CSI process, (2) a waterflood-assisted CSI process, and (3) a hybrid sequence integrating CSI, waterflooding, and nanoparticle flooding. The results show that waterflooding prior to CSI increased oil recovery from 30.9% to 38.9% under high-pressure conditions and from 26.9% to 28.8% under low pressure, while also extending production duration. When normalized to the oil saturation at the start of CSI, the Effective Recovery Index (ERI) increased significantly, confirming improved per-unit recovery efficiency, while nanoparticle flooding further contributed an additional 5.9% recovery by stabilizing CO₂ foam. The CO₂-CSI process achieved a maximum CO₂ sequestration rate of up to 5.8% per cycle, which exhibited a positive correlation with oil production. Numerical simulation achieved satisfactory history matching and captured key trends such as changes in relative permeability and gas saturation. Overall, the integrated CSI strategy achieved a total oil recovery factor of approximately 70% and improved CO₂ sequestration efficiency. This work demonstrates that combining waterflooding and nanoparticle injection with CO₂-CSI can enhance both oil recovery and CO₂ sequestration, offering a framework for optimizing low-carbon EOR processes. Full article

(This article belongs to the Special Issue Exploration and Development of Unconventional Oil and Gas Resources: Latest Advances and Prospects: 3rd Edition)

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12 pages, 1804 KB

Open AccessArticle

Evaluation Method of Gas Production in Shale Gas Reservoirs in Jiaoshiban Block, Fuling Gas Field

by Haitao Rao, Wenrui Shi and Shuoliang Wang

Energies 2025, 18(14), 3817; https://doi.org/10.3390/en18143817 - 17 Jul 2025

Cited by 1 | Viewed by 709

Abstract

The gas-production potential of shale gas is a comprehensive evaluation metric that assesses the reservoir quality, gas-content properties, and gas-production capacity. Currently, the evaluation of gas-production potential is generally conducted through qualitative comparisons of relevant parameters, which can lead to multiple solutions and make it difficult to establish a comprehensive evaluation index. This paper introduces a gas-production potential evaluation method based on the Analytic Hierarchy Process (AHP). It uses judgment matrices to analyze key parameters such as gas content, brittleness index, total organic carbon content, the length of high-quality gas-layer horizontal sections, porosity, gas saturation, formation pressure, and formation density. By integrating fuzzy mathematics, a mathematical model for gas-production potential is established, and corresponding gas-production levels are defined. The model categorizes gas-production potential into four levels: when the gas-production index exceeds 0.65, it is classified as a super-high-production well; when the gas-production index is between 0.45 and 0.65, it is classified as a high-production well; when the gas-production index is between 0.35 and 0.45, it is classified as a medium-production well; and when the gas-production index is below 0.35, it is classified as a low-production well. Field applications have shown that this model can accurately predict the gas-production potential of shale gas wells, showing a strong correlation with the unobstructed flow rate of gas wells, and demonstrating broad applicability. Full article

(This article belongs to the Special Issue Exploration and Development of Unconventional Oil and Gas Resources: Latest Advances and Prospects: 3rd Edition)

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36 pages, 23546 KB

Open AccessArticle

Tight Sandstone Gas Reservoir Types and Formation Mechanisms in the Second Member of the Xujiahe Formation in the Anyue Area, Sichuan Basin

by Lin Jiang, Xuezhen Sun, Dongxia Chen, Wenzhi Lei, Hanxuan Yang, Yani Deng, Zhenhua Wang, Chenghai Li, Tian Liu, Chao Geng, Tian Gao and Zhipeng Ou

Energies 2025, 18(12), 3009; https://doi.org/10.3390/en18123009 - 6 Jun 2025

Cited by 4 | Viewed by 1831

Abstract

With the advancement of oil and gas exploration and development, tight sandstone gas has become a major current exploration field. However, the effective development of tight sandstone gas faces significant challenges due to the strong heterogeneity of tight sandstone reservoirs, diverse reservoir types, complex pore structures, and unclear understanding of reservoir formation mechanisms, which brings great difficulties. Clarifying the types and formation mechanisms of tight sandstone reservoirs is vital for guiding oil and gas exploration and development. This study investigates the characteristics, types, and formation mechanisms of tight sandstone gas reservoirs in the Xujiahe Formation (T₃X₂) of the Anyue area using core observation, cast thin-section identification, scanning electron microscopy, high pressure mercury intrusion, nuclear magnetic resonance, and other experimental methods. It defines the physical property lower limit of T₃X₂ reservoirs in Anyue, classifies reservoir types, elaborates on the basic characteristics of each type, and analyzes their genetic mechanisms. The results show that T₃X₂ reservoirs in the Anyue area can be divided into four types. Sedimentary, diagenetic, and tectonic processes are identified as the primary factors controlling reservoir quality, governing the formation mechanisms of different reservoir types. Based on these findings, a reservoir formation mechanism model for T₃X₂ reservoirs in the Anyue area is established, providing an important basis for subsequent oil and gas exploration and development in the region. Full article

(This article belongs to the Special Issue Exploration and Development of Unconventional Oil and Gas Resources: Latest Advances and Prospects: 3rd Edition)

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19 pages, 7278 KB

Open AccessArticle

Enrichment Geological Conditions and Resource Evaluation Methods for the Gas in Thinly Interbedded Coal Measures: A Case Study of the Chengzihe Formation in the Jixi Basin

by Jiangpeng Guo, Shu Tao, Caiqin Bi, Yi Cui, Bin Yu and Yijie Wen

Energies 2025, 18(10), 2584; https://doi.org/10.3390/en18102584 - 16 May 2025

Cited by 1 | Viewed by 789

Abstract

The Cretaceous Chengzihe Formation in the Jixi Basin hosts abundant coal measure gas resources. Analyzing the geological conditions for gas enrichment and evaluating its resource potential are essential for advancing unconventional gas exploration. However, studies on the geological conditions controlling the enrichment of thinly interbedded coal measure reservoirs in the Chengzihe Formation and corresponding assessment methods remain lacking. Based on the analysis of source–reservoir–seal characteristics of the thinly interbedded coal measure gas system in the Jixi Basin, integrated with resource assessment and reservoir formation controls, this study systematically reveals the enrichment patterns and accumulation mechanisms. The results show that the accumulation of thinly interbedded coal measure gas depends on three key geological factors: the gas-generating capacity of high-quality source rocks, the widespread distribution and stacking of thinly interbedded reservoirs, and the sealing capacity of cap rocks. In addition, enrichment is influenced by multiple factors, including tectonic evolution history, magmatic intrusion, sedimentary microfacies, and hydrogeological processes. Among these, the development of sedimentary microfacies (interdistributary bay and peat swamp) plays a decisive role in controlling the spatial distribution and physical properties of the reservoirs, while other factors further shape gas enrichment through synergistic interactions. Finally, using the volumetric method, the estimated gas resources of thinly interbedded coal measure gas in the Chengzihe Formation are 1226.73 × 10⁸ m³, with the upper member showing significant potential of 688.98 × 10⁸ m³. Full article

(This article belongs to the Special Issue Exploration and Development of Unconventional Oil and Gas Resources: Latest Advances and Prospects: 3rd Edition)

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17 pages, 3398 KB

Open AccessArticle

Multilayer Gas-Bearing System and Productivity Characteristics in Carboniferous–Permian Tight Sandstones: Taking the Daning–Jixian Block, Eastern Ordos Basin, as an Example

by Ming Chen, Bo Wang, Haonian Tian, Junyi Sun, Lei Liu, Xing Liang, Benliang Chen, Baoshi Yu and Zhuo Zhang

Energies 2025, 18(9), 2398; https://doi.org/10.3390/en18092398 - 7 May 2025

Cited by 3 | Viewed by 887

Abstract

The Carboniferous–Permian strata in the Daning–Jixian Block, located on the eastern edge of the Ordos Basin, host multiple sets of tight gas reservoirs. However, systematic research on the characteristics and gas production differences of multilayer tight sandstone gas-bearing systems remains limited. Based on geochemical signatures, reservoir pressure coefficients, and sequence stratigraphy, the tight sandstone gas systems are subdivided into upper and lower systems, separated by regionally extensive Taiyuan Formation limestone. The upper system is further partitioned into four subsystems. Depositional variability from the Benxi Formation to the He 8 Member has generated diverse litho-mineralogical characteristics. The Shan 1 and He 8 Members, deposited in low-energy delta-front subaqueous distributary channels with gentle topography, exhibit lower quartz content (predominantly feldspar lithic sandstone and lithic quartz sand-stone) and elevated lithic fragments, matrix, and clay minerals (particularly chlorite). These factors increase displacement and median pressures, resulting in inferior reservoir quality. By comparing and evaluating the gas production effects under different extraction methods, targeted optimization recommendations are provided to offer both theoretical support and practical guidance for the efficient development of this block. Full article

(This article belongs to the Special Issue Exploration and Development of Unconventional Oil and Gas Resources: Latest Advances and Prospects: 3rd Edition)

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