Key Factors Affecting Shale Gas and Top Areas to Explore

Jim Crocker
25th May, 2025

Key Factors Affecting Shale Gas and Top Areas to Explore

Analysis of reservoir space types reveals a complex pore network comprising residual and dissolution mineral pores (a–c, h), clay interlayer fractures and microfractures (d, i), and organic-hosted pores (e, f), which collectively provide the essential storage capacity required for shale gas enrichment in the Wufeng–Longmaxi Formations.

Image adapted from: Zou et al. / CC BY (Source)

Key Findings

  • In China's Southern Sichuan Basin, researchers developed a new method combining heat history and geological stresses to better locate shale gas
  • They found that areas with higher organic content and optimal temperatures store more gas, enhancing extraction potential
  • The study identified specific promising zones for gas extraction and highlighted regions at risk of gas leakage
Shale gas has become a crucial energy resource, and understanding its distribution and extraction potential is essential for efficient development. In the Southern Sichuan Basin, the Wufeng-Longmaxi Formations (WF-LMX FM) have emerged as significant targets for shale gas exploration. However, these formations exhibit notable spatial heterogeneity, with gas content varying three to five times across similar strata that meet standard criteria for organic carbon content (TOC > 2.5wt.%) and porosity (>5%). This variation challenges conventional models that typically treat geochemical potential and tectonic preservation dynamics as separate factors, particularly in post-mature shale systems where the vitrinite reflectance (Ro) exceeds 3.0%[1]. Researchers from Southwest Petroleum University, Sichuan University of Science and Engineering, PetroChina Southwest Oil & Gas Field Company, and Hefei University of Technology addressed this issue by developing a comprehensive evaluation framework. This new approach integrates three critical determinants: thermal maturation trajectories, hydrocarbon generation-preservation windows, and the imprint of multi-phase tectonic stress on fracture connectivity. By doing so, the study effectively bridges the gap between geochemical potential and tectonic preservation, providing a more accurate prediction of shale gas distribution. The study's methodology involved a combination of well logs, 3D seismic interpretation, and experimental petrology. These tools were used to analyze five key parameters: Total Organic Carbon (TOC), thermal maturity (Ro), porosity, mineral brittleness, and a preservation potential index (SP). The SP index was particularly innovative, as it quantified the equilibrium between fault throw and erosion rates, calibrated against anomalies in shale bed thickness. This multi-faceted approach allowed for a nuanced understanding of the factors influencing shale gas enrichment. Previous research has laid the groundwork for these findings. For instance, a study on marine shale reservoirs in the same basin demonstrated that deep shale possesses complex pore structures and that porosity is positively correlated with TOC, siliceous minerals, and clay minerals[2]. Additionally, research on shale micro pore-fracture characteristics highlighted the importance of organic content and thermal evolution in pore development[3]. The current study builds on these insights by incorporating thermal maturation and tectonic stress factors, thereby providing a more holistic view of shale gas reservoirs. One of the key revelations of this study is the need to recalibrate the thresholds for optimal hydrocarbon enrichment. Specifically, the research suggests increasing the TOC threshold to greater than 4.0wt.% in high-maturity regimes. This adjustment redefines the hydrocarbon potential by recognizing that higher organic carbon content enhances gas storage capacity and preservation. Furthermore, the study identifies a thermal maturity window of 3.0-4.0% Ro, which balances the development of organic porosity with the potential for carbon deposition that can occlude gas storage sites. Porosity also plays a critical role in reservoir viability. The study found that effective gas storage requires porosity levels above 4.5%, while maintaining over 40% brittle minerals is essential for sustaining fractures that facilitate gas flow. These findings align with earlier research that emphasized the importance of pore structure and mineral composition in shale gas reservoirs[2][3]. By integrating these parameters, the study provides a clearer picture of the conditions necessary for successful shale gas extraction. The preservation potential index (SP) introduced in this research is a significant advancement. It accounts for the effects of erosion and fault connectivity, identifying areas where shale gas is more likely to be preserved. The analysis revealed two critical risk zones near the Changning anticline and northern Luzhou. In these areas, neotectonic fault reactivation can disrupt the maintenance of overpressure, which is vital for retaining gas within the shale. Understanding these risk zones allows for more targeted and effective exploration strategies, minimizing the chances of encountering depleted or non-productive areas. Moreover, the study identified two strategic exploration targets based on the spatial synthesis of the evaluated parameters. The first target is the NW-SE trending Jianwu-Weiyuan slope system, which exhibits an optimal thermal-structural synergy conducive to shale gas preservation and extraction. The second target is the Luzhou northern anticlinal cluster, where fault sealing effectively maintains preservation efficacy. These targets are chosen based on their favorable conditions as defined by the integrated evaluation framework, demonstrating the practical applicability of the study’s findings. Incorporating earlier studies, this research not only supports but also expands on existing knowledge of shale gas reservoirs. For example, the identification of organic matter pores and their contribution to overall porosity in deep shales, as discussed in prior research[2][3], is further validated and integrated into a broader framework that includes thermal and tectonic factors. This comprehensive approach allows for a more accurate prediction of gas content and reservoir quality, addressing the spatial heterogeneity observed in the Southern Sichuan Basin. The implications of this study are far-reaching for the field of shale gas exploration. By resolving the “geochemical preservation paradox” through dynamic process coupling, the research provides a transformative paradigm for deep shale gas exploration in thrust-fold terrains. This new model enhances the ability to predict gas distribution accurately, ultimately leading to more efficient and economically viable extraction practices. In conclusion, the pioneering framework developed by the research team from Southwest Petroleum University and collaborating institutions represents a significant advancement in shale gas exploration. By integrating thermal maturation, hydrocarbon preservation, and tectonic stress factors, the study offers a robust solution to the challenges posed by spatial heterogeneity in the Wufeng-Longmaxi Formations. This comprehensive approach not only builds on previous scientific findings but also sets a new standard for future research and exploration strategies in similar geological settings.

EnvironmentSustainabilityEcology

References

Main Study

1) Controlling factors for shale gas enrichment and their implications for favorable exploration areas: Insights from the Wufeng–Longmaxi Formations, Southern Sichuan, China

Published 23rd May, 2025

https://doi.org/10.1371/journal.pone.0323277

Related Studies

2) Shale pore characteristics and their impact on the gas-bearing properties of the Longmaxi Formation in the Luzhou area.

https://doi.org/10.1038/s41598-024-66759-7

3) Characteristics and main controlling factors for the development of shale micro pore-fracture in Tiemulike Formation, Yining Basin.

https://doi.org/10.1038/s41598-024-81804-1


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