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Peer-reviewedCC BY-NC-ND 4.0ACS Omega

Characterization of Macro-Micro Heterogeneity in Shale Reservoirs Based on Full-Diameter Core CT Scanning─A Case Study of Jurassic Lianggaoshan Formation Shale in Well Ping’an 3, Sichuan Basin

  • Jiping Wang1,2,3,4
  • Bo Gao1,2,3
  • Binhui Li1,2,3
  • Hu Wangshui5
  • Huifang Pan1,2,3
  • Lingling Li1,2,3
  • Tangyu Wang1,2,3
  • Xi Cao1,2,3
  • Yu Ma1,2,3
5 affiliations
  1. 1State Key Laboratory of Continental Shale Oil , ,
  2. 2Daqing Oilfield , , ,
  3. 3Heilongjiang Provincial Key Laboratory of Continental Shale Oil , ,
  4. 4Northeast Petroleum University , ,
  5. 5Yangtze University , ,
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Abstract

Continental shale reservoirs exhibit strong vertical heterogeneity in lamellar fracture development and pore–fracture systems, yet continuous core-scale characterization remains limited. This study presents a hierarchical characterization of four Jurassic Lianggaoshan Formation intervals from Well Ping’an 3, Sichuan Basin, based on full-diameter core computed tomography (CT) scanning combined with convolutional neural network (CNN)-based image segmentation, 3D reconstruction, and pore-scale seepage simulation. The results show that (1) reservoir heterogeneity increases vertically from siltstone to shale intervals, with average lamina/interlayer volume percentages of 11.12%–12.81% and lamina densities of 130–2185 strips/m in shale intervals; (2) lamellar fractures predominantly develop along bedding interfaces, with average fracture porosity of 0.4%–0.7% and strong vertical heterogeneity; (3) within the CT resolution limit, pore–fracture seepage assemblages are classified into pore-dominated, transitional, and fracture-dominated types, with reservoir connectivity jointly influenced by fracture density, aperture, and matrix pore coupling. This study provides a continuous macro–micro integrated characterization workflow for micron-scale pore–fracture features at the CT-resolvable scale (>150 μm), bridging the gap between plug-scale microanalysis and interval-scale geological evaluation. The nanopore system requires complementary methods such as scanning electron microscopy (SEM) and mercury intrusion capillary pressure (MICP) for full characterization.

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Cite

BibTeXRIS
BibTeX
@article{wang2026characterization,
  title = {{Characterization of Macro-Micro Heterogeneity in Shale Reservoirs Based on Full-Diameter Core CT Scanning─A Case Study of Jurassic Lianggaoshan Formation Shale in Well Ping’an 3, Sichuan Basin}},
  author = {Jiping Wang and Bo Gao and Binhui Li and Hu Wangshui and Huifang Pan and Lingling Li and Tangyu Wang and Xi Cao and Yu Ma},
  journal = {ACS Omega},
  year = {2026},
  month = oct,
  doi = {10.1021/acsomega.6c04701},
  url = {https://pubs.acs.org/acsodf/article/doi/10.1021/acsomega.6c04701/5455936/Characterization-of-Macro-Micro-Heterogeneity-in},
  note = {CC BY-NC-ND 4.0},
}
RIS
TY  - JOUR
TI  - Characterization of Macro-Micro Heterogeneity in Shale Reservoirs Based on Full-Diameter Core CT Scanning─A Case Study of Jurassic Lianggaoshan Formation Shale in Well Ping’an 3, Sichuan Basin
AU  - Jiping Wang
AU  - Bo Gao
AU  - Binhui Li
AU  - Hu Wangshui
AU  - Huifang Pan
AU  - Lingling Li
AU  - Tangyu Wang
AU  - Xi Cao
AU  - Yu Ma
PY  - 2026
DA  - 2026/10/22
JO  - ACS Omega
DO  - 10.1021/acsomega.6c04701
UR  - https://pubs.acs.org/acsodf/article/doi/10.1021/acsomega.6c04701/5455936/Characterization-of-Macro-Micro-Heterogeneity-in
AB  - Continental shale reservoirs exhibit strong vertical heterogeneity in lamellar fracture development and pore–fracture systems, yet continuous core-scale characterization remains limited. This study presents a hierarchical characterization of four Jurassic Lianggaoshan Formation intervals from Well Ping’an 3, Sichuan Basin, based on full-diameter core computed tomography (CT) scanning combined with convolutional neural network (CNN)-based image segmentation, 3D reconstruction, and pore-scale seepage simulation. The results show that (1) reservoir heterogeneity increases vertically from siltstone to shale intervals, with average lamina/interlayer volume percentages of 11.12%–12.81% and lamina densities of 130–2185 strips/m in shale intervals; (2) lamellar fractures predominantly develop along bedding interfaces, with average fracture porosity of 0.4%–0.7% and strong vertical heterogeneity; (3) within the CT resolution limit, pore–fracture seepage assemblages are classified into pore-dominated, transitional, and fracture-dominated types, with reservoir connectivity jointly influenced by fracture density, aperture, and matrix pore coupling. This study provides a continuous macro–micro integrated characterization workflow for micron-scale pore–fracture features at the CT-resolvable scale (>150 μm), bridging the gap between plug-scale microanalysis and interval-scale geological evaluation. The nanopore system requires complementary methods such as scanning electron microscopy (SEM) and mercury intrusion capillary pressure (MICP) for full characterization.
SN  - 2470-1343
ER  -