Integrated 3D Geological Modeling, Stress Field Modeling, and Production Simulation for CBM Development Optimization in Zhengzhuang Block, Southern Qinshui Basin

Zhong Liu, Hui Wang (), Xiuqin Lu, Qianqian Zhang, Yanhui Yang, Tao Zhang, Chen Zhang and Zihan Wang
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Zhong Liu: Petro China Huabei Oilfield Company, Renqiu 062550, China
Hui Wang: School of Emergency Management and Safety Engineering, North China University of Science and Technology, Tangshan 063210, China
Xiuqin Lu: Petro China Huabei Oilfield Company, Renqiu 062550, China
Qianqian Zhang: Petro China Huabei Oilfield Company, Renqiu 062550, China
Yanhui Yang: Petro China Huabei Oilfield Company, Renqiu 062550, China
Tao Zhang: Petro China Huabei Oilfield Company, Renqiu 062550, China
Chen Zhang: Petro China Huabei Oilfield Company, Renqiu 062550, China
Zihan Wang: Petro China Huabei Oilfield Company, Renqiu 062550, China

Energies, 2025, vol. 18, issue 10, 1-21

Abstract: The Zhengzhuang Block in the Qinshui Basin is one of the important coalbed methane (CBM) development areas in China. As high-quality CBM resources become depleted, remaining reserves exhibit complex geological characteristics requiring advanced development strategies. In this study, a multidisciplinary workflow integrating 3D geological modeling (94.85 km 2 seismic data, 973 wells), geomechanical stress analysis, and production simulation was developed to optimize development of the Permian No. 3 coal seam. Structural architecture and reservoir heterogeneity were characterized through Petrel-based modeling, while finite-element analysis identified stress anisotropy with favorable stimulation zones concentrated in southwestern sectors. Computer Modeling Group (CMG) simulations of a 27-well group revealed a rapid initial pressure decline followed by a stabilization phase. A weighted multi-criteria evaluation framework classified resources into three tiers: type I (southwestern sector: 28–33.5 m 3 /t residual gas content, 0.8–1.0 mD permeability, 8–12% porosity), type II (northern/central: 20–26 m 3 /t residual gas content, 0.5–0.6 mD permeability, 5–8% porosity), and type III (<20 m 3 /t residual gas content, <0.4 mD permeability, <4% porosity). The integrated methodology provides a technical foundation for optimizing well patterns, enhancing hydraulic fracturing efficacy, and improving residual gas recovery in heterogeneous CBM reservoirs.

Keywords: coalbed methane; geological modeling; stress field modeling; production simulation; reservoir evaluation (search for similar items in EconPapers)
JEL-codes: Q Q0 Q4 Q40 Q41 Q42 Q43 Q47 Q48 Q49 (search for similar items in EconPapers)
Date: 2025
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