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

郑庄区块是沁水盆地重要煤层气（CBM）开发区，优质资源枯竭后剩余储层地质复杂。本文融合 94.85 km² 三维地震、973 口井资料，在 Petrel 平台完成山西组 3 号煤层高分辨率三维地质建模；利用有限元方法建立地应力场模型，识别西南区为压裂有利区；继而采用 CMG-IMEX 建立 27 口井典型井组双孔双渗模型，经历史拟合后评价剩余气分布，并构建权重多指标评价体系，将资源划分为Ⅰ、Ⅱ、Ⅲ三类。研究结果为井网优化、压裂方案及剩余气动用提供了技术依据。

CMG 软件应用情况

• 模块：CMG-IMEX（2021 版）
• 模型：4650 m×4675 m，平面网格 25 m×25 m；纵向 20 层，双孔双渗（DUALPERM）
• 机理：考虑 Langmuir 等温吸附/解吸、气-水两相流动、基质-裂缝间扩散与达西流动耦合
• 拟合：以定井底流压方式对 27 口井 4–5 年产气、产水历史进行自动/手动历史拟合
– 累计产气量最大误差 15.2 %（拟合精度 >84.8 %）
– 累计产水量最大误差 11.6 %（拟合精度 >88.4 %）
• 应用：基于拟合结果提取剩余气饱和度与压力场，用于区块剩余资源潜力评价

结论

  1. 三维地质模型揭示 3 号煤岩相以半亮煤为主，孔隙度 1.3–12 %，渗透率 0.01–1 mD，强非均质受断裂控制。
  2. 地应力场呈显著各向异性（σH/σh 梯度 0.0344/0.0215 MPa/m），西南部为压裂改造有利区。
  3. CMG 历史拟合成功再现早期快速降压、后期稳压规律，中央剩余压力约 3 MPa。
  4. 剩余气 14–33.5 m³/t，集中于西部、东南部构造高部位；多指标评价将区块划分为：
    – Ⅰ类（西南）：高孔渗、高残余气（≥20 m³/t），优先开发；
    – Ⅱ类：中等条件，过渡区；
    – Ⅲ类：低孔渗、低含气，需技术突破。

作者单位：中石油华北油田分公司

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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 km2 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 m3/t residual gas content, 0.8–1.0 mD permeability, 8–12% porosity), type II (northern/central: 20–26 m3/t residual gas content, 0.5–0.6 mD permeability, 5–8% porosity), and type III (<20 m3/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.

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