Evolution of natural fracture stability in middle-deep shale reservoirs

doi:10.3969/j.issn.2096-1693.2026.01.005

Abstract

Abstract:

Natural fractures in middle-deep shale reservoirs experience continuous stress evolution under the combined influence of hydraulic stimulation and long-term production. Their stability evolution critically affects wellbore integrity, stimulation effectiveness, and the safety of infill-well deployment. Focusing exclusively on natural fractures, this study develops a stability evaluation framework by coupling a 3D geomechanical model with a discrete fracture network (DFN). The approach maps the strike and dip of natural fractures onto the 3D grid and constructs a spatially continuous fracture-orientation volume through geostatistical interpolation. This enables the unified coupling of natural fracture geometry with the regional 3D stress field and rock mechanical attributes, providing a continuous 3D quantification of natural-fracture stability. Results show that natural-fracture slip risk is governed by the combined effects of fracture orientation and tectonic stress regime, with distinct high-risk orientations under normal-faulting, strike-slip, and reverse-faulting conditions. Fluid injection may trigger natural-fracture instability through reduced effective normal stress and lowered frictional strength, whereas long-term production enhances effective stress and generally improves natural-fracture stability. In the YS108 block, the stress regime evolves toward a typical normal-faulting state after nearly ten years of production, leading to significantly reduced slip risk of natural fractures. The proposed 3D evaluation framework provides a practical basis for post-production stability assessment, well-trajectory optimization, and stimulation-risk management in middle-deep shale reservoirs.

Key words: unconventional oil and gas, natural fractures, instability risk, in-situ stress field evolution, infill well deployment

摘要：

中深层页岩储层长期处于压裂改造及多年生产的复合作用下，天然裂缝的应力状态不断演化，其稳定性变化直接关系到井筒完整性、压裂改造效果及加密井部署安全性。鉴于此，本文以天然裂缝为研究对象，提出一种基于三维地质力学模型—离散裂缝网络(DFN)耦合的天然裂缝稳定性评价方法，不涉及水力裂缝的形态与演化。通过将天然裂缝走向、倾角粗化映射至三维网格，并采用空间插值构建产状连续体，实现了天然裂缝几何特征与三维应力场、力学参数的统一耦合，从而获得天然裂缝稳定性的三维连续量化结果。研究结果表明：天然裂缝滑动风险受走向、倾角与区域应力状态的耦合作用控制，各应力状态下的失稳产状具有显著差异；流体注入可能通过“有效正应力降低”与“摩擦强度下降”两条机制诱发天然裂缝失稳；而长期生产导致孔隙压力下降，可增强天然裂缝的有效正应力，整体提升裂缝稳定性。对黄金坝YS108井区的研究表明，产后应力场向典型正断层状态演化，使天然裂缝滑动风险明显降低，为加密井部署及安全压裂提供了更高的稳定性基础。本文提出的三维天然裂缝稳定性评价体系可用于老区产后地层稳定性识别、井轨迹优化及压裂段风险控制，为中深层页岩气高效开发提供技术支撑。

关键词: 非常规油气, 天然裂缝, 失稳风险, 地应力场演化, 加密井部署

CLC Number:

TE37
P618.13

ZHANG Muyang, ZHOU Kairui, LI Caoxiong, CUI Huan, YUAN Xiaojun, SU Zhanhong, XIAN Chenggang. Evolution of natural fracture stability in middle-deep shale reservoirs[J]. Petroleum Science Bulletin, 2026, 11(1): 99-113.

张木杨, 周恺锐, 李曹雄, 崔欢, 袁晓俊, 苏展鸿, 鲜成钢. 中深层页岩储层天然裂缝稳定性演化规律研究[J]. 石油科学通报, 2026, 11(1): 99-113.

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URL: https://sykxtb.cup.edu.cn/EN/10.3969/j.issn.2096-1693.2026.01.005

https://sykxtb.cup.edu.cn/EN/Y2026/V11/I1/99

Figures/Tables 17

Fig. 1 Technical workflow for instability risk assessment based on geomechanical-discrete fracture network (DFN) coupling

Fig. 2 Workflow for coordinate transformation in fracture plane stress calculations

Table 1 Basis for stress state classification

应力状态	最大主应力S₁	中间主应力S₂	最小主应力S₃
正断层(NF)	S_v	S_hmax	S_hmin
走滑断层(SS)	S_hmax	S_v	S_hmin
逆断层(RF)	S_hmax	S_hmin	S_v

Table 2 The parameter values of the coordinate transformation matrix

参数	正断层(NF)	走滑断层(SS)	逆断层(RF)
α	Azi_S_hmin	Azi_S_hmax	Azi_S_hmax
γ	90°	0°	0°
β	0°	90°	0°

Fig. 3 Schematic diagram of natural fracture instability risk assessment

Fig. 4 Relative error of natural fracture slip risk in 2D/3D under varying stress states

Fig. 5 Coupled effects of fracture orientation on sliding risk under different stress regimes

Fig. 6 Dual-path fracture instability modes

Fig. 7 Formation pressure variations at the H4 platform and adjacent regions pre- and post-production

Fig. 8 Variation of formation stress states at the H4 platform and adjacent regions pre- and post-production

Fig. 9 Schematic of stress changes for a single fracture pre- and post-production

Fig. 10 Spatial distribution and geometry of natural fractures at the H4 platform

Fig. 11 Three-dimensional sliding risk volume and critical injection pressure volume

Fig. 12 Correlation of borehole quality parameters and slip risk in Well H4-2

Fig. 13 Plan view of sliding risk volume and critical injection pressure

Fig. 14 Relationship between sliding risk, critical injection pressure, and natural fracture orientations

Fig. 15 Distribution of along-well slip risk and critical injection pressure for infill wells

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