Scholarlink

<p>Self-propping phase-transition fracturing has emerged as a cost-effective and environmentally friendly approach for developing unconventional resources in a carbon-constrained world. The process involves injecting a Phase-transition Fracturing Fluid System, composed of Phase-transition Fluid and Non-Phase-transition Fluid, into the reservoir. The Phase-transition Fluid undergoes a temperature-induced phase transition to generate In-situ Generated Proppant, which supports the fractures. The Non-Phase-transition Fluid occupies the remaining space and, after flow back, creates high-permeability channels for oil and gas flow, thereby enhancing long-term fracture conductivity. Unlike conventional fracturing, this technology involves multi-field coupling between two-phase flow and mechanical interactions of solid particles and fracture surfaces. However, existing modeling approaches often fail to capture the dynamic coupling of fluid distribution, rock deformation, and in-situ proppant behavior, particularly under complex loading and multiphase flow conditions. This gap hinders a quantitative understanding of conductivity evolution in such systems. To address this issue, a mathematical model was developed that integrates two-phase flow in fractures, rock deformation, and particle–fracture interactions. A coupling algorithm—Discretized Virtual Internal Bonds, Element Partition Method, and Finite Volume Method—was proposed, validated, and applied to a field case. The results demonstrate improved computational efficiency and reduced model complexity. The optimal injection mode involves initiating fractures with conventional fluid, propping with Phase-transition Fracturing Fluid System, and displacing with clean fluid, resulting in longer and more conductive fractures. At low closure stress (&lt; 20&#xa0;MPa), fracture conductivity decreases with increasing Phase-transition Fluid volume fraction; at high closure stress (≥ 30&#xa0;MPa), the trend reverses. Higher displacement shortens injection time, reduces fluid leak-off, and promotes wider, more conductive fractures. These findings provide quantitative insights into conductivity evolution and offer practical guidance for optimizing Self-propping phase-transition fracturing treatment design.</p>

错误：搜索内容不能为空，请输入英文关键词
错误：关键词超出字数限制，请精简
高级检索

Revealing Hydraulic Fracture Geometry and Conductivity in Self-propping Phase-Transition Fracturing with a New Coupling Model for Low-Carbon Development of Unconventional Resources

  • 期刊论文

  • 发表日期：

    2025年10月6日

查看全文
  • Nanlin Zhang,
  • Fushen Liu,
  • Liangliang Jiang

摘要

Self-propping phase-transition fracturing has emerged as a cost-effective and environmentally friendly approach for developing unconventional resources in a carbon-constrained world. The process involves injecting a Phase-transition Fracturing Fluid System, composed of Phase-transition Fluid and Non-Phase-transition Fluid, into the reservoir. The Phase-transition Fluid undergoes a temperature-induced phase transition to generate In-situ Generated Proppant, which supports the fractures. The Non-Phase-transition Fluid occupies the remaining space and, after flow back, creates high-permeability channels for oil and gas flow, thereby enhancing long-term fracture conductivity. Unlike conventional fracturing, this technology involves multi-field coupling between two-phase flow and mechanical interactions of solid particles and fracture surfaces. However, existing modeling approaches often fail to capture the dynamic coupling of fluid distribution, rock deformation, and in-situ proppant behavior, particularly under complex loading and multiphase flow conditions. This gap hinders a quantitative understanding of conductivity evolution in such systems. To address this issue, a mathematical model was developed that integrates two-phase flow in fractures, rock deformation, and particle–fracture interactions. A coupling algorithm—Discretized Virtual Internal Bonds, Element Partition Method, and Finite Volume Method—was proposed, validated, and applied to a field case. The results demonstrate improved computational efficiency and reduced model complexity. The optimal injection mode involves initiating fractures with conventional fluid, propping with Phase-transition Fracturing Fluid System, and displacing with clean fluid, resulting in longer and more conductive fractures. At low closure stress (< 20 MPa), fracture conductivity decreases with increasing Phase-transition Fluid volume fraction; at high closure stress (≥ 30 MPa), the trend reverses. Higher displacement shortens injection time, reduces fluid leak-off, and promotes wider, more conductive fractures. These findings provide quantitative insights into conductivity evolution and offer practical guidance for optimizing Self-propping phase-transition fracturing treatment design.