石油学报 ›› 2014, Vol. 35 ›› Issue (6): 1130-1137.DOI: 10.7623/syxb201406010

• 油田开发 • 上一篇    下一篇

页岩储层裂缝网络延伸模型及其应用

时贤1,2, 程远方1, 蒋恕2, 李友志1, 孙元伟1, 王欣3   

  1. 1. 中国石油大学石油工程学院 山东青岛 266580;
    2. 美国犹他大学能源与地球科学研究院 盐湖城 84108;
    3. 中国石油勘探开发研究院廊坊分院 河北廊坊 300457
  • 收稿日期:2014-05-20 修回日期:2014-09-15 出版日期:2014-11-25 发布日期:2014-10-13
  • 通讯作者: 程远方,男,1964年4月生,1985年毕业于华东石油学院钻井工程专业,2000年获北京科技大学材料科学与工程专业博士学位,现为中国石油大学(华东)石油工程学院教授、博士生导师,主要从事石油工程岩石力学领域的教学和研究工作。Email:yfcheng@upc.edu.cn
  • 作者简介:时 贤,男,1984年5月生,2007年获中国石油大学(华东)学士学位,2014年获中国石油大学(华东)博士学位,现为中国石油大学(华东)博士后,主要从事非常规油气增产机理等方面的研究。Email:xianshiupc@126.com
  • 基金资助:

    教育部长江学者和创新团队发展计划项目(RT1086)和美国犹他大学页岩气开发项目第二期(No.5000-5050593)资助。

Simulation of complex fracture network propagation and its application for shale gas reservoir

Shi Xian1,2, Cheng Yuanfang1, Jiang Shu2, Li Youzhi1, Sun Yuanwei1, Wang Xin3   

  1. 1. College of Petroleum Engineering, China University of Petroleum, Shandong Qingdao 266580, China;
    2. Energy & Geoscience Institute in University of Utah, Salt Lake City UT 84108, U.S.A;
    3. Langfang Branch, PetroChina Research Institute of Petroleum Exploration and Development, Hebei Langfang 300457, China
  • Received:2014-05-20 Revised:2014-09-15 Online:2014-11-25 Published:2014-10-13

摘要:

页岩压裂后水力裂缝与天然裂缝交织形成的复杂裂缝网络无法应用传统基于对称双翼裂缝的压裂模型进行几何参数模拟。借鉴双重介质油藏理论,将页岩改造体积划分为裂缝网格和基质2种介质,假设改造体积为椭球体,提出以主干缝和小尺度次生缝网络构建整个复杂裂缝网络的几何模型。主干缝几何参数以拟三维压裂模型为基础计算,次生缝参数通过椭圆函数进行计算,并对建立的数学模型进行计算分析。通过对美国Piceance页岩盆地储层改造设计的应用,证明了该模型同现场数据吻合较好。模拟结果发现:弹性模量越大,水平应力差越小;压裂液黏度越低,延伸比越大,则整个储层的改造体积越大;水平应力差对储层改造体积结果的影响最为敏感。天然裂缝分布越低,虽然改造体积较为理想,但由于牺牲了裂缝网络的复杂程度,因此有时并不意味着更好的改造效果。该理论成果可为页岩储层水力压裂设计及产能分析提供有效的技术支持。

关键词: 页岩气, 水力压裂, 复杂缝网, 数值模拟, 数学模型

Abstract:

The commercial profit of shale gas is greatly controlled by the enhancement of matrix super-low permeability through effective reservoir volume stimulation. The resultant complex fracture network is composed of hydraulically induced fractures and natural fractures, while classical fracturing model based on the assumption of a symmetrical bi-wing fracture system is inapplicable for simulating relevant geometrical parameters. The stimulated shale volume is divided into fractures and matrix by referring to the theory of dual-media reservoir. This study assumes an elliptical stimulated volume and builds the whole complex fracture network with primary and small-scale secondary fracture networks. Geometrical parameters of primary fractures are computed using pseudo three fracturing model and secondary fracture parameters are simulated using elliptical equation. The mathematic model is programmed and applied for stimulation in Piceance shale gas reservoir in the U.S.A. The simulation data show high consistency with in-situ data. The larger the Young's modulus, the smaller the horizontal stress difference; the lower the viscosity of fracturing fluid, the greater the ratio of elongation, and the larger the simulated volume of the whole reservoir. Horizontal stress difference is most sensitive factor controlling the stimulated reservoir volume. Although sparser distribution of natural fractures means a larger stimulated reservoir volume, the effectiveness of stimulation is doubtful due to sacrificed complexity of the fracture network. This study provides a strong support for fracturing design and production prediction in shale gas reservoirs after fracturing stimulation.

Key words: shale gas, hydraulic fracturing, complex fracture network, numerical simulation, mathematical model

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