A Dual-Lattice Discrete Element Model to Understand Hydraulic Fracturing in a Naturally Fractured System
- Idaho National Lab. (INL), Idaho Falls, ID (United States). Center for Advanced Energy Studies
- Univ. of Utah, Salt Lake City, UT (United States). Dept. of Chemical Engineering
- Temple Univ., Philadelphia, PA (United States). Dept. of Physics
Interaction between hydraulic fractures (HF) and natural fractures (NF) may lead to complex fracture networks as a consequence of branching and merging of the natural and hydraulically-induced/reopened fractures. Conventional simulation methods, with assumptions of homogeneous and continuous media, are not able to capture realistic fracture patterns in the presence of pre-existing natural fractures (open or healed). These natural discontinuities alter the local stress field and impact the fracturing fluid pressure distribution when hydraulically-driven fractures approach natural discontinuities. Modeling the propagation of one or more propagating hydraulic fractures in naturally fractured reservoirs should carefully consider the complex mechanical and hydraulic interactions between hydraulically-driven and natural fractures. A rigorous hydraulic fracturing model based on a coupled discrete element method (DEM) and conjugate network flow model is described in this work. The coupled DEM-network flow model conveniently accounts for both continuous poroelasticity and discrete natural fractures simultaneously and provides more realistic fracture growth patterns in low-permeability rocks. This dual lattice DEM-network flow model can capture both tension-induced rock failure and shear-induced natural discontinuity sliding and dilation. Simulation results revealed that reactivation of natural fractures becomes more difficult when the following conditions are present: larger magnitude of stress difference, higher intercepting angle between the natural fracture and the propagating hydraulic fracture (higher implies more orthogonal to the natural fracture), larger natural fracture cohesion and angle of internal friction and/or lower natural fracture permeability - leading to continued growth of the hydraulic fracture. The term stress difference was colloquially used in the preceding sentence. For clarity, we will define this as ΔS = SH,max – Sh,min). The quantitative results of numerous simulations reinforced the intuitive understanding of the underlying phenomena. Other simulations reinforced insights from laboratory experimentation and field measurements that lower injection rates and treating fluid viscosities facilitate preferential fluid intake into natural fractures. Finally, this simulation capability for predicting the nature of complex fracture networks potentially enables optimizing treatment design and completion strategy in naturally fractured reservoirs.
- Research Organization:
- Idaho National Lab. (INL), Idaho Falls, ID (United States); Univ. of Utah, Salt Lake City, UT (United States)
- Sponsoring Organization:
- USDOE
- Grant/Contract Number:
- AC07-05ID14517
- OSTI ID:
- 1469322
- Report Number(s):
- INL/JOU-16-38144-Rev000
- Journal Information:
- Hydraulic Fracturing Journal, Vol. 4, Issue 2; ISSN 2373-8197
- Publisher:
- PetrodomainCopyright Statement
- Country of Publication:
- United States
- Language:
- English
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