Abstract

The flow properties of naturally fractured reservoirs are dominated by flow through the fractures. In a previous study we showed that even a well-connected fracture network behaves like a much sparser network when the aperture distribution is broad enough: i.e., most fractures can be eliminated while leaving a sub-network with virtually the same permeability as the original fracture network. In this study, we focus on the influence of eliminating unimportant fractures which carry little flow on the inferred characteristic matrix-block size. We model a two-dimensional fractured reservoir in which the fractures are well-connected. The fractures obey a power-law length distribution, as observed in natural fracture networks. For the aperture distribution, because information from the subsurface is limited, we test a number of cases: log-normal distributions (from narrow to broad), and power-law distributions (from narrow to broad). The matrix blocks in fractured reservoirs are of varying sizes and shapes; we adopt the characteristic radius and the characteristic length to represent the characteristic matrix-block size. We show how the characteristic matrix-block sizes increase from the original fracture network to the dominant sub-network. This suggests that the matrix-block size, or shape factor, used in dual-porosity/dual-permeability waterflood or enhanced oil recovery (EOR) simulations or in homogenization should be based not on the entire fracture population but on the sub-network that carries almost all of the injected fluid (water or EOR agent).

Highlights

  • Fractured reservoirs contain a significant amount of hydrocarbon reserves worldwide [1], the oil recovery from these reservoirs has been rather low

  • In the dualporosity/dual-permeability approach, the fracture and matrix systems are treated as separate domains; interconnected fractures serve as fluid flow paths between injection and production wells, while the matrix acts only as fluid storage, and these two domains are connected with an exchange term [3,4,5]

  • Even in a well-connected fracture network, injected water does not flow through the entire fracture network; it mainly flows through a dominant sub-network which is strongly affected by the aperture distribution

Read more

Summary

Introduction

Fractured reservoirs contain a significant amount of hydrocarbon reserves worldwide [1], the oil recovery from these reservoirs has been rather low. The low level of oil recovery indicates that more accurate reservoir characterisation and flow simulation is needed. Reservoir simulation is one of the most practical methods of studying flow problems in porous media. The dual-porosity/dual-permeability concept and the discrete fracture model are two typical methods [2]. In the dualporosity/dual-permeability approach, the fracture and matrix systems are treated as separate domains; interconnected fractures serve as fluid flow paths between injection and production wells, while the matrix acts only as fluid storage, and these two domains are connected with an exchange term [3,4,5]. In a dual-permeability model, fluid flow can take place between matrix grid blocks, unlike from the dual-porosity model [6,7].

Methods
Discussion
Conclusion
Full Text
Published version (Free)

Talk to us

Join us for a 30 min session where you can share your feedback and ask us any queries you have

Schedule a call