The Relationship Between Fracture Complexity, Reservoir Properties, and Fracture-Treatment Design

Summary In many reservoirs, fracture growth may be complex because of the interaction of the hydraulic fracture with natural fractures, fissures, and other geologic heterogeneities. The decision whether to control or exploit fracture complexity has significant impact on fracture design and well performance. This paper investigates fracture-treatment-design issues as they relate to various degrees and types of fracture complexity (i.e., complex planar fractures and network fracture behavior), focusing on fracture-conductivity requirements for complex fractures. The paper includes general guidelines for treatment design when fracture growth is complex, including criteria for the application of water-fracs, hybrid fracs, and crosslinked fluids. The effect of proppant distribution on gas-well performance is examined for cases when fracture growth is complex, assuming that proppant was either concentrated in a primary planar fracture or evenly distributed in a fracture network. Examples are presented that show that when fracture growth is complex, the average proppant concentration will likely be too low to materially impact well performance if proppant is evenly distributed in the fracture network and unpropped-fracture conductivity will control gas production. Reservoir simulations illustrate that the network-fracture conductivity required to maximize production is proportional to the square root of fracture spacing, indicating that increasing fracture complexity will reduce conductivity requirements. The reservoir simulations show that fracture-conductivity requirements are proportional k1/2 for small networks and k1/4 for large networks, indicating much higher conductivity requirements for low-permeability reservoirs than would be predicted using classical dimensionless conductivity calculations (FCD) where conductivity requirements are proportionate to reservoir permeability (k). The results show that when fracture growth is complex, proppant distribution will have a significant impact on network-conductivity requirement and well performance. If an infinite-conductivity primary fracture can be created, network-fracture-conductivity requirements are reduced by a factor of 10 to 100, depending on the size of the network. The decision to exploit or control fracture complexity depends on reservoir permeability, the degree of fracture complexity, and unpropped-fracture conductivity. It can be beneficial to exploit fracture complexity when the permeability is on the order of 0.0001 md by generating large fracture networks using low-viscosity fluids (water fracs). As reservoir permeability approaches 0.01 md, fluid efficiency decreases, and fracture-conductivity requirements increase, fracture designs can be tailored to generate small networks with improved conductivity using medium-viscosity or multiple fluids (hybrid fracs). Fracture complexity should be controlled using high-viscosity fluids, and fracture conductivity should be optimized for moderate-permeability reservoirs, on the order of 1 md.