Rapid multistage hydraulic fracture design and optimization in unconventional reservoirs using a novel Fast Marching Method

Abstract

Multi-stage hydraulic fracturing in horizontal wells is a crucial technology driving the economic production from unconventional resources. Multi-stage transverse fracture treatments provide significant reservoir stimulation, but recent industry study estimates that as high as one third fracture clusters are not performing as expected. This is due to the complexity of the fracture and reservoir characteristics and large number of possible design variables, such as the number of transverse fracture stages, the fracture spacing, horizontal well length, proppant concentration, and the fluid and proppant injection history. A systematic and efficient fracture design procedure is needed to provide a more optimal design.This paper focuses on the optimization of the number of fracture stages, their spacing, and the allocation of proppant during multistage hydraulic fracturing. Our optimization will rely on a novel approach for drainage volume calculations using a Fast Marching Method (FMM). The FMM is a recently introduced method that relies on a high frequency asymptotic solution of the diffusivity equation to extend the concept of depth of investigation to heterogeneous and fractured media. The approach has been shown to be computationally efficient, physically intuitive and can rigorously account for the interactions between the hydraulic and natural fractures during the computation of drainage volume. Our optimization approach will attempt to maximize the Net Present Value (NPV) from the engineering perspective, by selecting the optimal number and placement of fracture stages.Optimum fracture spacing need not necessarily be uniformly distributed along the horizontal wellbore, especially when prior reservoir properties, for example natural fracture density, are available from well logs and other sources. A systematic and efficient approach to fracture design will be demonstrated, constrained by long-term well performance while accounting for specific economic parameters. The power and practical utility of the proposed approach is demonstrated using a three-dimensional synthetic example. We find that there are an optimum number of fracture stages for a given reservoir. If adequate geological, geophysical, and engineering data are available to estimate reservoir heterogeneity before hydraulic fracturing, fracturing spacing can be further optimized instead of evenly spaced. If there is uncertainty associated with reservoir heterogeneity, multiple realizations can be integrated in the proposed optimization workflow.