Dual-Porosity Flow Diagnostics for Spontaneous Imbibition in Naturally Fractured Reservoirs

We extend single-porosity flow diagnostics to dual-porosity systems using a novel retardation factor R to account for the effect of fracture-matrix transfer on breakthrough times and displacement efficiency during two-phase flow in fractured reservoirs. R is based on an analytical solution for capillary-driven fluid exchange between the fractures and rock matrix. By linearizing R the time-of-flight tau(star) is adjusted to include fracture-matrix transfer and derive new metrics, the dynamic Lorenz coefficient L-c(star) to quantify the dynamic heterogeneity, and the dual-porosity sweep efficiency E-v(star) to estimate how efficiently the injected fluid displaces the reservoir fluid over time. We have tested different formulations of R across three case studies with increasing complexity to analyze the applicability and limitations of dual-porosity flow diagnostics. This analysis reveals that as long as flow in the fractures is faster than fracture-matrix transfer, dual-porosity flow diagnostics provide useful approximations when assessing displacement efficiencies and identifying the wells that are at most and least likely to experience early breakthrough. We show that L-c(star) and E-v(star) can be combined with stochastic optimization algorithms to improve the displacement efficiency in a 3D reservoir case study. Since a single dual-porosity flow diagnostics calculation requires less than 1 min while a full-physics simulation takes 2 h, we can now quickly screen a large parameter space to identify scenarios that need to be studied in more detail using full-physics simulations. Hence, our new dual-porosity flow diagnostics complement and accelerate state-of-the-art uncertainty quantification and optimization workflows for fractured reservoirs.