Triple-Porosity Systems for Representing Naturally Fractured Reservoirs

Abstract

SummaryThis study develops an improved model for analysis of pressure transient tests of naturally fractured reservoirs. The development was prompted by observations of actual well tests that showed anomalous slope changes during the transition period and where the behavior could not be explained by dual-porosity models.Geometrical configurations studied include both the strata model, where horizontal matrix layers are separated by fractures, and the uniformly distributed blocks, which are separated by an orthogonal set of fractures. These systems were assumed to be under gradient flow conditions. In both cases, two separate sets of matrix properties were assumed. The formulation of response was solved semianalytically. The solutions included the earlytime effects of both the afterflow and skin.Observations made from the theoretical predictions are that the fracture-controlled early times and portions of the transition period will resemble the behavior of a dual-porosity system. The latter part of the transition zone, however, exhibits slope changes; the duration is a function of λ1/λ2 (ratio of interporosity flow coefficients for the two matrix types) and ω1/ω2 (ratio of fluid capacitance coefficients).A correlation developed on the basis of numerous sensitivity runs allows the estimation of ω1/ω2 and λ1/λ2 with the times that correspond to the onset of anomalous slope changes. Because an infinite-acting slope may develop before the matrix blocks of the lowest λ show their existence during the anomalous slope changes, recognition of the various matrix properties emphasized in this study will also safeguard against extrapolation of incorrect late-time curves.