Condensate blockage effects in well test analysis of dual-porosity/dual-permeability, naturally fractured gas condensate reservoirs: a simulation approach

Fluid flow in gas condensate reservoirs usually exhibit complex flow behavior when the flowing bottomhole pressure drops below the dew-point. As a result, different flow regions with different characteristics are created within the reservoir. These flow regions can be identified by well test interpretation. The use of well test analysis for quantifying near well and reservoir behavior is well established for the case of simple single-layer homogenous systems. The behavior, however, is more complex in cases where different rock types or layering effects co-exist. In these cases, distinguishing between reservoir effects and fluid effects is challenging and needs a variety of analytical and numerical tools. The aim of this study is to investigate the liquid condensation effects on well test behavior of naturally fractured gas condensate through simulation approach in two different rock properties in a giant naturally fractured gas condensate field in south of Iran. A single well compositional model is developed to determine early-time, transition-time and late-time characteristics of the pressure transient data under condition of below dew-point pressure. Then compositional model has been used to verify the results obtained from conventional well test analysis in this field. The results of this study would improve modeling of the surrounding area in mentioned field. Interpretation of compositional model outputs have shown that condensate deposit near the wellbore yields a well test composite behavior in early and late time similar to what is found in single porosity homogenous system, but superimposed on double-permeability behavior. The behavior, however, is more complex in transition time which cause delay in hydrocarbon flow from the matrix blocks towards the fractures and lead to decrease in interlayer cross flow coefficient.