Tight gas carbonate fields are often faced with early water breakthrough in the presence of fractures connected with an active aquifer. The recovery assessment from such fields requires us to take into account the role played by water imbibition of the matrix, which, depending on the fracture density and rock properties, can delay water breakthrough significantly. The prediction of such spontaneous-imbibition phenomena requires experimental measurements and modeling in the case of rocks of complex porous structure like vuggy carbonates. This paper gives the results of such an investigation on samples from a vuggy carbonate field. A thorough petrophysical characterization of the rock was carried out first, followed by water/gas imbibition experiments. Those experiments were finally simulated numerically to check the consistency of the experimental data set and further understand the fluid-flow behavior of those peculiar media. The porous structure of several samples was characterized from capillary pressure and nuclear magnetic resonance (NMR) measurements. Spontaneous imbibition was found to be very slow, which required the implementation of a specific accurate measurement device. The slow kinetics was caused by the very low mobility of water, which was measured separately as well. To explain this flow behavior, the peculiarity of the porous structure of the rock-type studied-fairly large vugs dispersed within a tight matrix with very small pore thresholds-is invoked. Simulations on a representative pore-network model actually revealed that the flow ability of the water phase is considerably hindered in such a medium. Finally, the spontaneous-imbibition behavior was reproduced satisfactorily with single-porosity and dual-porosity models using the measured petrophysical parameters, thus showing the consistency of the measured data set. Gas-production management from vuggy carbonate reservoirs subjected to water encroachment requires a specific evaluation of matrix-imbibition phenomenon because the latter is ruled by unconventional flow parameters linked to the complex two-phase-flow interactions between vugs and micropores in such media. Copyright ? 2007 Society of Petroleum Engineers.