Tight gas-condensate reservoirs contain large reserves, but can be extremely costly to develop. Understanding the fundamental controls on the fluid flow behaviour of tight gas and gas-condensate reservoirs has the potential to result in more cost-effective reservoir development and help increase the world’s producible reserves. The principal objective of the paper is to improve understanding of multiphase flow within tight gas-condensate reservoirs. In order to achieve this objective a series of pore-to-core scale experiments under controlled conditions were performed, followed by numerical simulation.

Three methodologies were used in this study: First, pore-scale experiments in glass micromodels with liquid-liquid systems were performed to improve understanding of the phase separation and flow mechanisms at pore level. Second, coreflood experiments were performed while in-situ saturation was monitored using an X-ray CT-scanner. A newly developed liquid-liquid system was used in these experiments. Flow through tight gas sandstones allowed the determination of relative permeabilities as well as determining their dependence on absolute permeability and capillary number. Third, production simulation modelling has been conducted to investigate the implications of the results.

The micromodel experiments have proved extremely useful for characterizing the flow behaviour of condensate systems. The results showed that the flow mechanisms and phases’ distributions were affected largely by interfacial tension, pore structure and wettability. The experimental results showed the dependence of gas-condensate relative permeabilities of tight rocks on absolute permeability and capillary number. The incorporation of the results into production simulation modelling has shown an increase of gas production up to 70% for tight gas-condensate reservoirs when capillary number effects were included.

The modelling has shown that the high velocity phenomena near the production well must be taken into account for tight gas-condensate reservoirs. Therefore, the current practice of modelling these reservoirs using immiscible relative permeabilities should be immediately reviewed to avoid costly and ineffective reservoir development plans.

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