Abstract

Production from the gas-condensate window of the liquid-rich shale plays in the US such as Barnett, Marcellus and Eagle Ford, has increased during the past few years. However, there is still a lack of understanding of the flow behavior of gas-condensate in liquid-rich shales when the flowing bottom-hole pressure falls below the dew-point pressure. Condensate dropout below the dew-point pressure leads to variation in the composition of vapor and liquid hydrocarbons. The phase behavior prediction is further complicated by the nanometer-sized pores of the shale formations where fluid-rock interaction could be different than in conventional reservoirs.

This work investigated the compositional variation of gas-condensate during flow through Marcellus shale in laboratory coreflooding experiments. During the experiments, a gas-condensate mixture was injected into the core and during the flow, gas samples were collected through ports spaced along the core holder. Then, the gas samples were characterized using gas chromatography for compositional analysis. The results were compared to equivalent experiments in Berea sandstone.

The gas-condensate sample used in the coreflooding experiment was collected from the Marcellus liquid-rich region and the experiments were conducted at reservoir pressure and temperature. Prior to conducting the experiments, the permeability of the Marcellus shale core and the Berea sandstone core were characterized using the pressure pulse decay technique and the Darcy flow technique; respectively.

Results from this study showed that the gas composition varies along the direction of flow during depletion. The change in gas composition is due to the combination of condensate dropout and relative permeability effects. However, the magnitude of variation in the gas composition across the Marcellus shale core was less than that in the Berea sandstone core. This is an indication that the amount of condensate dropout varies between shale and sandstone for the same fluid system and at similar flowing conditions. Hence, the phase behavior is affected by the additional fluid-rock interaction expected for the shale due to flow through nanometer-sized pores.

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