Estimation of Gas Condensate Relative Permeabilities for Field Development in Egypt in Absence of Reliable Core Flood Experiments

Abstract

Abstract Gas condensate field development is a challenging task involving many technical disciplines, from sedimentology and petrophysics to reservoir and facility engineering. For evaluation of development options in a Nile Delta onshore field with original reservoir pressure close to dew point, reservoir simulation must account for potential condensate blockage near wellbore. Uncertainties related to blockage can severely risk the estimation of gas and condensate reserves and production, and significantly impact project development or even put the investment decision on hold. The method of Whitson8 for determining velocity-dependent gas-condensate relative permeabilities is sufficiently robust and reliable to model well deliverability in moderately homogenous reservoirs. However, with increasing heterogeneity, gas condensate flow in contrasting facies or thin laminated zones requires deeper investigation. Thin low permeability layers can act as bounding surfaces with condensate dropout below dew point, which may trap initially connected gas volumes. Estimation of gas condensate well deliverability is further complicated if shortage of reservoir core material and fluids precludes reliable coreflood experiments across the full range of pressure/flow regimes. This paper demonstrates how digital rocks technology can enhance the understanding and de-risk the prediction of gas condensate flow in contrasting rock types and with only limited core material and cuttings at hand. Remnants of sidewall core plugs from earlier laboratory analyses were scanned using X-ray micro-tomography to obtain 3D images down to pore-scale of regions ranging from open to tight. Flow simulations were performed in the pore space of the processed images to reconcile connected porosity, absolute permeability and capillary pressure-saturation curves with laboratory core analysis results, and to refine the rock types ranging from higher to lower reservoir quality. As input to two-phase gas-condensate flow simulation, representative capillary numbers and viscosity ratios were estimated based on PVT and the planned field development options and existing dynamic reservoir model. The dynamic pore-scale simulations yielded gas-condensate relative permeability curves versus rock type and capillary number which agreed well with published literature. The delivery of consistent relative permeability estimates in a short timeframe from this digital rocks approach served to reduce uncertainties in reservoir modeling to de-risk the development planning of the gas condensate field.