Understanding Mechanisms for Liquid Dropout from Horizontal Shale Gas Condensate Wells

Abstract

Abstract The presence of nanopores in tight, rich-gas-condensate wells (3,000 to ~10,000 scf/STB) may hold long-term gas/oil ratio (GOR) trends constant with time as observed in production data from some North American shales. This finding contrasts with some of the numerical simulation forecasts performed on calibrated pressure/volume/temperature (PVT) models based on bulk laboratory PVT data. Research efforts have pointed to a decrease in the PVT phase envelopes of hydrocarbon fluids confined in nanopores. This would delay the onset of dew point pressure and condensate liquid dropout and could be one of the causes of the observed constant producing GOR in the wells studied. An understanding of fluid properties in nanopores is fundamental to predicting the onset of condensate dropout in shale reservoirs. One approach may be molecular dynamics simulations that can shed the light on the difference in behavior of larger-chain hydrocarbon molecules at kerogen surfaces and bulk pore space. Additionally, shale gas condensate production management may be more fully optimized by understanding both the effects of hydraulic fracture degradation with drawdown and liquid dropout in the production string. An integrated approach of this kind can help optimize liquid-rich shale reservoir production management.