A Predictive Approach for Condensate Blockage Risk Evaluation with Limited Data Availability

Abstract

Summary Condensate blockage is a major risk in gas-condensate field development. In the investigated field, the initial reservoir pressure is close to the dew point, leading to condensate dropout and banking from the very beginning. The uncertainty in condensate blockage in the absence of reliable SCAL measurements is considered one of the main challenges. In this work, two approaches were presented to approximate gas-condensate relative permeabilities including high-velocity flow effects. Furthermore, condensate blockage mitigation methods are evaluated. The first investigated method is that of Whitson, based on the relation krg=f(krg/kro) in which PVT data and analog coreflood experimental data were used to generate relative permeabilities, also including a model for the capillary number effect. In the second method, a digital rocks SCAL analysis, based on Lattice Boltzmann two-phase flow simulation on a microscale 3D scan of remnants of sidewall core plugs, was used to simulate the relative permeabilities at low to high capillary numbers. For implementation of the curves in the dynamic simulation, the model by Henderson was used. The estimated relative permeability curves for different rock types were used directly in reservoir simulation to evaluate the risk of condensate blockage. In both methods, the effects of high velocity and non-Darcy flow were considered. The simulation results show that the designed gas plateau production rate cannot be maintained even for a few months. However, in an artificial single-phase gas flow case in which the presence of condensate is not influencing the gas flow, the gas plateau production could be sustained up to four years. As a result, the field needs to be produced three to four years longer to reach the same recovery factor, and thus significantly less return on investment is expected. Comparing both generated relative permeability curves, it is remarkable that the immiscible relative permeability curves (at lower capillary numbers) do not differ significantly from each other, despite the fact that neither of them is based on conventional SCAL experiments. Furthermore, a gas cycling scenario, well placement optimization, and a near wellbore treatment with wettability altering surfactants were analyzed in numerical simulations with promising preliminary results to mitigate condensate banking. The risk of condensate blockage for a real case scenario in the absence of reliable SCAL measurements, by adapting and comparing two approaches to approximate relative permeability curves including high-velocity flow effects, was evaluated and numerically analyzed in the present work.