Acid-Gas Storage in a Deep Saline Aquifer: Numerical Sensitivity Study to Evaluate Parameter and Model Uncertainty

Abstract

A modeling study is conducted to evaluate the sensitivity of acid gas evolution in a deep saline aquifer to expected variations of multiple geologic and engineering variables. Relative permeability hysteresis, aquifer heterogeneity variance, formation water salinity, permeability of caprock and leakage wells, injection rate, regional hydraulic gradient, and formation depth are evaluated as uncertain input parameters to a three-dimensional synthetic aquifer model with fully heterogeneous permeability. To understand the effect of conceptual model uncertainty on predicting gas flow and storage, permeability of the heterogeneous model is upscaled to equivalent permeability for three increasingly homogenized stratigraphic models: an eight-unit facies model, a three-unit depositional model, and a one-unit formation model. Two upscaling methods are used: a flow-based numerical method and an analytical averaging method. Over 120 years (20 years of injection and 100 years of monitoring), multiphase compositional simulation is conducted to model gas migration and trapping in the aquifer and its dissolution in the formation brine. Results suggest that among the variables evaluated, gas-relative permeability hysteresis, heterogeneity variance, and injection rate have the most significant impact predicting the total mobile gas in the storage system, whereas caprock permeability is the most important factor influencing the prediction of total gas leakage and thus the storage security. Over the simulation time scale, for the fixed amount of gas injected, regional hydraulic gradient, salinity, and formation depth have lesser impact on gas flow and storage predictions. Further, leakage through abandoned wells can occur when permeability of the wellbore is as low as 1 mdarcy (md), while caprock permeability becomes critical to storage security when it is more than