LAUSR

During injection of CO2 for geologic sequestration, reservoir pressure will increase. The magnitude of that increase is predicated on many factors, including a priori reservoir pressure, injection rate and hydraulic diffusivity. Controlling reservoir pressure buildup is feasible through different means, and especially common for such is extracting fluid from the reservoir via production wells. The configuration of well patterns is an important design aspect. We evaluated seven different well patterns for the SACROC unit, an enhanced oil recovery with CO2 site in the Permian Basin of western Texas, USA. Each pattern utilized a different production well configuration, including number and locations of wells. We quantified the performance of each well pattern. An intuitive result that was exhibited by simulation results is that patterns with production wells are always superior to non-production cases. More specifically, more production wells translates to less time needed to release the pressure, also intuitive, but our goal was to quantify. We also evaluated the impact of several model simplifications, including increased intrinsic permeability, homogeneity, linear relative permeability functions and flatness of vertical layers. Results indicate that models with multiple simplifications lead to more significant difference from the original “best calibrated” model compared to models with only one simplification. Among all studied factors, increasing the intrinsic permeability has the greatest impact on the pressure management, and thus is probably the most important variable to consider for pressure management strategies. The choice of relative permeability function is least important, at least in the context of pressure management strategy. Heterogeneity of the reservoir not only affects pressure management significantly, but also influences simulation grid design optimization as well as well alignment orientation.