Simulation of Fracture-to-Fracture Gas Injection in an Oil-Rich Shale

Abstract

Abstract Miscible gas injection is proposed here for improved oil recovery in unconventional, oil-rich shale reservoirs. The ultra-low permeability of shale makes injection from well to well difficult; thus it is proposed that gas is injected into a hydraulic fracture along a horizontal well and production occurs from an adjacent fracture, intersecting the same well. Compositional reservoir modeling was performed to investigate the effectiveness of the proposed gas injection scheme. The computational domain consists of two hydrofrac half-stages along a horizontal well to capture detailed information of the fluid flow near the well bore. The results show 15.7% OOIP incremental recovery for the base model with matrix permeability kmatrix = 10 μD over 5000 days (nearly 14 years) of CO2 injection, and 12.5% OOIP for the one with kmatrix = 1 μD, indicating that the gas injection scheme has the potential to vastly improve oil recovery in oil-rich shale formations. The effects of reservoir properties and injection conditions on oil recovery were investigated by changing the injection pressure, reservoir heterogeneity, hydrofrac spacing, dispersion, and compositions of the injection gas. Increasing injection pressure leads to higher production before breakthrough and faster recovery of the oil in the stimulated region. Reducing the hydrofrac spacing has similar effect, although the production declines more rapidly after breakthrough. Introducing heterogeneity to the reservoir results in lower recovery, but the effect of spatial continuity (correlation length) on recovery is insignificant. It was also found that dispersion is mainly dominated by diffusion and mechanical dispersion is less important in most cases. Injection of hydrocarbon gas outperforms CO2, especially if the economics is also taken into account.