Shut-in effect on oil recovery under different reservoir and operation conditions

Abstract

The aqueous fluid (water) is accumulated near the interfaces between fractures (hydraulic and natural) and the matrix during hydraulic fracturing. The accumulated water can be partially removed either through the immediate well flow back or through shutting in well before the flow back. Which method is more effective for oil recovery? The answers are mixed in the literature from field reports and experimental or simulation studies. This article proposes a hypothesis that the flow back of fracturing fluid is controlled mainly by two mechanisms: viscous displacement and capillary imbibition. The shut-in can outperform the immediate flow, or vice versa, depending on reservoir and operation conditions. When the viscous displacement dominates, the immediate flow back is more effective. When the capillary imbibition dominates, the shut-in is more effective. The hypothesis is verified by the results of many simulation models which are built by modifying some parameters of the same base model. Those parameters include pressure drawdown, capillary pressure, matrix permeability, wettability, initial water saturation, and formation compressibility. It is implied from this study that the immediate flow back is preferred to the shut-in method if the capillary pressure is small; otherwise, the shut-in is preferred.