Analyzing the impact of fracture complexity on well performance and wettability alteration in Eagle Ford shale

Abstract

Simulation of the impact of hydraulic fractures on completion optimization and well performance has been extensively studied. In most literatures, simple bi-wing-fracture pattern is assumed due to the difficulty and uncertainty in predicting the fracture geometry. However, bi-wing-fracture pattern does not agree with complex-fracture geometry in the way they influence the reservoir behavior. In this study, an integrated workflow of fracture propagation and reservoir simulation model is developed to simulate the well production in complex fracture geometries. Based on this model, the effect of fracture geometry complexity on well performance and wettability alteration is investigated. First, a fracture-propagation model (FPM) is developed to predict the complex hydraulic fracture geometry by considering elastic deformation of the rock and fluid flow. Then, the predicted fracture geometry from FPM is automatically read and transferred to a reservoir simulator through the embedded discrete fracture model (EDFM). In EDFM, the reservoir is discretized with structured grids and additional grids are introduced for both hydraulic and natural fractures. Through non-neighboring connections, the EDFM can properly handle complex fracture geometries by modifying transmissibility. Based on the concepts of EDFM, we can efficiently simulate the effect of wettability alteration by simply modifying the wettability condition of the activated fracture grids and matrix grids around the activated fractures to be water wet while keeping the inactivated fractures and nearby matrix grids remaining oil wet. The integrated workflow is applied to investigate the effects of complex geometry on the well production and wettability alteration in Eagle Ford reservoir. The complex-fracture geometry is predicted by the fracture propagation model and calibrated by diagnostic data. Then the fracture parameters are processed with EDFM and transferred to numerical simulator. With this workflow, we conduct history match of different numerical cases with different complexity of fracture networks. The oil flow rates are used as input data and we history match the bottom-hole pressure and gas flow rate. Simulation results show that larger fracture conductivity is required for bi-wing-fracture case compared with complex-fracture case to match the field data. However, long term production indicates that complex-fracture reservoir has apparently higher oil recovery despite its lower fracture conductivity. Then the effect of fracture complexity on wettability alteration is investigated. The results indicate that complex fracture networks will amplify the impact of wettability alteration on enhanced oil recovery and vice versa. Furthermore, sensitivity analysis of the surfactant imbibition depth, which is affected by the surfactant type and concentration, shows that increasing the imbibition depth has a much more significant impact on the enhanced oil recovery in complex fracture networks than that of the simple fracture networks. The results help us better understand and predict enhanced oil recovery as a function of wettability alteration and to investigate the impact of uncertainties in the fracture geometries and surfactant imbibition depth.