Numerical Investigation of Transient Flow Responses in Fractured Tight Oil Wells

Abstract

Increasing demand of global energy and limited conventional resources force the petroleum industry to shift their focus towards the low permeability reservoirs such as shale or tight rock reservoir. Multi-fractured horizontal wells have economically unlocked the massive hydrocarbon resources from unconventional reservoirs. Horizontal drilling and hydraulic fracturing create a complex fracture network that could enhance reservoir contact area to achieve economic production rates. In this study, we compute the transient response in a segment of a hydraulically fractured horizontal well using a triple-porosity model. Impacts of capillary discontinuity (fracture face-effect) and some limitations in analytical models such as sequential flow, single-phase flow and fully-connected symmetric fractures are investigated. We find that the uncertainty in model history-matched parameters and assumptions associated with analytical models could potentially over- or under-estimate production by up to 30%. History-matching with analytical models alone and the assumption of uniformly-spaced fracture stages would tend to overestimate long-term production forecast. In contrast, the assumption of no solution gas in tight oil reservoir leads to underestimation of reservoir properties such as length of fracture and permeability. Moreover, the simulated production data indicates that fracture face-effect results in rapid production decline. Lower capillary contrast between fracture and matrix results in less water blockage and higher production.