Understanding reservoir engineering aspects of shale gas development on the Alaska North Slope

Abstract

Horizontal drilling and multi-stage hydraulic fracturing made it possible to develop US shale resources. Shublik shale is one of such US shale resources - it is one of the largest source rocks for hydrocarbon accumulations located on the Alaska North Slope. This study used the workflow introduced by Mirzaei and Cipolla in 2012 to investigate the effects of fracturing fluid flowback; shale porosity; matrix, fracture and unpropped zone permeability; hydraulic fracture spacing; permeability anisotropy; non-Darcy flow; gas adsorption/desorption using the complex-fracture-network model, referred to as an Unconventional Fracture Model (UFM), and Voronoi grid on well performance in the Shublik shale formation. In addition, the effects of natural fracture network orientation, fracture spacing and length were examined using a single porosity model with incorporated Discrete Fracture Network (DFN). The Schlumberger Mangrove Plug-In for Petrel platform was used to conduct the study. Mangrove has the DFN feature, which can be deactivated in the single porosity model. The results suggested that ignoring fracturing fluid flowback and non-Darcy effects can lead to overestimation of the gas recovery factor. Neglecting gas adsorption/desorption effects leads to underestimation of the gas recovery factor. In addition, smaller fracture spacing leads to a higher gas recovery factor. DFN orientation, fracture spacing and length affect the propped fracture area and should be incorporated into analysis from shale plays since it can result in either overestimation or underestimation of the gas recovery factor depending on fracture network propagation. Finally, examining multiple hydraulic fractures instead of one fracture is more accurate due to the stress shadowing effects and fracture network propagation.