Pore diameter in shale strata ranges from a few to hundreds of nanometers, whereas in conventional reservoirs the range is 3 orders of magnitude greater. In spite of the small size of the pores-which would be expected to cause very low intrinsic permeability-field reports document unusually high loss of hydraulic fracturing fluid (as much as 90%) in shale reservoirs. The lost fluid remains in induced fractures and also leaks off into the shale matrix. Liquid flow in tiny pores is different from the flow in large pores. To compensate for this difference, the traditional liquid flow model needs a correction parameter called liquid slip length. We measured slip length of brine and pores in shale by using an atomic force microscope (AFM). Our measurements suggest a slip length of 250 nm in organic pores. We used measured slip length in a stochastic permeability model to calculate apparent liquid permeability (ALP) in the shale matrix. When corrected for slip length, the ALP in shale can be much greater than intrinsic Darcy permeability. We then used ALP in a coupled flow-geomechanical simulator to study the effects of slip-corrected matrix permeability on the induced fracture network and fluid loss during hydraulic fracturing. The results show the dramatic effects of the slip parameter on the fracture network and explain the high fluid loss during hydraulic fracturing. (C) 2015 Elsevier Ltd. All rights reserved.