Unconventional resources have received significant attentions as recent advances in technology has made it possible to economically produce from these reservoirs. While the economical production from these reservoirs have been initiated, the impact of the mentioned mechanisms on fluid flow are not well understood. In this thesis, to study the effects of flow regimes and geomechanical stress on fluid flow in shale matrix, several experiments were performed at different pore pressure and net stress conditions. It was aimed to obtain a reliable model for prediction of matrix permeability during the production period when the pore pressure is decreasing and the net stress is increasing with time. For this purpose, the matrix permeability of several shale rock samples were measured at different conditions. In addition, the results of TOC, Helium porosimetry, XRD analysis, contact angle measurements, MICP test and SEM image analysis were used to characterize the shale sample under study. In line with the experimental measurements, the corresponding flow equations were derived using Navier-Stokes (NS) equations with slip boundary conditions. The derived flow equations and the experimental results were used to obtain appropriate slip coefficients. Then the geo-mechanical effects on matrix permeability were considered. The experimental data were used to develop a model for permeability prediction at different pore pressure and net stress values. The proposed model was also validated using a set of experimental data in the literate. Furthermore, the gas flow in micro and nanoscale systems was simulated using the Lattice Boltzmann method (LBM). After validation, the simulation results were compared with the scaled experimental data. From the comparison, Tangential Momentum Accommodation Coefficient (TMAC) for LBM simulation of gas flow in shale rocks was determined. Results obtained in this study are essential for using the LBM as a simulation technique for fluid flow modelling in shale rocks. In addition to single phase flow studies, two-phase relative permeability of unconventional rocks were measured. It is shown that the Capillary End Effect (CEE) caused as result of ultra-high capillary pressure in shale formations, is the main artefacts that makes these measurements unreliable. In this thesis, a model is developed to correct the CEE during the steady-state relative permeability measurements. The proposed model was also evaluated by a set of artificially generated data and the experimental SS-kr data measured in the lab
