The economic trade-off between overcapitalization and ineffective hydrocarbon recovery has forced operators in shale plays to focus their efforts on understanding optimal wellbore spacing, both in the vertical and horizontal sense. Matrix permeability has a significant impact on the reservoir modeling results that drive many of these development decisions. Despite incorporating modern crushed-rock pressure-decay permeability datasets, well production is commonly degraded at wellbore spacing schemes much wider than the models indicate. The overstatement of permeability is likely due to experimentally derived flow-regime effects inherent to the analysis. Large helium gas molecules at low pressures are used in crushed-rock permeability experiments, which allow individual gas molecules to be quite far apart (they have a large mean free path, λ). Since shale pores are often smaller than λ, it is more likely a gas molecule will hit a pore wall than another gas molecule. This creates flow-regime effects, which tend to overstate permeability up to several orders of magnitude. To test this hypothesis, several crushed-rock samples from the Devonian Duvernay and Jurassic Nordegg Formations in the Kaybob area in the Western Canadian Sedimentary Basin (WCSB), as well as the Late Cretaceous Eagle Ford Formation in South Texas were analyzed with a pressure-decay apparatus at various λs. This was accomplished by manipulating the gas molecule used and the equilibrium pressure of the test. Although significant differences were observed, conventional approaches for correcting flow-regime effects, including slip and double-slip plots, were not successful in deriving the true (intrinsic) matrix permeability. A new technique, referred to as the λ plot, enables a reasonable derivation of flow-regime corrected permeability and effective pore size for all the samples. This permeability, k1λ, corrects the λ to a typical plug permeability experiment value of 1 nm, which we believe is quite close to the true (intrinsic) permeability. The results indicate that the median matrix permeability for all samples is 5 nD, down from over 200 nD when no corrections are made. Steady-state permeability measurements trend towards k1λ as confining stress is applied on plugs where microfractures appear to be minimal. Crushed-rock pressure-decay permeability, when corrected for flow-regime effects, offers the best measure of matrix permeability in shales.