By integrating numerical analysis with field information, we have developed realistic cross-sectional models of faulted sand-shale sequences at 3 km or greater depth to investigate how fluid-flow patterns vary with fault permeability. Simulated (isotropic) permeability ranges for shale were 10 (super -19) to 10 (super -17) m 2 (porosity f = 10-35%) and for sand were 10 (super -14) to 10 (super -12) m 2 (f = 20-25%). Fault permeability ranged between 10 (super -21) to 10 (super -12) m 2 among four models. Our results were obtained with a novel multigrid finite-element technique allowing the rapid solution of fluid flow on very fine meshes that represent thin faults and interlayered sand-shale strata with their correct aspect ratios (up to > or =800:1) and incorporate permeability contrasts with the country rock of up to ten orders of magnitude. Pressure-driven flows have been calculated for boundary pressures, simulating a transition from hydrostatic to 0.8 lithostatic with increasing depth. The four high-resolution models show that fault permeability and juxtaposition relationships across the fault control hydrodynamic fluid-flow patterns. The greater the difference between the permeability of the fault and that of the undeformed country rock, the more the flow patterns differ from those predicted by a simple geometrical analysis of sand-juxtaposition relationships across the fault, assuming that flow occurs only across overlapping sands. In our small-scale models and in another idealized basin-scale model of pressure-driven fluid flow, the direction of flow in faulted sand units can be reversed by changing the fault permeability. This two-dimensional result may indicate a wide range of hydrodynamic transport scenarios for hydrocarbons in basins where fault permeability changed with time.