Successful shale gas and tight oil applications require multiple hydraulic fracture treatments in a given horizontal well. Key design considerations are the spacing between injection zones, the size of the treatments, and the injection parameters (primarily rate and viscosity). Other important parameters are whether to inject into multiple zones simultaneously or sequentially, and whether to coordinate fracturing between multiple adjacent horizontal wells. We investigate various injection scenarios using two different "pseudo-3d" boundary element, displacement discontinuity method based hydraulic fracture simulators. A single fracture model couples the injection of non-Newtonian fluid, Carter leak-off behavior, arbitrary non-planar propagation, and height growth in a 3-layered media. The second model is designed to be more computational efficient and stable by simplifying the fracture fluid flow calculation. Fracture pressure variation through time is approximated by summing the inverse of width cubed over the created fracture network, and wellbore pressure is equated to the predicted summative pressure drop in the system. Results indicate that sequential fracturing geometries are highly dependent on injection zone spacing relative to fracture height – when fractures are closely spaced relative to stress shadow size, fracture path diversion and intersection as well as net pressure effects are likely. This strong mechanical interaction scenario promotes fracture complexity (which can be an advantage in some formations), but reduces the penetration distance of fracture wings away from the wellbore. Simultaneous fracturing of multiple stages is also strongly influenced by the spacing to height ratio – the closer the spacing the more difficult it is to get substantial growth from all completed zones.