Horizontal organic shale wells are typically completed with the same fluid system in each stage with identical pump schedules for each stage.  Each stage is not in the same stratigraphic interval vertically, however, and some reservoirs require more propped height than some fluid systems provide to connect the wellbore to the pay.  A lot of service company capital has been invested in systems that define horizontal heterogeneity in the shale plays using sophisticated horizontal logging programs.  This is counter-intuitive to the observation that these plays are successful and repeatable due to the relative lack of horizontal heterogeneity in these deep water sheet type depositional environments.  Production log data frequently indicates that entire stages are often not producing, however, suggesting there is a disconnect between the wellbore, propped fracture, and net pay.   It is proposed that a complete net pay and rock properties profile be generated in vertical pilot wells that define where the net pay is, what the rock properties distribution is, and what the effective propped height profile will be created as a function of wellbore placement vertically using a variety of frac fluid options.  This profile should then be validated with vertical well DFIT and traced propped frac treatments in the vertical wellbore.  With this information the optimum treatment can be designed for each stage depending on where the lateral intersects the vertical stratigraphic column.  If a stage cannot be effectively stimulated with available fluid systems it should be bypassed.   Examples of vertical well propped fracture dimensions vs fluid type and net pay distribution are presented for several of the major shale plays to support the proposed methodology.