With unconventional exploration expanding into basins with little seismic data and few wellbores, some lower cost technologies should be exploited up front to select areas of greater economic potential. Typically, 3D seismic is used for high grading, but it is expensive, ground access can be limited resulting in partial coverage, and, as with many technologies, interpretations can be ambiguous. However, there are less expensive alternatives, such as remote sensing, gravity and magnetics, geochemistry, and petrography, that can be used to initially identify areas with higher potential. After the initial screening evaluation, the high-graded areas can subsequently be appraised using more expensive techniques. Using less expensive screening alternatives up front can improve results and project economics. Two examples, one from the Bakken in the Williston Basin and another from the Eagle Ford at First Shot Field in Texas, are given showing how such less expensive screening data can be used to locate areas that have either better production and/or oil that is more easily produced from tight rocks. Our Bakken and Eagle Ford examples determined that our integrated approach could add value in different tectonic settings that involve rocks of very different geologic ages and depositional settings. Detecting and investigating igneous events in a sedimentary basin were important steps in our integrated approach. Igneous activity was more common in the upper crust and sedimentary basins than was generally assumed. In both of these examples, production “sweet spots” were related to igneous drivers that create areas of localized convective high heat flow that in turn were associated with recurrent movement of basement faults. Convective heat flow via hydrothermal fluids along faults and fracture zones was much more efficient than the transfer of heat by conductive heat flow. The screening data at the mega- and microscale supported the hypothesis that recurrent movement on faults and lineaments provided conduits for hydrothermal fluids and igneous volatiles. The hydrothermal fluids were interpreted to have had an important impact on in situ hydrocarbon generation, and petrography further suggested that precipitation of minerals from these hydrothermal fluids could affect porosity, permeability, rock fracturability, and overpressuring. The work and our examples proved how less expensive screening techniques, such as remote sensing, gravity, magnetics, geochemistry, and petrography, could be used to high grade unconventional shale oil plays, so the sweet spots could be drilled first.