In conventional petroleum systems, predicting gas-oil ratio and charge volumes ahead of drilling is a proven element of exploration strategy. In shale plays the liquid-gas cut-off must be known precisely, and production from the liquid-prone zone optimised. In-place does not necessarily correspond to produced GOR. In particular the transition from volatile oil, to condensate to wet gas is crucial, and production strategies must be developed accordingly. The first step in unravelling the fractionation phenomena occurring in both play types is to determine the bulk composition of the petroleum that is first-formed in the source rock. This is because all subsequent processes simply act upon and modify this original composition. Here we present numerous case studies where PhaseKinetics (di Primio and Horsfield, 2006), a compositional kinetic approach for predicting in-situ bulk fluid properties, has been employed in appraising acreage, and then go on to consider some of the critical aspects surrounding unconventional plays. In high pressure-high temperature (HPHT) reservoirs of the North Sea, which can be considered closed systems, black to light oil GOR distributions in the North Sea Viking Graben closely matched the predictions from our MSSV pyrolysis experiments (method of Horsfield et al., 1989) performed on the Draupne Formation source rock (di Primio and Skeie, 2004). In a similar study of the Jade and Judy Fields in the Central Graben (di Primio and Neumann, 2008), GOR predictions from MSSV pyrolysis bore a close resemblance to the natural HPHT system. Other examples of excellent GOR predictive capability are provided by modelling the Egret Shale and its generated petroleum in the Jeanne d'Arc Basin, Canada (Baur et al., 2012), and the Bakken Shale and its petroleums in the Williston Basin, USA (Kuhn et al., 2010, 2012). The lessons learned from conventional systems about petroleum compositional predictions can be readily applied to shale resource plays. Of key importance is the structure of the precursor organic matter, determined by organofacies and maturity. This applies both vertically and laterally. We also draw attention to the importance of determining whether cumulative or instantaneous fluids are found within the range of pore sizes present in shale. In the mid- to late oil window, instantaneous fluids from the Posidonia Shale are rich in gas and light liquids; phase envelopes change rapidly with increasing maturity. Cumulative fluids in juxtaposed strata have lower GORs. Fracking has to take these points into account or production GOR might turn out to be quite different to in-situ GOR, a phenomenon that has already been noted for the Eagle Ford.