Measurement of reservoir fluid gradients vertically and laterally in a reservoir captures a ‘snapshot’ of the evolution of fluid processes that take place over geologic time. Downhole fluid analysis (DFA) has enabled this reservoir fluid profiling to be performed in an efficient manner. Dramatically different fluid distributions are obtained in different reservoirs and can be categorized in terms of the extent of thermodynamic equilibrium attained. Factors that influence the equilibration process include the geologic timing of reservoir charging, possible secondary fluid processes, the extent of convection versus diffusion, the size of the equilibrating fluid component, and the size of the reservoir. Here, we show reservoirs that span a very large range, from very young reservoirs (Pliocene) that evidently exhibit stochastic distributions of solution methane over relatively small distances to old reservoirs (Lower Cretaceous) with equilibrated asphaltene clusters over immense distances. For each class of reservoir evolution, very different yet very important production concerns are identified. Characterization of the fluid columns in terms of (dissolved) solids, liquids and (dissolved) gases is found to be most informative for several reasons including 1) the large gradients associated with the different (dissolved) phases and 2) the important production concerns associated with the different phases. In particular, understanding the disposition of the asphaltenes in the reservoir is key for many purposes. This is accomplished using the industry’s first equation for asphaltene gradients, the Flory-Huggins-Zuo Equation of State for asphaltenes, with its reliance on the Yen-Mullins model of asphaltene nanoscience. The ability to model all three crude oil phases within a proper thermodynamic framework enables the ability to track the evolution of these phases in the reservoir, bringing into view simplifying systematics that significantly improve risk management in production of these reservoirs.