Abstract The Upper Cretaceous Woodruff sand in Tinsley Field provides a good case study of addressing the challenges influencing the flooding process of a complex reservoir. It primarily consists of sandstone intervals that were deposited in a shallow marine, wave-dominated shoal environment and appears deceivingly simple on wireline logs. Deeper investigation finds that the clastic reservoir is actually rich in carbonate concretions with varying geometries and percentages. These carbonate concretions change from scattered ovoid to discontinuous thin beds alternating with bioturbated intervals throughout the structurally-separated fault blocks of the field. Evidence supports the concretions acting as baffles rather than barriers to flow within the reservoir. The main Woodruff rock types were categorized based on petrographic description of cores taken from different locations and fault blocks within Tinsley Field, and this approach helped to highlight the impact of diagenesis on the reservoir quality throughout the field. The probe permeameter data of the cored wells provided a discrete, high-resolution method to determine net reservoir sand. Calibration of probe permeability measurements from the cores with wireline log-based permeability provided a good control on the petrophysical properties throughout the field. The uncertainty related to distribution of reservoir properties was addressed by building a sector model representing one of the Tinsley fault blocks. Population of the properties was controlled by semi-variogram ranges. Although thickness and percentage of pay versus non-pay remained uncertain, validation of the sector model was achieved by matching the static properties and calculated pore volumes to the production history. The results of the flow simulation model demonstrated that the geological model had a reasonable distribution of properties to reflect actual reservoir behavior. The Woodruff geological model provides the foundation for detailed reservoir simulation study that can enhance the understanding of fluid flow within the reservoir intervals. This knowledge will greatly assist in deriving the optimum flooding strategy to maximize oil production, and ultimately, the oil recovery factor.