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Many shoreface sandstone reservoirs host significant hydrocarbon volumes within distal intervals of interbedded sandstones and mudstones. Hydrocarbon production from these reservoir intervals depends on the abundance and proportion of sandstone beds that are connected by erosional scours, and on the lateral extent and continuity of interbedded mudstones. Cliff-face exposures of the Campanian 'G2' parasequence, Grassy Member, Blackhawk Formation in the Book Cliffs of east-central Utah, USA, allow detailed characterization of 128 erosional scours within such interbedded sandstones and mudstones in a volume of 148 m length, 94 m width and 15 m height. The erosional scours have depths of up to 1Á1 m, apparent widths of up to 15Á1 m and steep sides (up to 35°) that strike approximately perpendicular (N099 AE 36°) to the local north-south palaeoshoreline trend. The scours have limited lateral continuity along strike and down dip, and a relatively narrow range of apparent aspect ratio (apparent width/depth), implying that their three-dimensional geometry is similar to non-channelized pot casts. There is no systematic variation in scour dimensions, but 'scour density' is greater in amalgamated (conjoined) sandstone beds over 0Á5 m thick, and increases upward within vertical successions of upward-thickening conjoined sandstone beds. There is no apparent organization of the overall lateral distribution of scours, although localized clustering implies that some scours were re-occupied during multiple erosional events. Scour occurrence is also associated with locally increased amplitude and laminaset thickness of hummocky cross-stratification in sandstone beds. The geometry, distribution and infill character of the scours imply that they were formed by stormgenerated currents coincident with riverine sediment influx ('storm floods'). The erosional scours increase the vertical and lateral connectivity of conjoined sandstone beds in the upper part of upward-thickening sandstone bed successions, resulting in increased effective vertical and horizontal permeability of such intervals.

We present a surface-based approach to reservoir model construction in which all geological heterogeneity, whether structural, stratigraphic, sedimentological or diagenetic, that impacts on the spatial distribution of petrophysical properties is modelled as one or more discrete volumes bounded by surfaces. The modelled surfaces can be deterministically interpolated between control lines or points, or incorporate a stochastic element where control data are sparse. Models constructed from surfaces are not constrained by an underlying grid; indeed, the model is generated without reference to a grid. The only difference between ‘geological’ and ‘simulation’ models is that the latter incorporates a grid or mesh to allow numerical solution of the governing flow equations, the architecture of which is driven by the architecture of the modelled surfaces. This approach to gridding (or meshing) is directly compatible with the next generation of unstructured-mesh simulators, and allows the capabilities of the latter to be utilized fully in the modelling of complex reservoir architectures. A surface-based approach to model construction may facilitate a step change in reservoir modelling capabilities: once the requirement to upscale geological models to a structured simulation grid is removed, there is no need to build geological models that are restricted by grid resolution.

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A B S T R A C TPermeability contrasts associated with clinoforms have been identified as an important control on fluid flow and hydrocarbon recovery in fluvial-dominated deltaic parasequences. However, they are typically neglected in subsurface reservoir models or considered in isolation in reservoir simulation experiments because clinoforms are difficult to capture using current modeling tools. A suite of three-dimensional reservoir models constructed with a novel, stochastic, surface-based clinoform-modeling algorithm and outcrop analog data (Upper Cretaceous Ferron Sandstone Member, Utah) have been used here to quantify the impact of clinoforms on fluid flow in the context of (1) uncertainties in reservoir characterization, such as the presence of channelized fluvial sandbodies and the impact of bed-scale heterogeneity on vertical permeability, and (2) reservoir engineering decisions, including oil production rate.The proportion and distribution of barriers to flow along clinoforms exert the greatest influence on hydrocarbon recovery; equivalent models that neglect these barriers overpredict recovery by up to 35%. Continuity of channelized sandbodies that cut across clinoform tops and vertical permeability within distal delta-front facies influence sweep within clinothems bounded by barriers. Sweep efficiency is reduced when producing at higher rates over shorter periods, because oil is bypassed at the toe of each clinothem. Clinoforms are difficult to detect using