Core and log data indicate highly variable reservoir quality in the lower part of the Prudhoe Bay reservoir. Characteristic reservoir descriptions were developed in order to investigate the sensitivity of production performance to reservoir heterogeneity. Detailed core description and analysis showed that grain-size (lithotype) was the major control on poroperm. In turn, the spatial distribution of lithotypes is governed by the depositional environment, which is interpreted as a fluvial-dominated delta. This led us to develop new, quantitative, object-based models of the distribution of lithotypes within each of four major facies associations. These models were then converted to spatial distributions of poroperm on the core-plug scale, and these then re-scaled to give effective reservoir simulation grid properties. The quantitative lithotype models contain a number of variable parameters which enable sensitivities to uncertainties in the geological description to be studied.


This paper describes an integrated study that makes practical use of a number of recently developed techniques for characterizing inter-well heterogeneities. We also describe some new models, developed specifically to represent the distribution of lithotypes within a deltaic setting. These models, and the other techniques we have used in the characterization process, are not specific to the Prudhoe Bay reservoir and could be used for other fluvial-deltaic systems.

Our particular application is to Zone 1 of the Ivishak Formation, the lowermost of the four zones that comprise the major reservoir of the Prudhoe Bay Field, North Slope, Alaska. The Ivishak is broadly interpreted as a braided and meandering fluvial complex, underlain by finer grained rocks of deltaic origin, which interfinger with the pro-delta shales and siltstones of the underlying Kavik Formation see Figure 1.


The Prudhoe Bay reservoir is estimated to have contained approximately 12 billion stock tank barrels (BSTB) of recoverable liquids, of which 7.6 BSTB have been produced since the field came on stream in 1977. Since then, the vast majority of production has been from the upper three reservoir zones, where the major heterogeneities of concern were the presence of both mappable and stochastic shales. Ultimate recovery from these zones is expected to be about 55–60%. A variety of mechanisms are active in the field including, gravity drainage, lean gas re-cycling through the gas cap and waterflooding and miscible gas injection in the periphery.

To date, relatively little production has occurred from Zone 1 which contains approximately 1.8 BSTB of oil. Current recovery of this target is estimated to be in the region of only 10–15% due to its poorer reservoir quality, geologic complexity on the interwell scale plus structural considerations.

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