Sandstone-rich fluvial reservoirs of the upper part of the Statfjord Formation in Statfjord field, northern North Sea, include significant proportions of interstratified shale beds which complicate the production of oil under a high-pressure miscible gas flood. Flood-plain mudstones, characterized by pedogenic alteration, and finely laminated abandoned channel facies form the most important flow barriers. Mudstones deposited in flood plains are expected to have a greater lateral continuity than those deposited in abandoned channels. Fluctuations in allogenic factors such as base level and sediment-supply rates have led to a variable preservation of the mudstones. This combination of different facies types and fluctuating allogenic control has led to a complex barrier dist ibution within the reservoir which is difficult to describe using conventional mapping techniques.

A procedure, based on two stochastic simulation techniques, has been adopted in order to model the complex barrier distribution. A two-dimensional Markov field model is used as an alternative to conventional shale mapping to describe the distribution of shale beds that are correlated between two or more wells. The model is based on probabilistic estimations of shale continuity between well pairs and allows the simulation of local channel incision through otherwise extensive shale beds. A marked-point process model is adopted to describe the distribution of smaller scale discontinuous barriers within the reservoir sand bodies. It is based on probabilistic estimations of shale dimensions defined using cumulative frequency distributions.

The stochastic modeling procedure allows greater flexibility to include a variety of geological interpretations and assumptions in the heterogeneity model, and the increased geological input results in more realistic models of communication between and vertical permeability within the reservoir sand bodies.