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Abstract

This chapter describes three-dimensional (3-D) stochastic modeling of the Jotun field, which was initially undertaken in 1998 and updated after the first four wells came on production.

The Jotun field contains both differential compaction traps (Elli and Elli South four-way dip closures) and a stratigraphic pinch-out trap (Tau West). It produces from the distal parts of the Paleocene Heimdal Formation sand-rich submarine-fan system.

A predrill (1997) deterministic oil-in-place geological model was history matched so that simulated pressure drop resulting from Heimdal field gas production matched the observed pressure drop in the Jotun appraisal wells, with aquifer size and conductivity as the main history-matching parameters. With a development plan strategy of four producers on Elli, two on Elli South, and five producers on Tau West (all highly deviated or horizontal), the predicted aquifer support was such that predrilling water injectors for pressure support was unnecessary. This saved the considerable capital expenditure of three water injectors.

Predicted hydrocarbon recovery was influenced by vertical sweep efficiency, dependent on vertical permeability (kv)/horizontal permeability (kh), controlled, in turn, by the architecture of the interlayer shales. Reservoir heterogeneity was introduced in the 1998 model as architectural facies bodies in a 3-D object-based (Roxar STORM software) stochastic geological model. This captured and integrated the core-scale features in a seismic-scale stratigraphic and structural framework, using rules from outcrop analogs to fill in the missing scale. Subsurface realizations reflected different geological possibilities while preserving their influence in the upscaled dynamic simulation models.

One of the major uncertainties in the geological modeling was considered to be the extent of faulting, sandstone injection, and slumping as features, which disrupt shale continuity at core scale and which might greatly increase vertical communication and, hence, recovery. If such features are not common, significant volumes of oil could be trapped beneath laterally continuous shale barriers. Different scenarios of geometry, properties, and distribution were used to investigate the significance of such features on the expected ultimate reserves of the field. Both the large aquifer support and a high level of connectivity between the separate structures were confirmed by the first four producers brought on stream.

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