ExxonMobil (Norway)

Abstract A regionally extensive tight-gas accumulation in the Cretaeous age Mesa Verde Group of the Piceance Basin, Colorado, USA has been actively developed for over a decade. Daily production has increased from under 200 MMCFD in the year 2000 to over 1 BCFD currently. However, in some parts of the basin, the commercial development of the asset is challenged by water production. The tight gas reserves occur in a stacked, multi-sand system. It includes over 100 stacked reservoir targets distributed over approximately 5,000ft of formation vertically. Water can be produced from any of these targets geographically. Produced water can cause serious wellbore hydraulic issues and also increase water disposal cost. Therefore, recognizing and avoiding high water production zones before hydraulically fracturing is critical. A workflow for evaluating water-production risk has been developed. The workflow includes 1) deriving reservoir properties (porosity, water saturation, etc.) from open-hole and/or cased-hole logs, 2) calibrating the log measurements with a robust core-based, grain-size-dependent permeability prediction model, and 3) using water saturation in conjunction with permeability to evaluate the likelihood of low capillary or imbibed water for individual sands. This gives a qualitative analysis of water risk on a cross-plot of permeability versus permeability-water-saturation separation (k-Sw screening) with no water production risk (bound water) to high water production risk. The k-Sw screening concept has been verified with logs and production data from over 50 wells in the northern part of the basin. The workflow helped decrease water production thereby improving the economics of the tight gas play.

The Balder and Jotun fields are located on the western flank of the Utsira High, close to the eastern pinch-out of a Tertiary submarine fan system. Although similar in many aspects, the fields display important depositional, structural and stratigraphic differences which influence the choice of development strategy. The subsurface development strategy for the fields has been designed to optimize oil capture and minimize risk based on the interpreted reservoir geology. Therefore, differences between the exploration histories and reservoir geology are reflected in the development strategy of the two fields. Both fields comprise Tertiary reservoir sands shed from the East Shetland Platform and transported across the Viking Graben area onto the Utsira High by sandy debris flows and turbidites. These distal gravity flow deposits display both thin-bedded sands and thicker more massive sandstones (>100 m). In the Balder Field, an intricate interaction between deposition and soft sediment deformation processes generated a complex network of reservoir compartments with common fluid contacts. In the Jotun Field, the oil–water contact is also common between all three structures, but a gas cap is restricted to one of the structures.