Abstract

The Basal Quartz sandstone in the Duchess field of southern Alberta exhibits notable reservoir heterogeneity at various scales due to complex litho-stratigraphy and overprinting by early digenetic soil-related processes. Proper reservoir delineation, reserves assessment and simulation modeling has required the integration of stratigraphy, sedimentology, petrology, petrophysics, drill cuttings analysis and reservoir engineering. The main reservoir in Duchess consists of a two-tiered layer cake of variably permeable fluvial sandstone approximately 25 meters thick filling an incised valley roughly 800 meters wide. The valley is bounded by older channel sandstones which are essentially non-permeable except where leaching has occurred. The two "layers" comprising the main reservoir have been defined principally on differences in lithology and associated reservoir quality. The sandstone in the lowermost "layer" has relatively poor reservoir quality in comparison with the overlying sandstone which has increased quality. Oil is produced primarily from the lowermost poor quality sandstone and gas from the uppermost better quality sandstone which raised concerns for secondary recovery due to reservoir heterogeneity. After integrating all pertinent information a reservoir simulation was done to provide performance predictions for the pool under different development scenarios. Twenty performances predictions were run. Results showed that conversion of selected wells to injection and horizontal infill wells should increase the recovery from 6.7 % to 13.7% of the OOIP. However, due to the geological heterogeneity, the extensive gas cap, and a high in-situ oil viscosity the Duchess pool was not the best candidate to waterflood.

Introduction

The Duchess Lower Mannville X pool is located in Township 21, Range 14 and 15 West of the Fourth Meridian (Figure 1). The pool was discovered in 1994 with the drilling of the well 08–12–21–14w4m which tested oil out of the Basal Quartz formation at a depth of 1092 m KB. Based on the gamma ray log signature in the discovery well, combined with a regional understanding of the depositional setting, it was inferred that the Basal Quartz reservoir consisted of stacked fluvial channel sandstones. To date this pool has produced a total of 42.0 × 103m3 of oil, 22 × 106 m3 of gas, and 14 × 103m3 of water.

Subsequent drilling encountered stacked hydrocarbon-bearing Basal Quartz channel sandstones of similar thickness. However, in many instances, the Basal Quartz reservoir sandstones exhibit large unanticipated intrawell and interwell variations in log derived porosity and resistivity. For instance, in some wells, sandstones in the upper portion of the reservoir are highly porous and hydrocarbon bearing, whereas in adjacent wells, the same sandstone interval has little porosity, sub-economic hydrocarbon saturation and anomalously well developed porosity at the base of the reservoir unit (Figure 2).

An extensive gas cap was encountered in most of the wells. Despite the thick oil zone (as much as 15m) and completing the wells as far from the gas as possible, most wells were producing with a high GOR. Cement squeezes were attempted but generally did not work or did so only temporarily. Production was low because the wells were penalized from the high GORs.

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