A Synergistic Evolution Of The Norman Wells Reservoir Description

Abstract

Abstract A major development drilling program al Norman Wells has seen 237 wells drill1ed since 1981. With this expansion, an enhanced understanding of the reservoir has evolved from a synergistic treatment of the expanding data base by geologists and engineers. Volumetric and flow capacity characteristics have been determined to provide a sound basis/or managing the depletion of this Significant erode oil reservoir. The Devonian Kee Scarp Formation reef is recognized as having multiple cycles of growth as a response to relative changes in sea level. This creates a backstepping morphology which is more pronounced on the southeast side of the reef. The reservoir is naturally fractured. Dimension and distribution are controlled by burial depth and stratal boundaries. Tire development strategy implemented was a waterflood with pattern spacing and orientation designed to take advantage of the directional permeabilities associated with the fracture system. Geologic control has been integrated with performance data to describe the spatial variation in fracture-enhanced permeability. Comparisons of injection performance and core-derived permeability thickness data permitted quantifying the influence of the fractures on reservoir flow capacity. An areal map representing the effective flow capacity of the Norman Wells reservoir is assisting in the selection of workover candidates. Initial performance data confirms matrix continuity and localized incidence of fracture-related water breakthrough. The development of a more complete reservoir description supports the ongoing optimization of production and injection operations. Introduction In 1920, Imperial Oil drilled the Norman Wells discovery well 1500 km north of Edmonton (Fig. 1). Production was limited lo 36 wells located on the mainland and two natural islands, Bear and Goose, until l981. At that time, Esso initiated an expansion of this pool using the latest technology in artificial island construction and directional drilling to access the reservoir lying between 450 m to 750 m beneath the Mackenzie River. The reef dips structurally to the southwest at 4,5 degrees with oil trapped in the updip portion. The oil-in-place is currently recognized as 87 mllion m3 Pool performance has matched or exceeded expectations since initiating the field-wide waterflood. The current average daily production is 4100 m3 (Fig. 3) and gas-oil ratios have responded favourably to water injection. The predevelopment concern that natural fractures would dominate flow and limit recovery because of early water breakthrough has not occurred. Patterns with breakthrough are not displaying profiles of dramatically increasing water rates. Water injection in the pre-expansion area of the mainland commenced in 1980 and the largest portion of produced water volumes originates from this area. The presence of the natural vertical fracture system and their unknown impact on performance created a need to quantify fracture influence on permeability. The objective was to develop an areal map of effective permeability thickness to allow:evaluation of observed well productivities and injectivities,identification of workover candidates,support of reservoir simulation efforts directed al quantifying rate profiles and recovery projections for individual patterns, andprediction of fracture impact on breakthrough characteristics for specific patterns.