Norman Wells is a Devonian-age carbonate bank complex located in the Northwest Territories of Canada, 60 kilometres south of the Arctic Circle. The bank complex reaches a maximum thickness of 130 metres in the bank and thins towards the basin, due to a combination of bank-margin backsteps and depositional pinchout. Norman is an oil reservoir with approximately 108 million cubic metres (680 million barrels) of original oil in place. The reservoir is naturally fractured with low matrix permeability (avg. 2 to 4 millidarcies). Previous 3-D modeling efforts Norman Wells did not attempt to incorporate fracture permeabilities, resulting in discrepancies among the static dynamic reservoir models and historical field performance data. In the present study, a 3-D geologic model was constructed to quantify the combined affects of matrix and fracture properties on total, full-field permeability. Matrix and fracture properties were modeled separately, and then combined into a total permeability model. Matrix properties vary as a function of depositional facies and the sequence-stratigraphic framework. Core and log data were used in combination with facies and stratigraphic information to develop the 3-D porosity and matrix permeability models. Fracture permeabilities were modeled using a two-stage approach. First, in mjection and production data were used to isolate model the fracture component of total permeability within the reservoir (fracture-enhanced permeability). Second, geometric fracture properties (orientations, sizes, densities) measured from core, image logs and outcrop data were used to quantify fracture geometries and the resultant flow anisotropy (directional permeability). Structural, stratigraphic, and facies information were incorporated into the 3-D model framework and used to guide the allocation of fracture permeabilities away from well control.

Modeling results show that fractures variably enhance matrix permeabilities and that, without fracture enhancement, significant areas of the Norman Wells reservoir would be non-commercial. In most areas of the reservoir, the fracture network is developed at an optimum level to enhance matrix permeabilities without significant impact on reservoir conformance. However, some areas of the reservoir are more highly fractured, resulting in injected-water breakthrough and reduced reservoir conformance, Fracture properties vary in a predictable manner as a function of structural position and the mechanical stratigraphy of the carbonate bank. Fracture influence is greatest along the bank margins and in the steeper dipping, updip (northeast) structural region of the reservoir. Using this new model, a history match of production performance was achieved rapidly and required little modification of permeabilities in the flow simulator. Benefits of incorporating dynamic data directly into the 3-D geologic model include 1) reduced need for adjusting permeabilities in the flow simulator, resulting in increased consistency between the static and dynamic models, and 2) geologic information is used to guide the distribution of the excess permeability rather than ad-hoc adjustments in the flow simulator. The new static and dynamic models are being used for reserves and production forecasts, opportunity identification, and field management.

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