YOSE, LYNDON A.¹, TIM L. DAVIS¹, STEVE J. BROWN², GARY S. KOMPANIK³, THORSTEN EIBEN⁴, and PAUL LAPOINTE^4
1Exxon Production Research Co., Houston TX
²Imperial Oil, Calgary AB, Canada
³Exxon Exploration Company, Houston, TX
⁴Golder Associates Inc., Seattle WA

Abstract: 3-D Permeability Model of a Fractured Carbonate Reservoir: Norman Wells, NWT, Canada

Fractures influence fluid flow in many carbonate reservoirs including giant oil fields of the Middle East and Pre-Caspian Basin. The challenge lies in quantifying the geometric and hydraulic properties of the fracture system, and, ultimately, the impact of fractures on fluid flow and reservoir producibility. Norman Wells is a naturally fractured limestone reservoir with low matrix permeability (avg. 2-4 md.). A 3-D geologic model was constructed to quantify the combined affects of matrix and fracture properties on total, full-field permeability. Fracture permeabilities were modeled in a continuum model using two approaches: 1) "excess" (greater than matrix) permeabilities were calculated from reservoir engineering data (total kh - matrix kh) and then distributed away from data using geostatistics, and 2) geometric properties (orientation, size, intensity) calculated from oriented core image logs and nearby outcrops were used to model the fracture network and to allocate directional permeability. Fracture properties were found to vary in a predictable manner as a function of structural position, reef facies (texture) and mechanical layer thickness (bedding). These geologic parameters were built into the 3-D model framework and used to further constrain permeability interpolations. Modeling results indicate that most of the total permeability is contributed by fractures. Further, swarms and connected fracture compartments create permeability extremes (100's of md.) that dominate flow and locally compromise sweep. Directional permeabilities along fracture sets create flow anisotropy and vary with structural position within the reservoir. The 3-D model will be used as input for flow simulation and, ultimately, to direct future reservoir optimization strategies.

AAPG Search and Discovery Article #90928©1999 AAPG Annual Convention, San Antonio, Texas