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| Petroleum Geoscience |  |
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1 Fault Analysis Group, Department of Geology, University College Dublin, Dublin 4, Ireland (e-mail:fault{at}fag.ucd.ie)
2 Fault Analysis Group, Department of Earth Sciences, University of Liverpool, Liverpool L69 3BX, UK
Faults are represented conventionally in production flow simulation models using transmissibility multipliers which capture the single phase, but not the two phase, fault-rock properties. Available data indicate that fault-rocks have similar two phase properties to sediments of the same permeability, hence existing methods can be applied to estimate two phase fault-rock properties from their intrinsic permeabilities. Two methods of representing the two phase fault-rock properties implicitly in the flow simulator are compared, using one-dimensional numerical flow models containing water-wet faults with imbibition capillary pressure curves. The method which is the closer two phase analogue of the single phase transmissibility multiplier is inappropriate, as the implementation is unreasonably unwieldy. A simpler implementation is to derive pseudo-relative permeability functions including the fault-rock properties in the upstream grid block; these properties are then incorporated directly in the simulator. Relative transmissibility multiplier functions can be back-calculated from the pseudo-relative permeability functions, and indicate how closely the single phase multiplier approximates two phase flow through the fault. Implementation in a 3D model with complex fault juxtapositions validates the approach, and a practical workflow for the routine inclusion of two phase fault-rock properties in conventional faulted flow simulation models is outlined.
KEYWORDS: fault (geology), relative permeability, capillary pressure, flow model
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