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Dynamic Fault Seal Analysis Technology and Well Test Matching to Condition Full Field Reservoir Models in Corrib Field


Quantification of cross-fault flow and fault transmissibility multipliers is important for the development decisions, since the nature of hydrocarbon and water flow across faults will influence well counts, well placement, and ultimate recovery. The Corrib gas field discovered in 1996 lies 70 km offshore west of Ireland in 360 meter water depth. It is a faulted 4-way dip closure. Within the Sherwood Sandstone, extensional faulting with cataclastic fault rocks is the dominant expression of deformation. Two dominant fault families are present; one set dipping to the east and the other to the west. These faults mainly strike in NE-SW direction. Second generation ESE-WSW striking faults developed at a later stage of deformation probably as a result of sudden change in curvature and stress/strain states at the northern and southern flanks of the structure. Reservoir simulators of course do not include faults as cells, but rather calculate cross-fault flow using a transmissibility multiplier. This multiplier is a fraction that represents the ratio of the flow between two grid cells with and without the fault. For example, if a fault reduces the flow between two cells by 25%, the transmissibility multiplier is 0.75. The calculation of fault transmissibility multiplier as explained above does not capture all the physical variables required to give this value a realistic meaning. A large number of independent physical variables underpinned by water-tight structural model affect the magnitude of cross-fault flow. These physical variables were incorporated into the static reservoir model to generate realistic along fault properties. In order to condition the model as accurately as possible for dynamic simulation, a proprietary well test matching software was applied to enable matching of the short duration well test data both during the drawdown and build-up phases. In this workflow, a sector is taken out of the full-field model and re-upscaled using the underlying voxel permeabilities and a high degree of areal refinement in order to model the rapidly changing pressures proximal to the sandface. The full well test history was then simulated and reservoir parameters adjusted to match the observed test data. The integration of results from fault seal analysis and well test matching delivered significant business impact and demonstrated the value of fault seal dynamic modeling capabilities in locating the remaining hydrocarbon (LTRH) and reserves booking.