To optimise recovery in naturally fractured reservoirs, the field-scale distribution of fracture properties must be understood and quantified. We present a semi-deterministic method to systematically predict the spatial distribution of natural fractures and their effect on flow simulations. This approach enables the calculation of field-scale fracture models. These are calibrated by geological, well test and field production data to constrain the distributions of fractures within the inter-well space. First, we calculate the stress distribution at the time of fracturing using the present-day structural reservoir geometry. This calculation is based on geomechanical models of rock deformation such as elastic faulting. Second, the calculated stress field is used to govern the simulated growth of fracture networks. Finally, the fractures are upscaled dynamically by simulating flow through the discrete fracture network per grid block, enabling field-scale multi-phase reservoir simulation. Uncertainties associated with these predictions are considerably reduced by constraining and validating the models with seismic, borehole, well test and production data. This approach is able to predict physically and geologically realistic fracture networks. Its successful application to outcrops and reservoirs demonstrates there is a high degree of predictability in the properties of natural fracture networks. Several examples show the success of the method in singleand multi-phase fields. In cases of limited data-where stochastic models typically fail-this method remains robust.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper describes a Permian evaporite carbonate gas field that has been plagued by severe water problems since it was put on production in the mid-80s. The field is a carbonate complex consisting of three communicating reservoirs that are heterogeneously fractured. Matrix permeability is typically less than 2 mD, except in one highly permeable streak, where it can be as high as 5 D. The permeability of the natural fracture network is extremely heterogeneous, and varies by up to a factor 100 over the field. Complex interaction between fractures, matrix and the highly permeable streak caused a surprising pattern of water breakthrough, which can be explained by a geomechanical model for the heterogeneous natural fracture network. This predictive, field-wide fracture model was validated and constrained by both geological and flow data. First, the stress distribution around seismically visible faults was calculated assuming homogeneous, isotropic, linear elastic rock mechanical properties, and frictionless faults. Second, the calculated stress field was used to simulate the growth of discrete fracture networks, which were constrained by statistically comparing fracture orientation and connectivity with that derived from core, BHI, PLT, mud loss, and well test data. Finally, the fracture networks were upscaled dynamically to the grid of a dual-permeability simulator, enabling fieldscale multi-phase reservoir simulation. The flow model obtained this way matched historical production data from all wells. It also explained the source of water breakthrough and the inflow profile seen on PLTs. Integrating seismic, borehole, well test and production data to constrain and validate such a field-wide model considerably reduced the uncertainty in the final predictions.This integrated, predictive fracture model is presently used to investigate future field development scenarios. To this end, the model is coupled to a surface network simulator, which comprises the whole infrastructure. The fully coupled surface and subsurface models offer the flexibility to optimally plan the position and timing of new wells, the size of compressor units, additional in-field trunk lines and the gas offtake.