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Integrated Characterization and Multi-Well Flow Simulation of Tight Oil Shale Resources

Abstract

We present an integrated approach for characterization and flow simulation of tight oil shale at pad scale, combining well logs, seismic data, outcrop analogues and historical production. Subsurface heterogeneity relates to lateral variations in lithofacies, which translate into variations in matrix permeability, porosity, water saturation and mechanical properties; it also relates to variations in permeability and rock strength associated to the presence of natural fractures. Data from a pilot hole and 8 horizontal wells were used in combination with results from seismic inversion to model lateral and vertical variations in matrix properties. Seismic attributes, microseismic data and outcrop analogues were combined to model subsurface distribution of natural fractures. We modeled joints and small faults, with fracture spacing controlled by strain and fault proximity. Joint height and spacing were also controlled by bed thickness. Heterogeneity in rock properties, introduced by variations in lithology and fracture density, can have a significant impact on hydraulic stimulation and well performance. The final result of this static reservoir characterization is a geological model for both matrix and natural fractures that is consistent with borehole and seismic data. The static model was validated through flow simulation using single porosity, double porosity and dual permeability modeling approaches, to understand how each best reflected the flow and pressure behavior between the matrix and fracture systems. Hydraulic fracture properties were a simulation matching parameter, constrained by RTA and hydraulic fracture modeling. To improve consistency between parameters used for flow simulation and RTA, joints and matrix properties were combined together and only small faults were included in the final simulated fracture network. Dual permeability modeling enhanced the impact of heterogeneity as compared to the single porosity approach. Using a similar geological model, dual permeability generated a more heterogeneous distribution of pressure behavior with consistent history matching of multiple wells. In contrast, after adjusting history-matching parameters, single porosity generated a more uniform distribution of pressure depletion. This analysis concluded that, for this geological scenario, dual permeability simulation better captures the heterogeneity introduced by lateral variations in permeability and rock strength associated with natural fractures.