ADCO's onshore oil field lies along an elongated highly faulted northeast-southwest anticlinal trend. The main reservoirs are part of the Lower Cretaceous Upper Thamama Group, in particular the Shuaiba and Kharaib Formations interbedded with dense limestones. The impact of faults and associated fractures on fluid flow and reservoir connectivity within the field has been previously uncertain. Flow in these reservoirs is believed to be matrix dominated, but there is some evidence that fracturing enhances fluid flow in some areas as well as vertically across dense zones. This might become more pronounced with changes in reservoir pressure. This paper describes an integrated approach in detecting occurrence and disposition of fractures, their impact on fluid flow and sensitivity to changes of in-situ stresses.

ADCO has interpreted many faults from 3D seismic data, and has drilled a deviated cored well across a major fault in the reservoir. Core, logs, image log, petrographic analysis and pressure measurements across the fault have provided invaluable information and knowledge in understanding the relationships between fracture occurrence and rock mechanical/petrophysical properties. This is complemented with fracture characterization and structural interpretation from image logs of 32 vertical, deviated and horizontal wells. Finer scale structural information has been extracted from inspection of the cores from more than 30 wells.

Overall, fractures are scarce, but their occurrence has given encouraging correlation with (1) reservoir rock type, (2) porosity, (3) distance to fault and (4) structural anomalies evident in seismic curvature attributes. These correlations support the extrapolation of interpretations away from the wells to identify where fractures are most likely to affect reservoir performance. Quantification of the effect of such fractures on production have been calibrated using an integrated analysis of lab test scale permeability at different confining pressures alongside CT-scans identifying small scale fracturing, and in-situ permeability measurements from well tests and production logging of well intervals with imaged fractures.

The novel parts of the workflow are how this characterization has produced a 3D discrete fracture network model with apertures of fractures controlled by present or future in-situ stress. When this fracture model is integrated with the 3D geomechanical model, the upscaled directional fracture permeabilities have shown sensitivity to production behavior based on the degree of reservoir depletion / injection.

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