3D Fracture Permeability Modelling in Offshore Arabian Gulf Reservoir

Abstract Characterization of fractures and their role in reservoir performance have continued to be a difficult issue to handle. Recent advances in geostatistics and geomechanical 3D modeling capabilities have given workers a helping hand into assessing routine description of fractures in terms of better understanding of their geologic control and integrate them into reservoir engineering models. Published information working under the presumption that, on average, total permeability incorporating matrix and fracture contribution should equal to test permeability in reservoirs with single porosity models. On this basis, we have developed stochastic method, which offers means of predicting fracture permeability distribution field-wide and better accounts for water encroachment trends. The work was done on a carbonate reservoir of offshore Abu Dhabi. The reservoir is deposited in an overall finingupward rock succession that is interspersed by fine-scale sequences of sedimentation. The environment is characterized by broad transgressive event punctuated by minor cyclicity and hiatuses due to relative sea level changes. Strain field over the reservoir, which correlates with test permeability, is here obtained from curvature analysis and calibrated to strain calculated from core fractures. High strain areas are set to be associated with highly fractured zones that are commonly marked by increased conductivity (Heffer et al., 1994). Computer module computes fracture permeability from a power-law relationship and conditions it to match interpreted test permeability in 3D space. Comparison of modeled permeability with actual test permeability values suggests that there is a genuine permeability contribution from fractures in the reservoir. The matrix permeability model and the strain model are combined geostatistically so that the resultant permeability model matches well test permeability. The results helped achieve better history match results more easily than would have been possible without the combined model. It should be noted that the curvature technique used to estimate the strain field encapsulates a range of uncertainties that include strain estimates, detailed of fracture spatial geometry, and shear/strike-slip movements. Better strain field determination and 3D seismic data can improve the results. Introduction This work evaluates effects of open natural fracture networks on total permeability of Zone-I reservoir system. Zone-I is a shallowing upward carbonate reservoir composed of predominantly grainstone and packstone with subordinate wackestone/mudstone rocks. The structural development history of fractures in the zone is interpreted from a collage of information. The information includes well cores, FMI/FMS images, dipmeter logs, wireline logs and lateral thickness variations. Collectively, this data suggests that there are at least five elements contributed to the development of fractures in Zone-I reservoir. 1) Rejuvenation of Permo- Triassic N-S-trending basement normal faults, which generated intense fracturing whose trend spans from NNW to NNE. Fractures produced are mostly closed, mineralized and associated with regional lineaments crossing the field. 2) Upper-Middle Cretaceous rotation of crestal blocks resulted in parasitic fracture system with left lateral shears trending NE-SW. 3) Synthetic fractures emanating from and orthogonal to the rotated basement faults are observed crosscutting the reservoir. 4) Curvature and fracture trend analyses indicate that the prevailing tectonic stress orientation over the field is about N10 °E.