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Summary The extent to which fractures affect fluid pathways is a vital component of understanding and modeling fluid flow in any reservoir. We examined the Wafra Ratawi grainstone for which production extending for 50 years, including recent horizontal drilling, has provided some clues about fractures, but their exact locations, intensity, and overall effect have been elusive. In this study, we find that a limited number of total fractures affect production characteristics of the Ratawi reservoir. Although fractures occur throughout the Wafra field, fracture-influenced reservoir behavior is confined to the periphery of the field where the matrix permeability is low. This work suggests that for the largest part of the field, explicit fractures are not necessary in the next-generation Earth and flow-simulation models. The geologic fracture assessment included seismic fault mapping and fracture interpretation of image logs and cores. Fracture trends are in the northeast and southwest quadrants, and fractures are mineralized toward the south and west of the field. Pressure-falloff tests on some peripheral injectors indicate partial barriers, and most of these wells lie on seismic-scale faults in the reservoir, suggesting partial sealing. A few wells show fractured-reservoir production characteristics, and rate-transient analysis on a few producers indicates localized dual-porosity behavior. Producers proximal to dual-porosity wells display single-porosity behavior, however, to attest to the notion of localized fracture response. The spatially restricted fracture-flow characteristics appear to correlate with fracture or vug zones in a low-permeability reservoir. Presence of fracture-flow behavior was tested by constructing the so-called flow-capacity index (FCI), the ratio of khwell (well test-derived value) to khmatrix (core-derived property). Data from 80 wells showed khmatrix to be consistently higher than khwell, a relationship that suggests insignificant fracture production in these wells.

AbstractThe extent to which fractures affect fluid pathways is a vital component of understanding and modeling fluid flow in any reservoir. We examined a Lower Cretaceous grainstone for which production extending over 50 years, including recent horizontal drilling, has provided some clues about fractures, but their exact locations, intensity and overall effect have been elusive. This study attempts to discern open fractures, if any, and their locations to facilitate building next generation earth and flow-simulation models.The geological assessment involved mapping fault orientations from seismic and analyzing image logs and cores for fractures. Fracture trends are in the NE and SW quadrants and fractures are mineralized toward the south and west of the field. Pressure falloff tests on some peripheral injectors indicate partially sealing faults. Most of these wells lie on seismic-scale faults mapped in the reservoir. Some wells show fractured-reservoir production characteristics and rate-transient analysis on a few producers indicates localized dual-porosity behavior. Producers proximal to dual-porosity wells display single-porosity behavior, attesting to the notion of localized fracture response. The spatially-restricted fracture signature may be owing to fracture or vug zones, or to low-permeability reservoir.Presence of fractures was discerned by constructing the so-called flow-capacity index (FCI), which is the ratio of khwell (welltest-derived value) to khmatrix (core-derived property). Data from 80 wells showed khmatrix to be consistently higher than khwell, with the p-50 reciprocal-FCI being 13, a relationship that suggests insignificant fracture production in these wells.