After the cementing of an oil well, part of drilling fluid is confined in the annulus between the cement and an isolation tool (pack off). During the production phase of a well, the confined fluid will be exposed to a temperature gradient due to the circulation of reservoir fluid through the production screen. This increase in the temperature causes a pressure evolution that can damage isolation.

Among several possibilities for APB mitigation, the strategy of communicating the annulus with a formation is often considered. In this case, when pressure reaches formation fracture, fluid would be drained from the annulus and thus, the pressure would be released. However, several authors claim that, after a period, barite sag in the drilling fluid will create an impermeable layer, which will prevent communication of annulus with the formation; and APB mitigation strategy would fail. These wells are placed in operation a few years after completion is concluded.

This article presents an extensive experimental task aiming the understanding of the effect of rheology on barite sag for different fluid concepts. The experiments consisted of long time sedimentation tests (monitored by gamma ray techniques) and a rheological characterization of the fluids. Fluids tested include new and aged Synthetic based systems. The role of particle diameter in the permeability of the sedimented bed was also investigated. The experimental results provide valuable guidelines for designing fluids aiming APB mitigation.

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