The development of deepwater reservoirs requires thorough planning as well as the ability to quickly respond to changing downhole situations. During development drilling of a deepwater subsalt reservoir in the Gulf of Mexico1, a critical production liner could not be placed across the reservoir. Maximizing well productivity made an open hole completion a possibility. Like many reservoirs in the deepwater Gulf of Mexico, a shale barrier existed in the production sand between the upper and lower portions of the reservoir. Accessing the reserves below the shale using an open hole completion requires that the well production screen be placed through the shale. This further complicates the drill-in fluid design requiring that the fluid provide wellbore stability in addition to being non-damaging to reservoir productivity. Conventional fluid design for wellbore stability typically exposes unstressed shale pieces to the fluid. These exposed pieces are evaluated for their integrity. In this situation, the results were found to be misleading. Utilizing shale from a full size core of the reservoir section, the initial drill-in fluid formulation was tested under equivalent downhole conditions of effective stress, differential pressure, and temperature. The results indicated that the fluid would not be suitable for shale stability. After reformulation with different shale stability additives in much higher concentrations, the drill-in fluid performed acceptably with regard to shale stability. The results of the downhole simulation testing using the reformulated fluid compare favourably with a non-aqueous synthetic fluid formulation like the fluid typically used to drill this reservoir

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