Full-scale laboratory drilling tests investigated the drilling performance potential of a number of different drilling fluids in three analogue rocks for the pre-salt formations offshore Brazil: Bonne Terre dolomite, Carthage limestone, and Navajo Gold travertine. High-pressure drilling tests were performed in each of these rocks using a total of nine different drilling fluids, including a synthetic-based fluid used as reference for performance comparison.

There was a consistent ranking of drilling fluids in terms of their penetration rate and mechanical specific energy in all three rocks. Several of the fluids tested showed penetration rates ∼50% higher and mechanical specific energies ∼35% lower than those seen with the baseline synthetic-based fluid. There was no clear correlation between good drilling performance and base fluid, rheology, or suspended solids. There was, however, evidence of a correlation between drilling performance and continuous phase viscosity; drilling performance apparently increased as the continuous phase viscosity decreased. This effect is consistent with a hypothesis that filtrate invasion into the damaged rock can relax so-called chip hold-down forces and thereby reduce their negative impact on the efficiency of the rock destruction process.

The results presented here yielded what is believed to be the first evidence that increasing drilling fluid temperature can lead to an increase in penetration rate and a decrease in mechanical specific energy when all other conditions and operating parameters are held constant.

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