Reservoir drill-in fluids are specifically designed to avoid excessive fluid penetration and solid invasion into production zones so as to minimize formation damage. With wellbore temperatures increasing, the drive to develop thermally stable drill-in fluids has increased dramatically over the last few years. Oil-based or synthetic-based drill-in fluids can meet temperature requirements easily, but are often not desirable for drill-in applications. Brine-based drill-in fluids usually use bio-based polymers as viscosifiers, but they are not suitable for high temperature applications because most bio-based polymers break down at temperatures above 300°F. Most synthetic polymers available in the market are difficult to hydrate in concentrated brine solutions, and they are not so thermally stable because of hydrolysis, especially when the temperature is above 350°F. This paper describes the application of two uniquely developed polymers in brine-based drill-in fluids that demonstrate outstanding performance at temperatures greater than 400°F.

Polymer 1 is designed to work with monovalent brines, and polymer 2 is intended for divalent brines. Using these two polymers, thermally stable, brine-based drill-in fluid formulations were prepared with densities ranging from 10.5 to 18 ppg. Various brine and weighting agent combinations were investigated to keep the total amount of solids low for the various fluid densities tested. Calcium carbonate (CaCO3) was used as a bridging and weighting agent for low density fluids, and manganese tetroxide (Mn3O4) was used for high density fluids. All fluids were prepared using a multimixer, and the fluid viscosity was examined with a direct-indicating viscometer. Return permeability testing was conducted on both a lower permeability Kirby sandstone core and a higher permeability Berea sandstone core.

Both polymers provided very good rheology and solid suspension capability, as well as very good fluid loss control. The drill-in fluids made with these two polymers were statically aged at 400°F for 72 hours after conditioning the fluid by hot-rolling for 16 hours at 150°F. The viscosity of the fluids was well maintained after aging, and the high temperature (350°F/500 psi) fluid loss was less than 15mL and 10 mL for polymer 1 and polymer 2, respectively. The thermally stable brine-based drill-in fluids demonstrated high return permeability values, indicating minimal formation damage on the tested cores.

High temperature brine-based drill-in fluids are limited by the availability of thermally stable viscosifiers and fluid loss control additives. The newly developed polymers 1 and 2 provide thermal stability up to 400°F for 72 hours, which has not been achieved with previous bio-based polymers or other synthetic polymers.

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