Novel High Density Brine-Based Drill-In Fluids Significantly Increased Temperature Limit for HP/HT Applications

Abstract

Abstract Drill-in fluids, also known as reservoir drilling fluids, are specifically designed to help minimize formation damage and facilitate wellbore cleanup. Typical water-based drill-in fluids use brines to achieve a desired fluid density and rely on acid-soluble solids, such as calcium carbonate, for bridging of pore spaces. Biopolymers, such as xanthan gum and crosslinked starch, are generally used as viscosifiers and fluid-loss additives for the drill-in fluids. Unfortunately, these biopolymers begin to degrade at temperatures greater than 275°F. As a result, conventional water-based drill-in fluids are generally limited to wells with temperatures below 300°F. Clay-free, brine-based drill-in fluids for temperatures greater than 300°F still pose challenges in high-pressure/high-temperature (HP/HT) conditions. Novel high density brine-based drill-in fluids have been developed using a specifically designed dual-functional polymer as a thermally stable viscosifier and fluid-loss additive. Divalent brines, such as CaBr2 (14.2 lbm/gal) and CaCl2 (11.6 lbm/gal), were used as the base fluids. The drill-in fluids show similar thixotropic behavior to those biopolymer-based, yet exhibit excellent thermal stability up to 450°F, which is at least 150°F higher than typical drill-in fluids. After static aging at 450°F for 16 hours, the fluids exhibited only slight color change, and no stratification or solid settling was observed. Rheological properties of the aged samples increased slightly compared to samples before aging. The samples still provided excellent fluid-loss control, even after aging, with a measured HP/HT fluid loss less than 10 mL after 30 minutes at 350°F. Core flow testing showed that the drill-in fluid is nondamaging after acid breaker treatment, with a return permeability of 100%.