Design Criteria and Application of High-Density, Brine-Based Fracturing Fluid for Deepwater Frac & Packs

Abstract

Abstract Completing deepwater Gulf of Mexico (GOM) wells with depths greater than 20,000 ft and high geopressure may require the use of higher-density fracturing fluids to reduce high wellhead treating pressures. In Shell's Deimos field, frac fluid density of up to 12.5 ppg was required. Although the industry has pumped 11.5 ppg NaBr-based borate cross-linked fracturing fluids, a 12.5 ppg NaBr-based borate cross-linked fracturing fluid has not been used until now. There are many challenges when applying a 12.5 ppg NaBr-based borate cross-linked fracturing fluid. The 12.5 ppg NaBr high-density, brine-based fluid has significantly different rheological behaviors than typical fracturing fluids made with freshwater or low salt concentrations. The high-density, borate cross-linked fluid responds very differently to shear history and recovers much more slowly than does freshwater-based fluid. Breaker efficiency is also very different. The high-density, brine-based fracturing fluid is potentially incompatible with formation crude. Base brine quality was also critical to final fluid quality and quality control procedures had to be better defined. Shell developed lab and field QA/QC protocols to ensure the fluid met the frac & pack job requirements. With rigorous fluid testing and optimizations, three wells in the Deimos field were successfully completed in 2007. This paper summarizes the extensive rheology, fluid compatibility, fluid optimization, and fluid QA/QC processes. It also summarizes important aspects in the application of 12.5 ppg NaBr-based fracturing fluids. This paper will also discuss friction pressure, treatment pressure, actual frac & pack job performance, and postjob production data. The fracturing fluid design and test methodology applied in these three Deimos wells are also very beneficial to design and optimization of other kinds of fracturing applications.