Preparation and Performance Evaluation of Temperature- and Salt-Resistant Hydrophobically Associated Polymer...

The development of deep oil and gas resources faces the challenge of high-temperature environments, where the performance of traditional fracturing fluids is limited. Therefore, there is an urgent need to develop fracturing fluid systems capable of withstanding high-temperature (up to 200 °C) and high-salinity (up to 45 g/L NaCl and multivalent ions) environments. This study explores the preparation and performance evaluation of a novel high-temperature (up to 200 °C) and salt-resistant (up to 45 g/L NaCl and multivalent ions) hydrophobically associated polymer fracturing fluid, focusing on its thickening mechanism and stability under extreme reservoir conditions. Key equipment used includes a rheometer for viscosity measurements and an environmental scanning electron microscope for microstructure observation. The base fluid maintained an apparent viscosity of 32.4 mPa·s at 200 °C, demonstrating excellent thermal stability. Long-term evaluations showed a viscosity retention rate of 94.9% after 90 days in high-salinity conditions, indicating outstanding durability. Sand-carrying tests revealed ceramic grain settling rates below 0.48 cm/min, confirming strong suspension capability. The fracturing fluid system exhibited low formation damage rates of 16.85% and minimal proppant pack damage, with a conductivity reduction of only 20.08%, both well below industry standards. These findings provide technical support for efficient fracturing operations in deep and ultradeep wells, particularly in environments with temperatures up to 200 °C and salinities exceeding 45 g/L NaCl, contributing to the development of fracturing fluids for such challenging conditions.