甲酸盐加重瓜胶压裂液体系

为解决深层破裂压力高、常规压裂液难以压开的难题，开展了加重压裂液体系研究。由于压裂液需要进入到储层深部，因此要求加重剂具有良好的水溶性，而瓜胶压裂液需要在弱碱性环境中交联，因此强酸弱碱盐类加重剂，如氯化钙、氯化锌等不适用，溴酸盐（溴化钾、溴化钙等）虽可用但成本较高，难以应用，因此选择甲酸盐，该加重压裂液密度在1.0~1.5g/cm3范围内可调。受电性、分子量和分散性的影响，助排剂和黏土稳定剂可能与甲酸盐发生化学反应或物理作用，出现絮凝、析出或沉淀现象，通过实验优选出ME-1微乳助排剂和FP-2黏土稳定剂，结合流变性、滤失和破胶等实验，优选了与其配伍的有机硼交联剂等相关助剂，形成综合性能良好的加重压裂液体系。董8井压裂层段5 353.70~5 364.45 m，地层温度为120℃，优化加重压裂液（密度为1.2 g/cm3）现场配制工艺，成功地进行了现场应用；压后破胶液黏度小于5 mPa·s，返排率达100%。该加重压裂液技术为下一步的高闭合应力油藏的压裂改造提供了经验。 

Guar Gum Fracturing Fluids Weighted with Formates

In fracturing formations with higher fracture pressures, high-density fracturing fluids should be used because low-density ones have difficulties fracturing these formations. Weighting agents for use in fracturing fluids should have good water solubility because the fracturing fluids will go deep into the reservoirs. Guar gum fluids, which will crosslink in weak alkaline conditions, cannot be weighted with salts of strong acids and weak bases, such as CaCl2, ZnCl2. Bromide salts, such as potassium bromide, calcium bromide, can be used but are expensive. By balancing the cost and performance, formates were selected to weight fracturing fluids. The density of the fracturing fluid can be adjusted between 1.0 g/cm3-1.5 g/cm3. The performance of formates was affected by the factors such as electrophicility, molecular weight, and dispersity. The tendency of reaction (both chemical and physical) between cleanup additives, clay stabilizers and formates, may lead to flocculation, separation and precipitation of the fracturing fluids. To avoid these unfavorable factors, a micro emulsion cleanup fluid ME-1 and a clay stabilizer FP-2 were selected for use in the fracturing fluid formulation. An organo-boron crosslinking agent was selected through rheology, filtration and gel-breaking experiments. This fracturing fluid, with density of 1.2 g/cm3, has been successfully applied on the well Dong-8 to fracture the formation between 5,353.70 m and 5 364.45 m, with formation temperature of 120℃. The fracturing fluid, after gel breaking, had viscosity of less than 5 mPa·s, and was 100% flowed back. This weighted fracturing fluid technology has provided valuable experiences for fracturing high closure-stress reservoirs in the future.