Economical and environmental concerns have forced the oil and gas industry to consider reusing flowback and produced water for fracturing operations. The major challenge is that the high-salinity of flowback water usually prevents its compatibility with several fracturing fluid additives. In this paper, the authors explored an economic and effective method to prepare guar fracturing fluids with different salinity waters. The main research idea was to use chelating agents to mask metal ions, such as calcium and magnesium, that are harmful to crosslinking. Firstly, a complexometric titration test was conducted to measure the chelating ability of three chelating agents. Secondly, through viscosity, crosslinking, and hanging tests, it was verified that the complex masking method could cope with the problem of high-valence metal ions affecting crosslinking. Thirdly, the preferred chelating agent was mixed with several other additives, including thickeners, crosslinkers, and pH regulators, to prepare the novel guar fracturing fluid. The comprehensive performances of the novel fluid system were tested such as temperature and shear resistance, friction reduction, gel-breaking performance, and core damage rate. The results show that the organophosphate chelating agent (i.e., CA-5) had the greatest ability to chelate calcium and magnesium ions. There was a good linear relationship between the dosage of CA-5 and the total molar concentration of calcium and magnesium ions in brine water. The main mechanism was that the chelating agent formed a complex with calcium and magnesium ions at a chelation ratio of 1:5. The test results of the comprehensive performance evaluation indicate that the prepared guar fracturing fluid met the requirements for field application, and the lower the salinity of the flowback water, the more it is economical and effective.

Hydraulic fracturing of deep, high-temperature reservoirs poses challenges due to elevated temperatures and high fracture pressures. Conventional polymer fracturing fluid (QCL) has high viscosity upon adding cross-linking agents and significantly increases wellbore friction. This paper examines a polymer fracturing fluid with pH response and low friction. Experimental results indicate that cross-linking occurs quickly in acid, while alkali can slow the cross-linking process and reduce friction. Sodium carbonate (Na₂CO₃) serves as an effective candidate. An optimized formulation consisting of “salt + pH + polymer + cross-linking agent” is proposed in two stages: low viscosity for fracture generation and high viscosity for sand transport. PH control enhances polymer hydration, increasing sand-carrying in the low-viscosity stage. Scanning electron microscopy (SEM) reveals that the fluid’s structure varies with pH, showing that alkali promotes a stable network structure. Infrared spectroscopy (IR) shows that higher pH increases negative charges of the polymer chains, which enhances their hydrodynamic radius, slightly raises viscosity, and enhances sand carrying. Field tests confirm the formulation’s effectiveness, leading to lower operating pressures, stable sand transport, and notable production, averaging 107.57 m³ of oil and 276 m³ of gas per day. Overall, this research provides low-friction solutions for the efficient development of deep reservoirs.