In this paper, experimental techniques have been developed to prepare and characterize chemical agents for augmenting injectivity in low permeability reservoirs. First, chemical agents are selected, formulated, and optimized on the basis of interfacial tension (IFT), scale inhibition ratio, and clay particle size distribution and specific surface area. The spinning drop method is utilized to measure the IFT between crude oil and the formulated solution, while contact angle between brine and rock surface is measured to examine effect of the chemical agents on the rock wettability. Also, scale inhibition ratio and antiswelling ratio are, respectively, measured by performing static-state scale inhibition experiments and centrifugation experiments. Then, displacement experiments are conducted to evaluate injectivity improvement after one pore volume (PV) of such formulated chemical agents has been injected into a core plug. It is found that the optimized solution consists of 0.15 wt % fluorocarbon surfactant FC-117, 4.00 wt % isopropanol, 1.20 × 10−3 wt % scale inhibitor 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTCA), and 1.50 wt % clay stabilizer diallyl dimethyl ammonium chloride (DMDAAC). The IFT between crude oil and the optimized solution can be reduced to 5.36 × 10−3 mN/m within a short time, while the scale inhibition ratio and antiswelling ratio are measured to be 94.83% and 86.96%, respectively. It is found from comprehensive evaluation experiments that such a formulated and optimized solution can not only alter the rock surface from oil-wet to water-wet but also reduce the scale formation of the reservoir brine. In addition, it is shown from displacement experiments that the pressure is decreased by 34.67% after the injection of such formulated solution. When the formulated solution contains 0–300,000 mg/L sodium chloride (NaCl) and 0–5000 mg/L calcium chloride (CaCl2) at 50–90 °C, the IFT between crude oil and the formulated solution can be reduced to lower than 10−2 mN/m.

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