Abstract Waterflooding remains one of the primary techniques for developing low-permeability reservoirs. However, scale accumulation caused by incompatible water mixing can lead to pore blockage and formation damage, resulting in elevated injection pressure and reduced water injection efficiency, which ultimately undermines the effectiveness of such development efforts. This study focuses on the Shuanghe oil area within the Yanchang Oilfield, China, where three distinct water sources—produced water from the Chang 6 reservoir, produced water from the Yan’an Formation, and surface water—are utilized for injection purposes. To address the challenges associated with water injection in this block, we conducted a comprehensive set of investigations, including reservoir sensitivity experiments, injected water quality analysis, and compatibility studies; notably, the wastewater treatment process has been optimized. Through these efforts, we systematically examined the conditions that lead to the formation of plugging factors during water injection. Our findings reveal that poor compatibility between the different injected water sources readily triggers the precipitation of inorganic scale upon mixing, which in turn clogs reservoir pores and drives up injection pressure. Specifically, when water samples from different sources in the Shuanghe oil area are mixed, they precipitate three main types of scale: calcium carbonate (CaCO₃), barium sulfate (BaSO₄), and strontium sulfate (SrSO₄). Among these, calcium carbonate and barium sulfate were the most abundant in mixtures of produced waters. Additionally, we observed a significant increase in calcium carbonate scale formation as both temperature and pH levels rose. Targeting the specific scale types identified in the block’s mixed-layer water, we implemented a two-pronged control strategy: pre-mixing the effluent waters and adding pH regulators. This approach proved effective in suppressing the formation of both carbonate and sulfate scales. Finally, core experiments were performed to assess the extent of reservoir damage caused by injected water. The results showed that after treatment, the core damage rate associated with mixed water injection was reduced to 15%.
Qi et al. (Thu,) studied this question.