Abstract Inorganic salt scaling is a major and costly challenge in the oil and gas industry that requires proactive mitigation to ensure long-term well reliability, yet the effectiveness of chemical scale inhibitors depends on accurate prediction of scale-forming conditions based on detailed scale and produced water chemistry. Accordingly, this study analyzes eight produced water samples and associated scale deposits from three oil-producing wells in the Williston Basin’s Bakken formation. The PW was highly saline (TDS ≈ 275,000 mg/L) and moderately acidic, with an average pH of 6.67 ± 0.26. Sodium (80,746 mg/L), calcium (19,221 mg/L), and chloride were the dominant ions, while sulfate (311 mg/L) and trace metals such as Ba 2 ⁺, Sr 2 ⁺, and Mg 2 ⁺ were present at lower concentrations. Phosphorus-based squeezes exhibited a decrease in Ca-bearing crystalline phases at the wellhead but not near the wellbore, where calcium- and strontium-rich deposits persisted. Distinct compositional shifts were observed across equipment and operations: Drilling-phase (BHA) scale was carbonate-dominated, whereas production-tubing scale consisted primarily of magnetite and silica. At near-wellbore region, a clear inner–outer asymmetry was observed with inner aragonite-rich deposits and outer apatite-type inhibitor-scale complexes. Acid-solubility tests further distinguished these phases, with BHA carbonate-rich scale showing > 70% solubility in 15% HCl. Overall, the results show that phosphorus-based squeeze treatments reduced wellhead scale formation but were less effective at preventing calcium and strontium buildup near the wellbore during production. These integrated water–scale correlations offer a practical first-pass tool for assessing treated wells, supporting improved scale management and long-term production sustainability.
Talukder et al. (2026) studied this question.