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<p>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<sup>2</sup>⁺, Sr<sup>2</sup>⁺, and Mg<sup>2</sup>⁺ 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 &gt; 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.</p>

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Compositional Variation in Scale Products on Oil Field Equipment: Study in the Bakken Formation

  • 期刊论文

  • 出版模式：

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  • 发表日期：

    2026年5月7日

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  • Musabbir J. Talukder,
  • Ali S. Alshami,
  • Glavic Tikeri,
  • Nadhem Ismail,
  • Arash Tayyebi,
  • Ashraf Al-Goraee

摘要

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 Ba2⁺, Sr2⁺, and Mg2⁺ 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.