A major operator was experiencing severe scale deposition in a deep, hot gas well in Mobile Bay, Gulf of Mexico. The deposits primarily consisted of calcium carbonate, with much smaller amounts of mixed calcium fluoride, lead and zinc sulfide scales. A squeeze application was the desired treatment, but test work had to be performed to ensure the chemical would not cause damage to the formation. Although scale deposition in the production wells are common, no such scale inhibitor application had been attempted in this region previously, primarily due to concerns for formation damage in this complex and extremely high temperature (≥204°C) Norphlet sandstone formation.

Core flooding tests were performed in the laboratory at 204°C to simulate the squeeze treatment using actual core material from the well. Once a suitable scale inhibitor product had been identified, core flood tests were performed by injecting gas and brine through the core and assessing the change in permeability.

Historically scale buildup had been found in the subsurface safety valve and production tubing deep downhole. Steady productivity declines were observed after each near wellbore acid stimulation. When the untreated well had to be shut-in, it often experienced a decline in production upon restart if not a complete well loss. Since the squeeze has been performed in the field, the well has maintained the production in spite of being shut-in and reactivated numerous times due to hurricanes or other tropical storms.

This paper documents the first ever successful scale squeeze treatment in this extremely hot and complex reservoir formation. It describes the results from the detailed lab work leading up to the successful implementation of the scale inhibitor treatment in the field. The paper also discusses the results seen in the field following treatment.

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