Calcium sulfate scale precipitation is a challenge especially during stimulation treatments. The main objective of this study is to mitigate calcium sulfate precipitation during fracturing treatment. With high sulfate content in source/mixing water up to 2,000 parts per million (ppm) and excessive of total dissolved solids (TDS) formation water that can reach 60,000 ppm calcium.

An experimental study was conducted at the reservoir downhole temperature of 280°F to evaluate the formation water compatibility with source water wells used for fracturing fluids. The sulfate content varied in the fracturing fluids up to 2,000 ppm. This paper addresses: the scaling tendency of water-water interaction; the efficiency and minimum inhobitor concentration of three commercial calcium sulfate scale inhibitors; the stability of high sulfate fracturing fluids at 280°F (138°C) with scale inhibitors.

This study indicated: water-water compatibility tests reinforce the mineral risk assessments findings for calcium sulfate scales, scale inhibitors were effective to prevent scale deposition when added at 1.5 gpt to the source water. The high pH-fracturing gelled fluids must be prepared using relatively low sulfate water (SO42- ≤ 500 ppm). The scale inhibitors, when added to the high pH-fracturing, gelled fluids at minimum inhibit concertation will not negatively affect the polymer gel rheology and adhesion.

The study set guidelines to prevent calcium sulfate scales issues during fracturing jobs with incompatible source and extreme salinities formation water. The lesson learned exhibits an effective practice to maximize treatment efficiency and minimize formation damage that could be induced during fracturing.

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