The Kestrel field is an 8-km sub-sea tie-back to the Tern platform in the Northern North Sea, and consists of two gas-lifted (GL) producers supported by a single injection well. Seawater broke through at P1 in the first half of 2004, and after several months at low seawater fractions a very rapid decline observed in the downhole pressure gauge was inferred to be caused by BaSO4 scale. Although the scaling tendency was predicted to be relatively low in this Brent-type reservoir ([Ba2+] < 30 mg/l in the formation water), other flow assurance causes, including sand production and liner collapse, were deemed much less likely.

The most cost-effective manner to confirm the inference of scale, as well as to recover lost productivity and prevent further deterioration in P1, was deemed to be a scale dissolver treatment deployed through the sub-sea GL line, via the crossover valve and into the well, followed by an inhibitor squeeze, similarly deployed. The rationale was that even partial recovery of productivity by the dissolver and/or arrest of further decline by the squeeze should confirm scale as the culprit. Although successful GL-line-deployed inhibitor squeeze had been reported earlier using a non-aqueous package, this was the first using conventional aqueous chemicals, as well as being the first deployed together with a scale solvent. Deployment of a solvent along the methanol line, reported elsewhere, was precluded in Kestrel by the small umbilical diameter and materials constraints. The main challenges in both Kestrel treatments included control of the fluid fronts, compatibility with the materials in the GL line, and prevention of hydrate formation, both at the start of the treatment and upon re-commencement of gas-lift injection.

We report how these challenges were met, and how GL-deployed treatments recovered productivity on P1 and demonstrated that scaling in the field could be managed in this manner in the future.

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