Electrical Submersible Pump (ESP) failures have a range of root causes from reservoir solids/ sand, fracture proppant and asphaltenes within the intake assembly of the pumps to deposition of different types of inorganic scale on the motor. The formation of such scale deposits is not unusual, and the mechanism of formation is well understood but the fact that scale deposition and associated pump failures can be observed to occur at water cuts of <1% is less well understood. Treatments with scale inhibitor via continual injection are not always successful at such low water cuts and failure to inhibit scale can also be a result of poor understanding of the mixing point of inhibitor and brine vs the location of onset of scale formation. The deployment of conventional scale squeeze treatments can be associated with significant oil production losses which are commonly attributed to the treatment of low water cut wells with aqueous based scale inhibitors, and operational issues may be caused by the requirement to pull the pump if a bypass valve is not present.

This paper outlines the development of an effective treatment strategy for production wells that suffered significant performance impairment at water cuts below 5% due to carbonate scale deposited within the ESPs. These wells were treated with a mutual solvent and an oil soluble scale inhibitor squeeze treatment. Field results agreed with the laboratory qualification studies showing that the wells treated did not suffer any reduction in oil production rate and the ESPs were effectively protected from carbonate scale deposition.

This work was extended, and applications carried out within offshore fields in the GOM and West Africa where scale inhibitor was applied in fracture fluids programs used for frac pack operations to provide scale inhibition but eliminating the need for an initial squeeze at low water cut. The development of scale inhibitor compatible with the fracture fluids eliminated the need for expensive well intervention until the water cut of the wells exceeded 10% whereby the continual downhole injection system was able to protect the ESPs.

The paper highlights the need to understand the implication of the location of the ESP/motor within the completion in each well to allow assessment of the best scale inhibitor deployment strategy in each case. The selection of treatment strategy is discussed, along with the laboratory qualification studies required to select appropriate inhibitors. Case history data demonstrating successful deployment in the field for continual injection, solid inhibitors and squeeze application are presented, along with analysis of the risk factors to be considered when reviewing the scale formation potential over the lifecycle of a well in new field developments.

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