The Pyrenees development is located offshore Western Australia, and has been producing since 2010 under the operatorship of BHP Billiton Petroleum. Six heavily biodegraded, low GOR oil fields are developed by 19 horizontal production wells with reservoir sections up to 3000m long. Each field has between 1 and 6 gas lifted production wells connected by separate production and test flowlines to a Floating Storage Production and Offtake (FPSO) vessel. As field water cuts progressed above 10%, an increasing deviation between predicted and actual flowline pressure drop was observed and indicated the formation of emulsions in the wells production tubing and flowlines. The additional flowing pressure loss and consequent reduction in production rates formed the basis for a debottlenecking project to treat subsea emulsions. After identification of a suitable demulsifier chemical through laboratory testing, chemical treatment was initially undertaken via injection at the subsea manifolds. Initial demulsifier field trials yielded a 4% increase in field oil production. In an attempt to realise further pressure drop reduction, the opportunity for downhole injection at each well was investigated. As downhole chemical injection had been initially designed for scale inhibitor, flow assurance studies were performed to ensure repurposing the downhole lines would not result in an elevated calcite scaling risk in subsea equipment. Field implementation of downhole chemical injection across the available wells resulted in an additional 18% field oil production uplift, with individual wells achieving up to 50% increase in drawdown and 58% increase in liquid production. Additional benefits attributed to downhole demulsifier injection include improved gas lift efficiency and stabilised flow regimes and pressures observed at the downhole gauges and topsides risers. This paper provides a unique case study in opportunity identification and multifaceted problem solving to significantly and safely debottleneck production. An innovative solution was found by relocating the injection location and repurposing existing topsides and subsea equipment with very low additional capital investment. The lessons and processes used in this project may be carried across to other existing fields and facilities to assist identifying and resolving related flow assurance bottlenecks.