First developed in 1990, intensive studies that were conducted after 10 years of production of the Tunu field showed that due to its heterogeneity, the lateral connectivity of the Tunu reservoirs was not sufficiently addressed by the initial drilling pattern. The next phases of Tunu development plan would then involve the drilling of infill wells with reduced spacing. By 2005 the operator estimated that 800 new wells would need to be drilled, at a rate of 60 wells per year, in order to maintain the field potential and achieve the targeted recovery factor. In addition, with low incremental reserves per well, the main challenge that the operator faced, was to reduce the cost of drilling infill wells, to preserve the economics of the development projects. The stakes for cost reduction were very high, as the Tunu field represented half of Mahakam PSC's remaining gas reserves and was expected to remain its biggest producer for years to come. This paper illustrates the different design and operational optimization efforts that have been undertaken since 2005 in the framework of cost reduction exercises involving different disciplines: drilling, completion, surface facilities, and development project. Analysis performed in 2008 showed that, at constant market conditions, the successful optimization process on 2 projects sanctioned in 2006/2007 contributed to around 300 MUSD of savings, whilst long term potential cost savings are estimated to be more than 2 BUSD of the 8 BUSD initial capex estimate.