The Guntong field is currently the largest waterflood field and a major oil producer in Peninsula Malaysia. The field and its development are highly complex, resulting in various challenges in the areas of reservoir description, reservoir management, and facilities optimization. This paper showcases key challenges and the evolution of the field depletion plan as the complexities were identified and better defined. Based on actual performance, and updated geoscience and reservoir engineering studies, various changes to the original depletion plan are being implemented even after 17 years of production. The changes range from a revision in waterflood operating pressure strategy, to innovative facilities optimization, and the more expensive workovers and infill drilling,. Effective teamwork by multi disciplinary team members also played a major role in transforming the challenges into opportunities. The implemented changes to-date have successfully increased production and reserves. Introduction The Guntong field is a large anticline of about 12 km long and 7km wide, located 210km offshore Terengganu, Malaysia (Fig. 1). It was discovered in 1978 and a total of 9 exploration wells were drilled. Two major north-south trending faults divide it into three fault blocks; East, Central, and West. Field development started in 1985 and a total of 138 development wells have been drilled through 1997. ExxonMobil Exploration and Production Malaysia Inc. operates the field in partnership with PETRONAS Carigali Sdn Bhd, as Production Sharing Contract (PSC) contractors to PETRONAS, the national oil company of Malaysia. The first 3D seismic survey was acquired in 1985 and was extensively used to formulate and enhance the original field development plan. A newer 3D seismic survey was acquired in 1998 and fieldwide geologic studies were recently completed which integrate the seismic data, sequence stratigraphy, improved formation evaluation, and performance data. Reservoir Description Hydrocarbon-bearing reservoirs are primarily mid-Miocene sandstones deposited in fluvial/tidal/deltaic environments. There are fifteen vertically stacked, highly heterogeneous reservoirs, cut by numerous channels and faults. As depicted by the cross-section (Fig. 3), these reservoirs have variable reservoir thickness, quality, areal extent, gas cap size, fluid contacts, and oil column thickness. The main reservoirs are in the group I sandstones, sub-divided into the Upper I group consisting of the I-10 through I-45 reservoirs, and the Lower I group which is made up of the I-60 through I-104 reservoirs.The major reservoirs are the I-10, I-25, and I-70, containing close to 75% of the total field recoverable reserves. Reservoir quality varies significantly. An example is the contrast between the clean I-25, which consists largely of fluvial deposits and the more stratified I-10, which is mainly subtidal and intertidal deposits (Fig. 3) Also present are the group J reservoirs, which are generally of poorer quality with thinner oil columns. However, this paper focuses on the group I reservoirs, and primarily the I-10 and I-25 reservoirs.