The results of a reservoir performance evaluation of a giant mature heavy oil field are presented here. This field began production in 1927. By 2002, cumulative production had surpassed half a billion barrels of low-gravity oil from Miocene sandstone formations produced under natural depletion, water and gas injection, and cyclic steam injection from more than 400 wells. As a result, several interdependent flow models including black-oil full-field, thermal single-well, and thermal large-sector models were built for field analysis and optimization. The long and complex production history, as well as the various recovery mechanisms, presented a number of challenges in constructing and calibrating the models to past historical performance. The optimization work was done in the following three stages. First, a coarse-grid black-oil model was constructed to study the field performance prior to steam injection, following the successful geological modeling phase of this project (presented in Márquez et al., 2001 1). The second stage involved single-well and sector-model thermal simulation analysis. The thermal models were used to match the field historical pressure and production data over the natural depletion, water injection and cyclic steam injection periods.T hird, we investigated the field performance under different development scenarios. Optimization results with the single-well thermal models were incorporated into the sector models, which were used for processing runs to examine infill drilling; recompletion of active wells; waterflooding; huff ‘n’puff steam injection; steam drive; and horizontal well drilling. The project resulted in the identification of more than 100 infill or recompletion candidates, and an estimated three million barrels of oil (MMBO)of additional recovery during the first 2 years of this project. As a result there were significant performance improvements and more are anticipated through the implementation of the field development strategies recommendedhere. The modeling approach led to significant time savings and provided an effective reservoir management tool for future field development. Introduction Schlumberger Data and Consulting Services (DCS), in Denver, Colorado, initiated a project for preparing the numerical 3D predictive model of theLL-04 Miocene reservoirs in Lake Maracaibo. The objectives of the reservoir performance evaluation were toprovide Petróleos de Venezuela, S.A. (PDVSA), the Venezuelan state-owned national oil company, with an updated geologic model that could be used to select new drilling and workover candidatesprovide PDVSA with a dynamic flow model that could be used as a tool to improve ultimate recovery from a number of operating strategies, and to monitor the field performancemake recommendations that would help PDVSA maximize production, maximize oil recovery, and to determine the best operating strategy for the field. This paper describes the reservoir simulation part of the reservoir characterization and simulation project. The Reservoir The LL-04 field is located on the northeast side of Lake Maracaibo along the Bolivar Coast of Venezuela (Fig. 1). This was one of the first fields discovered in Lake Maracaibo with production dating back to 1927. Production is from shallow (2000 to 3000 ft) unconsolidated sands in the Miocene La Rosa, Lower Laguna and Lower Lagunillas formations. Because production from the field is from highly unconsolidated sands, very limited core was available. Complicating the reservoir performance is the subsidence that has occurred. This has been accounted for by using very high rock compressibility in the simulation model.