Located offshore East Kalimantan, Indonesia, the Serang Field consists of complex multi-layered reservoirs with strong aquifers and large gas caps. The dynamic change of fluid distribution and saturation in these reservoirs due to production poses a unique challenge for managing and developing the field. Issues important for reservoir management involve locating and defining fluid contacts, optimizing well placement and their timing, selecting proper completion techniques, and identifying potential workover candidates to capture additional recovery.

This paper presents a field case study describing the use of reservoir modeling to assist operations to manage and optimize the Serang field development. The model constructed helps explain the reservoir fluid flow behavior, its production characteristics, and is subsequently used to plan forthe field development strategy. Based on modeling results, value-basedrecommendations are made with focus on selecting optimal in fill locations, completion techniques, wellbore placement and timing, identifying work over candidates and recompletion potential, and forecasting flow rates and reserves. Results from current development drilling program with emphasis on using horizontal wells for improving recovery under gas-cap gas and strong aquifer support are presented. Specific strategy used in planning and completing these horizontal wells is also discussed.

The paper demonstrates that reservoir modeling as an integral part of the asset team, plays an important role for technical decision, bridges communication between cross- disciplined team members and becomes a useful forecast tool to help manage the asset and increase its value.


This paper presents a case study that demonstrates the use of reservoirmodeling to assist operations in reservoir development. The field data discussed in the paper are from the Serang Field, located offshore East Kalimantan, Indonesia (Figure 1). Hydrocarbon is produced from reservoirs consisting of complex stacked channel sands and under the influence of a largegas cap and strong aquifer support. As a result of production from continuous drillings and work overs, fluid distribution in the reservoirs has be comeextremely dynamic which challenges the field management for both short and longterms. Specific issues important for optimizing the field development are locating current fluid contacts for optimal placement and timing for new wells, selecting proper completion techniques, identifying potential work over candidates, and examining the effect of surface facility upgrades on recovery.

To address these issues, reservoir models are used as a monitor and planner tool in the field life. As the field grows mature, its use is even morecritical as the originally thick oil column becomes thinner and water influx/production grows significant. In addition, avoiding pre-mature gas cap blow down at this stage is even more challenging as production is inclined togas with thinner oil bands. Under this condition, results from the models suggest the use of horizontal wells to alleviate coning. Performance data from 17 horizontal wells drilled in the last three years show that they are a better option to develop the field at this later stage with thin oil columns. Theiradvantages are summarized as follows

  • enlarging contacts and drainage areas,

  • allowing less drawdown hence delayed coning,

  • delivering faster recovery, and

  • resulting in better sweep and recovery efficiencies.

Although beneficial, their application can be more costly for requiring more accurate geological interpretation, detailed well plan, and sophisticated equipment while drilling. In turn, the models again prove to be useful to help make decisions on well locations, timing, and completion strategy for asset management. Practical experiences and lessons learned from planning anddrilling these horizontal wells are also discussed.

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