| dc.description.abstract | Reservoir management is a significant aspect in petroleum that aims at optimizing the hydrocarbons recovery. It involves establishing the development and depletion strategies, numerical models for production and reserves forecasts. Reservoir simulation is one of the most powerful predictive tool used in reservoir management.
The simulation results serve as the basis for investment decisions at initial development stages of the field and in monitoring day-to- day operation activities. Due to inadequate subsurface information to describe the reservoir, leads to uncertainties in the simulation models. As more data becomes available, refining the simulation models is necessary for reliable predictions and the appropriate changes have to be implemented in the reservoir management plan.
Objective of the study was to update the reservoir simulation model of Mnazi Bay Gas field using available data. The model was constructed in 2010 by incorporating geological static data, well test and actual production data from one well that started in 2007. In updating the model, a traditional approach (manual history matching) was used in this study.
Through material balance analysis, a moderate natural water drive in upper Mnazi Bay region and a potential for existence of compartments within the reservoir were depicted. These features were respectively incorporated in the model during history matching by introducing the aquifer and transmissibility across the geological layers.
Permeability, transmissibility, aquifer thickness, and radius were adjusted to match the wellhead pressures of the current producers namely MB-1, MB-2, MB-3, and MB-4 wells. The best matched model was selected based on visual analysis and percentage deviation. A descent match of less than 10% deviation was obtained in all wells. About 95% match was obtained in the MB-1 well, 97 % in MB-2 and 93 % in MB-3 and MB-4 wells. For model comparison, the predictions were run using both updated and base case model from November 2017 to the end of contract period in August 2031.
With the updated model, 19.57 Bsm3 of gas would be produced to the end of contract period using five wells as compared to nine wells that gave 15.71 Bsm3 in the base case
model. One additional well would be required to maintain a plateau rate for 13.25 years using an updated case model, compared to base case model which gave a plateau length of 9 years by the end of 2026 using five additional wells.
The results reveal that the production strategy may change as more data becomes available. The more the data, the better the model, and better predictions. Therefore, it is recommended to update the models regularly to improve the field development strategy and overall reservoir management. | en |
