An Integrated Production Optimization Approach of a Natural Gas Filed in Bangladesh

摘要

This paper presents an integrated production model for a producing gas field in Bangladesh. Integrated production modeling is a powerful method for optimizing gas or oil field production planning. This approach combines the reservoir performance, well inflow and outflow relationship and the surface facilities in a single platform to cover all operating envelopes and constrains. Once the model is established and validated, the production forecasts can be generated to study alternative development scenarios against reservoir performances. This allows choosing an optimum production strategy from different options. The method is computationally intensive, therefore commercial software packages are used to conduct this study. PROSPER TM , MBAL TM and GAP TM modules from the IPM software suite were used to carry out this work. The current production strategies predict recovery factor of 49.38 % and 40.46% from Upper Gas Sand (UGS) and Lower Gas Sand (LGS) respectively, for next 25 years. An attempt to increase production from this field was considered in this study, since the field is producing only 50 MMCFD while the installed process plant capacity of 220 MMCFD. Several production strategies have been investigated that includes change in the tubing size of existing well, setting up new wells and addition of compressor facilities. Plateau production and ultimate recovery for next 25 years were compared for these scenarios. Initially change in the tubing sizes has been studied for well # 1 in UGS and well # 3, 4 in LGS gives 16% and 3% increase in ultimate recovery from current tubing condition respectively. The effect of adding two infill wells in UGS and two in LGS has also been studied. With additional wells, the ultimate recovery factor increases to 68.5% and 57 % for UGS and LGS respectively. Using compressor and infill wells shows the recovery of 92% for UGS and 71% for LGS respectively. Journal of Chemical Engineering, Vol. 29, No. 1, 2017: 34-39