| dc.description.abstract | The main objective of the present study was to determine the field development plan for Mnazi Bay gas field, which is located in the southeast of Tanzania. The study was carried out with the premise (as specified by Petroleum Development Corporation, TPDC)) that the field should deliver a gas rate of 80 MMscf/day for the first year and then increase to 130 MMscf /day for 16 years. Four field development strategies were analysed and several sensitivity studies were made on the best strategy case. The analysis was performed using commercial software from the company Petroleum Experts.The surface production network was modelled in the program GAP and two other programs from Petroleum Experts (MBAL and PROSPER) were linked from within its interface. MBAL was employed to model the reservoir behaviour with time using the material balance formulation, and the well inflow deliverability and tubing system were represented in PROSPER. The simulations were performed by setting the field gas target flow rates schedule in GAP and specifying the total simulation time and the number of time steps.A mathematical optimization was carried out by GAP in each time step to compute the value of adjustable elements in the network (wellhead choke opening or compressor pressure drop) that ensured the production of the specified gas flow rate. When the optimization had no feasible solution, the field gas rate was reduced. The maximum well gas flow rate estimated for a single layer was 13.6 MMscf/day and 32.9 MMscf/day was approximated for 7 producing layers of the modelled cases.Based on the simulation studies, the best field development plan that fulfils the gas field rate scheduled consists drilling 12 wells and implementing plateau prolonging measures. Drilling 12 wells provided a plateau period of 11.5 years and the plateau prolonging measures provided the remaining plateau period of 5.5 years. The plateau prolonging measures considered were to perforate more layers in wells, increase perforation spacing intervals, increase tubing diameter and install a surface compressor. Gas recovery factor increased from 70.1 % to 90.2 % when plateau prolonging measures were used. Cumulative NPV for this case was estimated to be 55 MM USD for gas price of 3.2 USD/MM Btu at discount rate of 20 %.The sensitivity analysis studies show that, the best field development plan is sensitive to separator pressure, the type of well completion, the size of production tubing, the perforation spacing interval, gas price and discount rates. Changes in flow line diameter size and formation damage shows negligible impact on the predicted plateau length.Lastly, it is recommended to conduct well deliverability tests on those layers that have not been tested to determine their storage capacity and their reservoir properties. It is also recommended that the future wells have a production tubing diameter of 3.5 inches and to increase the perforation intervals in the gas production area so as to maximize reservoir exposure | nb_NO |
