Perpustakaan Digital ITB

ABSTRACT SIMULATION OF INITIAL START-UP PROCEDURE FOR SUBSEA WELL AT HPHT GAS RESERVOIR USING MONO ETHYLENE GLYCOL By ENDRO CAHYONO NIM: 23016030 (Master’s Program in Chemical Engineering) The development of oil and gas in the future, especially in Indonesia is deepwater oil and gas exploration with water depth above 200 m. The ABC gas condensate field has water depth -610 m with a characteristic of high pressure and high temperature (HPHT) reservoir will be developed using subsea equipment to produce natural gas which is further processed into LNG on floating LNG production. The maximum capacity of each production well is limited by x-mass tree maximum flow rate of 200 MMscfd. The initial start-up process has several operating challenges such as the possibility of hydrate due to seawater temperature at -610 m depth of 6.9oC, slugging condition in the flowline-riser, possibility of corrosion and erosion in the flowline-riser, and optimization of initial start-up time. This research has been performed to simulate the transient condition of an initial start-up in the preparation of ABC gas field operation procedure. The evaluation was conducted using OLGA ver 2015 software and validation model using a comparison of pressure data from XYZ field which has operated with simulation calculation result in steady state condition. The flowline media used in the initial start-up is vaporized LNG at a topside pressure of 75 bara as a base case and hydrate inhibitor (MEG) at a topside pressure of 15 bara as case A as well as the sensitivity analysis of the topside pressure of 75 bara as case B. From the simulation results can be confirmed that the initial start-up time of the base case is 14 hours, the maximum flowline pressure is 164 bara, the minimum temperature of -15,2oC and an estimated cost of US$12M. The initial start-up time of the case A is 36 hours, the maximum flowline pressure is 222 bara, the minimum temperature of -24,1oC and an estimated cost of US$7M. The initial start-up time of the case B is 16 hours, the maximum flowline pressure is 307 bara, the minimum temperature of -25,6oC and an estimated cost of US$7M. The potential for hydrate formation can be overcome by insulation of the flowline and MEG injection. Surge arising from slugging condition at the initial start-up of the gas flow rate of 0 MMscfd to the maximum gas flow rate of 200 MMscfd can be minimized with the correct combination of subsea and topside choke. Keywords: deepwater, subsea equipment, OLGA, slugging, hydrate inhibitor