Performance Analysis and Comparison of Membrane Permeation Versus Supersonic Separators for CO2 Removal From a Plausible Natural Gas of Libra Field, Brazil

Abstract

Libra Field is a giant oil and gas offshore field situated in Santos Basin, at 200 km from southeastern Brazil coast, 2200 m water depth and 5 km crust depth. The product of Libra is a 27°API oil with a remarkable characteristic: an impressive gas/oil ratio of approximately 600 sm/m with a CO2 content over 40%mol. The extraction of this oil obligates the processing of such CO2 rich gas, which must end with the reinjection of all CO2 into the field for environmental reasons and to sustain oil production. The removal of CO2 and adequate destination of specified gas with minimum footprint – due to space and weight constraints in offshore platforms – and energy consumption configure a central challenge in the Libra scenario. A strategy involves the separation of CO2 from natural gas at the platform and the transportation of the processed gas to shore via pipelines. Four alternatives of topside gas conditioning are assessed in terms of final gas quality and energy demand, using a professional process simulator. The conventional alternative (A) selects a Membrane Permeation (MP) train including TEG Dehydration and JT Expansion for respectively adjusting water dew-point and hydrocarbon dew-point. Case B is devised by using only a Supersonic Separator (3S) to treat the gas. The third alternative (C) uses 3S for dew points adjustment and MP for CO2 removal. Case D also involves TEG absorption and JT Expansion, however, CO2 removal is accomplished by a 3S. The results show that Case B could not completely specify the gas stream, practically not changing the CO2 content. Case C is considered an improvement of Case A, since it employed much less equipment and still presented a better quality natural gas, with 68% more liquid extraction and 18% less energy consumption. Both cases reduced CO2 content to nearly 20%mol. Case D confirms the potential application of 3S for CO2 removal from a dry gas at extremely low temperatures. The final gas CO2 content was slightly higher (24%mol) and the energy demand increased 23% regarding case A, due to the high pressure required. However, the CO2 rich stream in this case is at higher pressure, which means less compression power required for reinjection application.