This paper assesses two possible acid gas removal processes for CO2 removal onboard a floating LNG facility: (1) the well-established amine absorption process, and (2) a membrane/amine absorption hybrid process. The assessment considers process and economic aspects as well as sizing due to the on-board application.

Process simulation models of each of the systems were developed in the Aspen Hysys (V8.6) software package. Two different gas fields are assumed with Feed1 containing 10%/0% CO2/H2S and with Feed2 50%/1% CO2/H2S. The feed rate in each scenario was 590,000 Nm3/h and the sweet gas specification was 50 ppm CO2 and 4 ppm H2S. The amine absorption process modelled as the base case was a 50% MDEA solution. The hybrid membrane/amine process featured a polymeric membrane unit implemented as a sub-flowsheet and then the amine unit.

Our results suggest that for a very sour gas feed there may be advantages with a hybrid membrane/amine process that allows the plant weight to be reduced by 80%, volume by 50%, investment costs by 70% and annual operation costs by 40%. The most important disadvantage concerning the hybrid process is the high methane slip which can be reduced by further development of membrane properties and process design. The participation of the membrane unit increases generally with the percentage of acid gas in the feed. If the boundary conditions are comparable to those used in this paper, it can be stated that the CO2 concentration should be at least 10% for a proficient application of a hybrid process.

This study presents models to evaluate novel acid gas removal processes and describes suitable process metrics that could be considered for floating LNG production facilities.

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