This paper performs a techno-economic analysis of natural gas-fired combined cycle (NGCC) power plants integrated with CO2 selective membranes for post-combustion CO2 capture. The configuration assessed is based on a two-membrane system: a CO2 capture membrane that separates the CO2 for final sequestration and a CO2 recycle membrane that selectively recycles CO2 to the gas turbine compressor inlet in order to increase the CO2 concentration in the gas turbine flue gas. Three different membrane technologies with different permeability and selectivity have been investigated. The mass and energy balances are calculated by integrating a power plant model, a membrane model and a CO2 purification unit model. An economic model is then used to estimate the cost of electricity and of CO2 avoided. A sensitivity analysis on the main process parameters and economic assumptions is also performed. It was found that a combination of a high permeability membrane with moderate selectivity as a recycle membrane and a very high selectivity membrane with high permeability used for the capture membrane resulted in the lowest CO2 avoided cost of 75 US$/tCO2. This plant features a feed pressure of 1.5 bar and a permeate pressure of 0.2 bar for the capture membrane. This result suggests that membrane systems can be competitive for CO2 capture from NGCC power plants when compared with MEA absorption. However, to achieve significant advantages with respect to benchmark MEA capture, better membrane permeability and lower costs are needed with respect to the state of the art technology. In addition, due to the selective recycle, the gas turbine operates with a working fluid highly enriched with CO2. This requires redesigning gas turbine components, which may represent a major challenge for commercial deployment.

Gasification section Coal handling a,b Ash handling a,b Gasifier a,b Air separation unit (ASU) a,b Power section Gas turbine, generator and auxiliaries a,b,c HRSG, ducting and stack a,b,c Steam turbine, generator and auxiliaries a,b,c Cooling water system and BOP a,b,c Nitrogen compressor for GT dilution b Gas conditioning and CO2 separation section Low temperature heat recovery (LTHR) a,b Selexol acid gas removal (AGR) a,b Rectisol Acid gas removal (AGR) a,b Water treatment b Claus b Water gas shift reactors b Selexol CO2 separation system a,b CO2 compressor and condenser a,b Compressor power, MW 9.9 13.0 0.67 1 a DOE/NETL-2011/1498 (n.d.). b Franco et al.

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This study focuses on the application of Pd-based membranes for CO 2 capture in coal fuelled power plants. In particular, membranes are applied to Integrated Gasification Combined Cycle with two innovative feeding systems. In the first feeding system investigated, CO 2 is used both as fuel carrier and back-flushing gas for the candle filters, while in the second case N 2 is the fuel carrier, and CO 2 the back-flushing gas. The latter is investigated because current dry feed technology vents about half of the fuel carrier, which is detrimental for the CO 2 avoidance in the CO 2 case. The hydrogen separation is performed in membrane modules arranged in series; consistently with the IGCC plant layout, most of the hydrogen is separated at the pressure required to fuel the gas turbine. Furthermore, about 10% of the overall hydrogen permeated is separated at ambient pressure and used to post-fire the heat recovery steam generator. This layout significantly reduces membrane surface area while keeping low efficiency penalties.The resulting net electric efficiency is higher for both feeding systems, about 39%, compared to 36% of the reference Selexol-based capture plant. The CO 2 avoidance depends on the type of feeding system adopted, and its amount of vented gas; it ranges from 60% to 98%. From the economic point of view, membrane costs are significant and shares about 20% of the overall plant cost. This leads in the more optimistic case to a CO 2 avoidance cost of 35 €/t CO2 , which is slightly lower than the reference case.

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