Amine capture plant processes

As mentioned above, post-combustion CO2 capture using amines (typically MEA 30

wt%) is the most advanced process for removing CO2 from fossil fuel combustion

flue gases. This process, see Figure 2.7, cools the flue gases via a direct contact cooler to ~40°C, where they enter the bottom of the absorption column and the aqueous–MEA solvent enters into the top of the absorption column (IPPC, 2005). The absorption column comprises of structured or random packing, whereby, the lean solvent stream flows downwards over the packing material and mixes counter– currently with the flue gases. The packing material enhances mass transfer as there is a high surface area which maximises contact between the liquid and the gas.

Figure 2.7. Schematic of the amine CO2 capture process.

Once the aqueous–MEA solvent reaches the bottom of the absorption column, the stream is termed “rich” as it has absorbed CO2 from the gas phase. The treated flue

gases (with a low CO2 concentration) exit the top of the absorption column and

enters a wash column where entrained solvent droplets are removed. This is to ensure that the MEA is not discharged into the atmosphere because of the detrimental impact these emissions have on the environment. The CO2–rich solvent

stream is pumped to the lean/rich heat exchanger and is heated before being sent

STRIPPER ABSORBER CROSS HEX LEAN AMINE HEX CONDENSER RICH AMINE PUMP LEAN AMINE PUMP RICH AMINE (COLD) REBOILER RICH AMINE (HOT) LEAN AMINE (COLD) LEAN AMINE (HOT) REFLUX REFLUX PUMP CO2 STREAM CONDENSATE REFLUX DRUM STEAM WATER CO2 DEPLETED FLUE GAS FLUE GAS BOOSTER FAN FLUE GAS

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to the top of the stripper tower. The rich solvent flows downwards, contacting with the CO2/steam stream flowing vertically upwards from the reboiler. The reboiler

heats the MEA–solvent to approximately 115°C to 120°C, thus, producing a vapour stream acting as a CO2 stripper (Akram et al., 2015). The vapour stream leaves the

top of the stripper column, comprising predominantly of CO2, steam and small

amounts of MEA–solvent. The entrained steam and MEA–solvent droplets are removed by a condenser and refluxed to the stripper column. The residual highly- concentrated CO2 stream is further purified if necessary, compressed and

transported for storage. The hot lean MEA–solvent exits the stripper column where it is pumped via the lean/rich heat exchanger for heat recovery and subject to additional cooling to ~40°C prior to entering the absorber column.

The overall performance of CO2 capture plants which use MEA solvent is well

known, however, the key limitation of this process for gas fired systems is the specific reboiler duty, which requires ~4 MJ/kg CO2 captured (Li et al., 2011a). This

results in a reduction in the CCGT power plant efficiency by ~11 percentage points (DOE/NETL, 2015). The reason why such a reduction occurs is due to the much greater flue gas flowrates that comprise of low CO2 concentrations ~4 vol%.

Furthermore, because of the higher flue gas O2 concentrations in CCGT power

plants, this can affect the energy penalty due to issues associated with oxidative solvent degradation. Thermal degradation is more prominent at temperatures above 120°C or at elevated stripper pressures, when using MEA. However, depending on the process conditions, operating at higher temperature and pressures may be undesirable under S-EGR conditions.

This oxidative and thermal degradation have the potential to lead to greater economic and energy costs when coupling CCS to gas-fired systems (DOE/NETL, 2015). To overcome these issues, research is focused on optimising the post- combustion CO2 capture plant performance. There are a number of pilot and

demonstration plants and two full-scale plants globally which have investigated CO2

capture mainly from coal fired systems. Boundary Dam, which is located in Saskatchewan, Canada, has the capacity to capture 1 Mt CO2/year from a 139 MW

thermal coal fired power plant using the Shell Cansolv Process with a 90% capture efficiency (Stéphenne, 2014). More recently, Petra Nova in the USA became the largest operational CCS facility to capture 1.4 Mt CO2/year from a CO2 capture plant

(90% capture efficiency) using an amine KS-1 solvent produced by Mitsubishi Heavy Industries (NRG Energy, 2017). The CO2 flue gas treated in Petra Nova is

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of CO2 capture plants treats flue gases from coal fired power plants, although a

small number of facilities that exist which treat flue gases from gas fired systems. In Norway, the CO2 Technology Centre Mongstad has the capability to capture 20 kt

CO2 / year from the flue gas generated in a combined heat and power combustion

facility (Brigman et al., 2014; de Cazenove et al., 2016) burning natural gas. Furthermore, Sulzer in Switzerland has developed a pilot scale plant which treats a flue gas up to ~4 vol% CO2 (150 kg/h flue gas flowrate) from a gas fired burner

(Notz et al., 2012; Tait et al., 2016). The SINTEF facility, situated in Norway, captures CO2 (flue gas CO2 concentration up to ~9 vol%) from a 380 kW propane

combustor with a flue gas flowrate of up to 50 kg/h (SINTEF, 2018). In the UK, the PACT Research Centre incorporates an amine capture plant which has the capacity to capture up to 1 tonne of CO2 per day from flue gases produced from either

natural gas, coal or biomass combustion (PACT, 2018). The Turbec T100 mGT at PACT produces flue gas CO2 concentrations of ~1.7 vol% at full load conditions

when combusting natural gas. However, work by Best et al. (2016) has simulated EGR increasing the CO2 concentration to ~6.3 vol% by injecting CO2 into the micro

gas turbine. In addition, an onsite synthetic gas mixing skid allows a range of CO2

concentrations to be investigated by injection directly into the CO2 slip stream

(Akram et al., 2016). Despite the advancement of post combustion CO2 capture

plants, there are still requirements to optimise the process for gas-CCS. Notably, these include optimising plant performance under flexible operation, decreasing energy and financial costs, the advancement of novel solvents and making process improvements.