Heat recovery solves carbon capture issues
Flue gas heat recovery at the fired heater overcomes major drawbacks to the successful operation of an amine based carbon capture plant.
BART VAN DEN BERG, HeatMatrix Group
EARL GOETHEER, TNO
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The refining sector is facing a major transformation in the next three decades. Driven by more stringent regulation towards CO2 abatement and increasing pressure from consumers and investors, refiners are exploring options to significantly reduce CO2 emissions. A broad range of technologies are available to reach a zero emission goal by 2050. Each technology, whether it is heat recovery, electrification, alternative feedstocks, or carbon capture and storage (CCS), is at a different stage of maturity and applicability. Of these four technologies, heat recovery and carbon capture are the most mature and ready for implementation. This article covers the apparent advantages of these two technologies when they are applied simultaneously.
Carbon capture and storage
Post combustion carbon capture technology goes back as far as the 1930s and basically consists of a two-step process. In the first step CO2 is absorbed into a solvent and in the second step it is thermally released from the solvent, resulting in a concentrated CO2 stream. The concentrated stream can be further processed for transportation or underground storage. Typically, an aqueous amine solution is used for the reactive absorption of CO2. The original amine based process has been further developed in order to optimise three major drawbacks. The first is the high energy consumption of the solvent regeneration step. According to the Global CCS Institute, the energy cost of a CO2 capture unit downstream of a refinery fired heater could be as high as 20-30% of the fired heater duty. The second drawback is degradation of the amine solution, and the third drawback is entrained amine emissions. The main challenge of amine emissions is that amine aerosols are difficult to remove from the depleted flue gas stream with standard techniques.
When flue gas contains a high concentration of acidic contaminants (NOx and SOx), pretreatment steps prior to CO2 capture are required to reduce their concentration. Otherwise, these acidic components lead to loss of amine activity due to the formation of heat stable salts. A stable salt bleed and fresh amine make-up will be necessary to compensate for the loss of amine efficiency. A standard selective catalytic reduction (SCR) and wet flue gas desulphurisation column are the appropriate technologies to achieve this.
Another required pretreatment step is the reduction of flue gas temperature to 30-50°C, which is the optimal operating temperature for most carbon capture technologies. Especially in refineries, the flue gas temperature can be as high as 350°C depending on the degree of heat integration between flue gas and combustion air. Typically, the flue gas is cooled using a water quench prior to a CO2 absorber, either in a separated quench step or integrated in the wet flue gas desulphurisation column (DESOX). A quench step is a quick and low cost option for reducing flue gas temperatures but has several disadvantages which are explained in the following.
Figure 1 shows a typical lay-out for a post-combustion CO2 capture system for a typical combustion process. The SCR, ESP, APH and DESOX steps are optional and can switch order depending on local circumstances.
Amine aerosol formation
Since the last decade, it has been established that amine emissions from the CO2 absorber could significantly exceed regulatory limits. The root cause was tracked down to the formation of sulphuric acid aerosols and subsequent amine entrainment. These aerosols are created when acidic flue gas is fed to the CO2 absorption column. Very small sulphuric acid aerosols (d <0.02 μm) are too small to be absorbed or knocked out and remain in the gas phase throughout the absorption column. However, amine vapour present in the absorption column can condense on these aerosols, leading to excessive growth of particles. As a result, small particles grow to micron-size particles which are difficult to remove using a standard washing section or demister. Relatively expensive techniques, such as a wet electrostatic precipitator or a Brownian demister, are required to capture these aerosol particles.
The Dutch research institute TNO has a long track record of improving amine based CCS technology. TNO, as part of a large European consortium, will demonstrate CO2 capture at a refinery in Ireland. This facility will incorporate the latest developments for amine based CO2 capture technology in a refinery setting. One of the attention points, next to demonstrating low energy consuming amine solvent systems, will be to further study amine based aerosol formation and countermeasures.
Research case power plant
One of the important steps which TNO took was to identify the root cause of aerosol entrained amine emission. Together with the energy production sector, the relationship between flue gas composition and amine emission have been identified and quantified. To study this in depth, a 600 MWe coal fired power plant in the Netherlands was selected for an extensive flue gas sampling trial. The power plant has two parallel flue gas treatment sections downstream of the boiler, one with heat integration around the wet flue gas desulphurisation column and one without heat integration (see Figure 2). The heat integration step consists of a rotating heat exchanger which cools flue gas upstream of the wet flue gas desulphurisation column while reheating the saturated flue gas stream downstream of this column. In this way, flue gas exiting the stack remains above water dew point conditions.
This unique situation allowed for comparing the effect of a sharp temperature reduction in the wet flue gas desulphurisation step (quench) to a slower temperature reduction in the rotating exchanger. Without a rotating heat exchanger, the temperature of the flue gas is instantly reduced from 122°C to 52°C in the desulphurisation column by quenching. In the rotating exchanger, the flue gas temperature is reduced from 122°C to 80°C followed by a moderate quench in the desulphurisation column to 52°C.
TNO researchers measured the flue gas sulphur content around the rotating exchanger and the desulphurisation column. They also measured the particle size distribution (PSD) of the samples with an electrical low pressure impactor (ELPI). Finally, flue gas from sample points was taken to a small amine absorption column in order to visualise the amine based aerosol growth. The results give a clear picture of the sulphuric acid aerosol formation mechanism.
First flue gas train with quench
With a quench as cooling step, the sulphuric acid concentration upstream and downstream of the column remained the same (SP1: 5.2, SP2: 5.8 mgNm3). Apparently, no sulphuric acid is absorbed in the desulphurisation column. However, downstream of the desulphurisation column a high number of small particles were measured (SP2: 6E7 cm3), which is 100 times higher compared to the sample upstream the desulphurisation column (SP1: 6E5 cm3). The formation of aerosols inside this column can explain why there is no absorption of sulphuric acid since aerosols pass through the column in the gas phase, unaffected by the absorption solution.
The high particle concentration downstream of the desulphurisation column also leads to clear mist formation in the small amine absorber installed downstream of the desulphurisation column due to further growth by amine deposition. This effect has significant consequences for the design of a potential CO2 capture facility because, without additional measures, amine emission permit levels will be exceeded.
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