1. Introduction
5.2 Possible future solvent developments
5.2.3 Relationship between solvent thermal stability and partial pressure of CO 2 . 125
5.2.3 Relationship between solvent thermal stability and partial pressure of CO2
Oyenekan and Rochelle (2006) points out the relationship between the temperature swing of the process and the enthalpy of absorption of the solvent. The rationales are explained in details in Oexmann and Kather (2008). Assuming that the mixture is ideal, the Van’t Hoff equation relates the change in temperature of the solvent to the change in equilibrium constant, expressed here as pressure, given the standard enthalpy change for the process. It can be written as
d ln PCO d1
T
∆Habs
R (33)
Where
Bar Partial pressure of carbon dioxide
R J/mol/K Universal gas constant: 8.3145
T K Temperature
∆ J/mol/K Enthalpy of absorption of carbon dioxide
Assuming that, to a first order approximation, the standard enthalpy change is relatively constant over the temperature swing and the change of solvent loading, it is possible to relate the ratio of partial pressure of CO2 in the absorber and in the desorber to the temperature swing of the process
PCO2des
Superscript des Desorber
Superscript abs absorber
Oyenekan and Rochelle (2006) indicates that, for a given temperature swing, say 80ºC, solvents with high enthalpy of absorption will deliver a higher partial pressure of CO2, and by extension a higher total desorber pressure. They refer to it as thermal compression of carbon dioxide.
The Van’t Hoff equation also shows that increased solvent thermal stability produces the same effect. The changes between partial pressure of CO2 and desorber temperature are highly non‐linear as indicated by equation (37), so that thermally stable solvents with a relatively low enthalpy of absorption can possibly benefit from thermal compression. This needs to be quantified rigorously with a model including the loss of output of the power cycle due to steam extraction, a the potential for integration between the capture unit and the power cycle accordingly to the solvent regeneration temperature, and a dedicated compression model.
5.2.4 Methodology for solvent assessment: An integrated approach
Typical examples of solvents needing to be assessed on a rigorous basis compared to 30%wt MEA are ionic liquids, piperazine and ammonia based solvents. Wappel et al. (2010) have proposed to regenerate the former at 110ºC with a partial pressure of CO2 at the top of the desorber for the optimised solvent loading reported, of the order of 0.3‐0.4 bar, compared to 1.1 bar for MEA. On the other hand, piperazine and ammonia solvents have a lower thermal energy of regeneration but are regenerated at a higher temperature. Ammonia‐based solvents can be regenerated between 100 and 200ºC (Gal, 2006) while piperazine‐based solvents are thermally stable up to 150ºC (Freeman et al., 2010).
This and the two previous sections illustrate the need for a rigorous methodology to assess process conditions specific to solvent properties. An integrated power plant, solvent, compression system was developed for that purpose. The steam cycle model for pulverised coal plants of Chapter 3 was modified to conduct a sensitivity analysis of sixteen solvents with a range of thermal energy from 3.5 to 2.6 GJ/tCO2 and a range of reboiler operating temperature from 90ºC to 180ºC. The enthalpy drop and the number of turbine stages of the IP and the LP turbine was adjusted to set the IP/LP crossover pressure to match the temperature required on the solvent side of the reboiler. For consistency the generator output without capture is identical for each case. Figure 5‐3 shows the steam turbine configuration adopted for solvents with a temperature equal or above 120ºC on the solvent side of the reboiler. For reboiler temperatures of 150ºC and 180ºC it was necessary to relocate the steam tapping point feeding the deaerator upstream, since the reboiler condensate with capture is hotter than the water outlet temperature of the last LP turbine feedwater heater when the steam cycle is operated without capture.
Solvents with a temperature of 90ºC required a different turbine arrangement. In practice the condensate heating arrangement would need to be modified for these solvents by replacing one of the LP turbine feed water heaters and move it upstream to the IP turbine. Instead, the extracted steam for solvent regeneration was expanded in an additional back‐pressure turbine, as shown in Figure 5‐4, so that steam was entering the reboiler at as low a pressure as possible. The addition of the back‐pressure turbine allowed consistency with the reference case without capture. After the expansion in the back‐pressure turbine the steam extracted did not contain enough superheat to justify a desuperheating feed water heater and this was replaced by a reboiler condensate spray.
In addition to the steam cycle model five adiabatic compressors, their respective intercoolers and the stripper reflux condensers were modelled to work out the temperature and the amount of heat available for each configuration, to replace the LP turbine feed water heating arrangement with capture. The stripping steam, carried away with the carbon dioxide at the top of the desorber, is gradually removed in the reflux condenser and in the compressor intercoolers. The compression arrangement is illustrated in Figure 5‐5.
Solvent volatility was neglected so that the gas mixture leaving the desorber is only composed of water and carbon dioxide. Although this de facto limits the analysis to low volatility solvents, behaving relatively closely to an ideal mixture, the methodology could be extended to other solvents with available vapour liquid equilibrium data. Modelling assumptions for thermodynamic integration and temperatures available for heat recovery are given respectively in Table 3‐3 and Table 3‐4. It should be noted that the composition of the mixture at the inlet of the first compressor is only
determined by the temperature of the cooling medium, i.e. either the power cycle condensate or water available in the main plant cooling system.
Variations of the loss of output of the steam cycle, expressed as electricity output penalty are shown as a function of solvent thermal energy and temperature of regeneration in Figure 5‐6, and presented as the difference in output, expressed in kWh/tCO2, with a reference solvent with similar characteristics to 30%wt MEA, i.e. 3.2GJ/tCO2 required at 120ºC. It can notably be seen that the power output of the power cycle, and hence the electricity output penalty (EOP), is a strong function of the reboiler operating temperature. For example, solvents with a thermal energy of regeneration of 3.5 GJ/tCO2, higher than the reference solvent, but requiring the extraction of steam at a lower pressure to deliver 90ºC on the solvent side of the reboiler, reduce the EOP of the power cycle by 15 kWh/tCO2. On the contrary solvents with a lower thermal energy of regeneration but operating with a higher reboiler temperature can increase the EOP of the power cycle, e.g. by 20 kWh/tCO2 for a 2.9GJ/tCO2 solvent regenerated at 180ºC.
To complete the analysis the pressure at the top of the desorber equally needs to be considered to calculate the power requirement of compression, and add them to the loss of output of the steam cycle to estimate the overall EOP of a specific solvent. Oexmann et al. (2008) shows that the minimum efficiency penalty possible for 30%wt MEA is achieved with a desorber total pressure of 2.1 bar at regeneration temperature of 120ºC, for the specific plant configuration they studied19. The reference solvent was assumed to be identically operated with its total pressure set t0 2.1 bar. It should be noted that the total pressure in the desorber is composed of the sum of the contribution of the partial pressure of carbon dioxide and water.
The energy requirements for a mixture of CO2 and water at 2.1 bar compressed up to 20 bar are shown in Figure 5‐7. This illustrates the potential trade‐offs between power for compression and loss of output in the steam cycle for solvent selection as the contribution of the electricity output penalty of the steam cycle can be compensated by a reduction of the compression energy requirement resulting from solvents with favourable vapour‐liquid equilibrium.
To facilitate solvent selection the desorber total pressure of each of the sixteen solvents considered in this sensitivity analysis was reverse‐engineered to calculate a break‐even pressure. This break‐
even pressure can be seen as a hypothetical total desorber pressure for which the overall electricity
19 This was optimised rigorously by considering compression work and the loss of output of the turbines, although their results cannot be extended for a different feed water heating system and beyond the limited temperature range they considered – 131ºC to 155ºC.
output penalty is equivalent to the reference solvent, assuming that the ancillary power for solvent circulation in the capture unit is independent of the type of solvent. For example, solvents with a lower contribution to the electricity output penalty in the power cycle have a break‐even pressure lower than the reference solvent, and vice versa. In fact, the metric for solvent comparison becomes the break‐even pressure, shown in Figure 5‐8. Each of the solvents needs to operate with a total desorber pressure above its break‐even pressure to outperform the reference solvent.
The methodology proposed allows a rapid comparison of solvents against 30% wt MEA as a function of their thermal stability, desorber total pressure and thermal energy of regeneration. It also shows that the emphasis on thermal energy of regeneration in the existing chemical engineering literature is misleading. The current research effort should assess potential solvents not on the sole basis of thermal energy of regeneration, but use a rigorous methodology taking into account the power cycle and the compression system, for which the reboiler temperature is a key issue.