This paper compares the techno-economic performances of three technologies for CO2 capture from a lignite-based IGCC power plant located in the Czech Republic: (1) Physical absorption with a Rectisol-based process; (2) Polymeric CO2-selective membrane-based capture; (3) Low-temperature capture. The evaluations show that the IGCC plant with CO2 capture leads to costs of electricity between 91 and 120 €·MWh−1, depending on the capture technology employed, compared to 65 €·MWh−1 for the power plant without capture. This results in CO2 avoidance costs ranging from 42 to 84 €·tCO2,avoided−1 , mainly linked to the losses in net power output. From both energy and cost points of view, the low-temperature and Rectisol based CO2 capture processes are the most efficient capture technologies. Furthermore, partial CO2 capture appears as a good mean to ensure early implementation due to the limited increase in CO2 avoidance cost when considering partial capture. To go beyond the two specific CO2-selective membranes considered, a cost/membrane property map for CO2-selective membranes was developed. This map emphasise the need to develop high performance membrane to compete with solvent technology. Finally, the cost of the whole CCS chain was estimated at 54 €·tCO2,avoided−1 once pipeline transport and storage are taken into consideration.
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Simon Roussanaly, Monika Vitvarova, Rahul Anantharaman, David Berstad, Brede Hagen, Jana Jakobsen, Vaclav Novotny, Geir Skaugen. Techno-economic comparison of three technologies for pre-combustion CO2 capture from a lignite-fired IGCC. Front. Chem. Sci. Eng., 2020, 14(3): 436-452.
Process contingency /%DC without contingencies [46]
TRL-level [4]
Owner’s costs and project contingencies /%EPC cost [47]
IGCC plant (except gasifier)
Included in EBTF estimates
?
19
IGCC plant gasifier
Including in EBTF estimates+ 10%
?
24
Rectisol CO2 capture and CO2 conditioning
10
8
24
Membrane CO2 capture
20
7
30
Low-temperature CO2 capture
30
6
36
Tab.6
Utilities and consumables
Cost
Lignite /(€?GJ–1) [53]
2
Process water /(€?m–3)
3.15
Cooling water /(€?m–3)
0.15
Ash disposal /(€?t–1)
Not included
Sulphur credit /(€?t–1)
0
Tab.7
Fig.7
Parameters
No CO2 capture
Rectisol capture
Low-temperature capture
Capture process based on membrane A
Capture process based on membrane B
Lignite thermal power input /MWth
638.5
638.5
638.5
638.5
638.5
Gas turbine net power /MWe
181.8
168.8
167.2
156.9
163.4
Steam turbine gross power /MWe
134.8
101.9
102.7
95.0
96.6
Gross power output /MWe
316.7
270.7
269.9
255.1
260.0
Fuel treatment /MWe
1.8
1.8
1.8
1.8
1.8
ASU unit /MWe
16.6
16.6
16.6
16.6
16.6
O2/N2 compressors /MWe
12.8
12.8
12.8
12.8
12.8
Gasifier unit including quench (fans+compressors) /MWe
3.7
3.7
3.7
3.7
3.7
AGR unit /MWe
2.6
2.6
2.6
2.6
2.6
CO2 capture unit /MWe
?
1.2
13.9
30.7
8
CO2 conditioning unit /MWe
?
13.9
?
14.8
14.8
Steam cycle auxiliaries /MWe
3.5
3.3
3.3
3.3
3.3
Net power output /MWe
275.7
214.8
215.2
168.7
196.3
CO2 capture ratio /%
?
89.0
84.1
86.9
86.9
CCR /%
?
86.6
81.8
84.6
84.6
Specific CO2 capture and conditioning work /(MJe?kgeq captured–1)
?
0.30
0.29
0.92
0.46
Specific CO2 emissions /(?kWh–1)
764
103
139
117
118
Tab.8
Fig.8
Fig.9
Fig.10
KPIs
CO2 capture ratio /%
50
60
75
85
LCOE /(€?MWh–1)
Rectisol
?
91
96
97
Low-temperature
83
?
?
91
Capture process based on membrane A
95
98
108
120
Capture process based on membrane B
88
87
92
99
CAC /(€?–1)
Rectisol
?
56
51
47
Low-temperature
48
?
?
42
Capture process based on membrane A
78
71
75
84
Capture process based on membrane B
59
49
47
53
Tab.9
Fig.11
Fig.12
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