Pre-combustion with Physical Absorption E.R. van Selow R.W. van den Brink Presented at the 2 nd ICEPE, 18 November 2011, Frankfurt, Germany ECN-L--11-126 November 2011
Pre-combustion with Physical Absorption Ed van Selow, Ruud van den Brink 2 nd ICEPE, 2011 www.ecn.nl
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IGCC with carbon removal Gas treatment Oxygen Pulverised Coal H 2 Gas treatment Sulphur absorption steam Clean gas shift CO 2 absorption Gasifier 3
Exergy losses in gas treatment (IGCC with CCS) Kunze et al (2010) 4 th Int Freiberg Conf, Dresden 4
IGCC with carbon removal Oxygen Pulverised Coal Gasifier Gas treatment Sour vs sweet WGS Existing sour gas treating technologies Chemical, physical, hybrid absorbents Physical sorbents and processes Developments Advanced solvents Advanced shift Low steam sour shift Sour PSA Gas treatment steam High-temperature gas Clean clean-up gas shift CO Sulphur absorption 2 absorption Reaction/separation integration: SEWGS Pilot at Buggenum IGCC H 2 5
6 Sour vs sweet WGS
Sour vs sweet (clean) WGS arrangement Sour Shift Retains steam Hydrolysis COS Operates in a wider temperature range Sweet Shift More selective sulphur removal Smaller reactor Cheaper catalyst 7
8 Existing sour gas treating processes
Gas treatment requirements (example) syngas Selective sulphur removal De-S syngas CO 2 +H 2 S H 2 S+COS < 30 ppm H 2 S > 20% syngas Sulphur + carbon removal H 2 CO 2 +H 2 S H 2 S+COS < 30 ppm, CO+CO 2 < 3% syngas Selective sulphur + carbon removal H 2 CO 2 CO 2 +H 2 S H 2 S+COS < 30 ppm, CO+CO 2 < 3% H 2 S < 200 ppm H 2 S > 20% 9
Selecting the absorbent Chemical solvents (amines) Mixed (hybrid) solvents Physical solvents More efficient at low pressure Sulphur removal 98% Higher energy penalty due to steam stripping May form heat-stable salts Low coabsorption Very high sulphur recoveries can be achieved. More efficient at high pressure Sulphur removal 99% High selectivity for H 2 S Higher investment costs Stable solvent Remove additional impurities such as HCN, NH 3 Co-adsorption of H 2 10
Selecting the absorption process Ullmann s Encyclopedia Trade-off at p CO2 ~ 6 bar between solvent loading/recirculation (lean vs. rich) and equipment sizing Selection of suitable CO 2 absorption process: a) Physical solvent + amine b) Physical solvent, physical solvent + amine or activated hot K 2 CO 3 c) Physical solvent d) Physical solvent or activated hot K 2 CO 3 e) Activated hot K 2 CO 3 or concentrated amine f) Activated hot K 2 CO 3 or amine g) Amine 11
Monoethanolamine MEA O O O Diethanolamine DEA O Diisopropanolamine ADIP O Methyldiethanolamine MDEA O O O Potassium carbonate Hotpot O O O Methanol+MDEA/DEA Amisol O XXX+MDEA Flexsorb O Sulfolane+MDEA/DIPA Sulfinol O DME of PE glycol Selexol O Methanol Rectisol O O N-Methylpyrrolidone Purisol O PE glycol + dialkyl ether Sepasolv O 330 MW e NGCC Power Plant. Based on January 2006 prices. Propylene carbonate Fluor solvent O Tetrahydrothiophenedioxide Sulfolane O Tributyl phosphate Estasolvan O C h e m i c a l M i x e d P h y s i c a l 12
Monoethanolamine MEA O O O Diethanolamine DEA O Diisopropanolamine ADIP O Methyldiethanolamine MDEA O O O Potassium carbonate Hotpot O O O Methanol+MDEA/DEA Amisol O XXX+MDEA Flexsorb O Sulfolane+MDEA/DIPA Sulfinol O DME of PE glycol Selexol O Methanol Rectisol O O N-Methylpyrrolidone Purisol O PE glycol + dialkyl ether Sepasolv O 330 MW e NGCC Power Plant. Based on January 2006 prices. Propylene carbonate Fluor solvent O Tetrahydrothiophenedioxide Sulfolane O Tributyl phosphate Estasolvan O C h e m i c a l M i x e d P h y s i c a l 13
Gas solubility data at 1 atm, 25 C (-30 C methanol), vol gas/vol liq Gas Selexol Fluor solvent Purisol Methanol H 2 0.047 0.027 0.02 - CO 0.10 0.072 0.075 - C 1 0.24 0.13 0.26 - C 2 1.52 0.58 1.36 - CO 2 3.63 3.41 3.57 15 C 3 3.7 1.74 3.82 - COS 8.46 6.41 9.73 - NH 3 17.7 - - - H 2 S 32.4 11.2 36.4 92 nc 6 39.9 46.0 - - H 2 O 2661 13640 14280 - HCN 4356 - - - Bucklin and Schendel (1985) Hochgesand (1970) 14
Comparing Selexol and Rectisol processes Selexol Rectisol H 2 S selectivity 9 6 H 2 S+COS removal < 0.1 ppm H 2 S + COS Few ppm CO 2 Temperature -5.. 175 C -60.. -15 C OPEX, CAPEX Higher OPEX and CAPEX: complex scheme and need to refrigerate Other COS hydrolysis needed High vapor losses 15
Absorber/desorber column design Absorption Stripping 16
Regeneration of solvents Flashing Stripping Reboiling 17
18 Source: UOP
Selecting the absorption process in IGCC Sulphur removal (not stringent) w/o CO 2 removal Chemical solvent Physical solvent Low Capex Low steam requirements Sulphur + CO 2 removal 2-stage Selexol Other Quoted as preferred Depending on requirements 19
IGCC/CCS studies NETL/Parsons 2002. Evaluation of Fossil Fuel Power Plants with CO 2 Recovery. 2007. Cost and Performance Baseline for Fossil Energy Plants. DOE/NETL- 2007/1281. Foster Wheeler 2003. Potential for improvement in gasification combined cycle power generation with CO 2 capture. IEA report No. PH4/19, 2003. 2007. Co-production of hydrogen and electricity by coal gasification with CO 2 capture. IEA Greenhouse Gas Program report 2007-13. Politecnico di Milano / Alstom UK 2011. European best practice guidelines for assessment of CO 2 capture technologies. 20
21 New Developments
Improvements in CO 2 solvent process Shell/Procede TNO New combinations of amines Membrane-assisted desorption TU Delft Ionic liquids 22
Advanced Shift (Sweet/Sour) Carbo et al (2009) Int J Greenhouse Gas Ctrl 3 (6) 712 23
24 Low-Steam Sour Shift
Sour H 2 PSA US2010.011955 25
Drivers for high-temperature gas clean-up The higher process efficiency without syngas cooling and removal of water from the syngas: +5.2%-points *. The elimination of sour water treating. The elimination of the black mud produced in wet scrubbing of particulates from the syngas. The potential related Capex and Opex savings. The viability of air-blown gasifiers. * Exergetic efficiency. Kunze et al. Energy 36 (2011) 1480 26
CO + H 2 O CO 2 + H 2 Syngas WGS 2%-6% CO H 2 & CO 2 WGS Separation H 2 CO 2 27
CO + H 2 O CO 2 + H 2 Syngas WGS 2%-6% CO H 2 SEWGS 400 C 25 bar CO 2 28
CO + H 2 O H 2 CO 2 CO CO 2 2 CO 2 CO CO 2 2 sorbent catalyst sorbent CO 2 Meis et al. (2008) K-promoted Hydrotalcite (layered clay) Fe-Cr Mg 6 Al 2 (OH) 16 CO 3.4H 2 O 29
cumulative amount of CO2 desorbed (mmol/g) Relative intensity Formation of MgCO 3 Relative mass loss (%) 50 40 30 20 x x x x x x x x x x x x x x x x x x x x x 4) Feed CO 2 +steam (10 bar) 3) Pressurisation (dry CO 2 ) 2)Regeneration Low pressure N 2 1) End of feed step 10 2 θ (degrees) 12 0 0 200 400 600 10 Temperature ( C) 8 reference sorbent 6 4 2 new sorbent 0 0 50 100 150 200 250 300 cumulative amount of steam fed (mmol/g) 30
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SEWGS multi-column unit at ECN FIC PCV FI FIC H 2 product Steam FIC purge H 2 FIC rinse FIC CO 2 repressurization FIC N 2 FIC CH 4 FIC CO feed PCV depressurization FI purge CO 2 product 32
33 SEWGS process development unit at ECN
CO2 in top product (% dry) Alkasorb sorbent is stable 1 Van Selow et al (2010) GHGT-10, Amsterdam 0.75 0.5 0.25 0 250 300 350 400 450 500 cycle no. 34
Effect of feed pressure Wright et al (2010) GHGT-10, Amsterdam 35
MS response [a.u.] 0.0E+00 1.0E-12 Co-capture of H 2 S H 2 S does not change CO 2 sorption capacity or kinetics 8.0E-09 11% CO 2, 17% H 2 O, N2, (500 ppm H 2 S) 17% H 2 O, 83% Ar 1.0E-11 7.0E-09 N 2 9.0E-12 6.0E-09 8.0E-12 5.0E-09 4.0E-09 3.0E-09 H 2 S H 2 O K-AL 7.0E-12 6.0E-12 5.0E-12 4.0E-12 400 C 1.5 bar 2.0E-09 1.0E-09 CO 2 3.0E-12 2.0E-12 0.0E+00 1.0E-12 1340 1345 1350 1355 1360 1365 1370 1375 1380 1385 1390 Time [min] Van Dijk et al (2011) Int J Greenhouse Gas Cntrl 5 (3) 505 36
Sufficient WGS activity before CO 2 breakthrough 400 C 30 bar 40 % H 2 O 17 % CO 17 % H 2 20% CO 2 200 ppm H 2 S Van Dijk et al (2011) Int J Greenhouse Gas Cntrl 5 (3) 505 37
Performance comparison IGCC, ~400 MW e No cap Selexol SEWGS Net Efficiency % 47.7 36.5 38.4 CO 2 avoidance % - 87.6 98.0 Specific energy use GJ/ton avoid - 3.7 2.6 Gazzani et al. GHGT-10 38
Catch-Up Pilot Plant, Buggenum Picture: Vattenfall 39
Catch-Up Pilot Plant, Buggenum process specifications and constraints simultaneous optimization of solvent and processes optimized process solvent parameters solvent candidates molecular mapping Damen et al. GHGT-10 40
Conclusions Physical solvents are attractive for pre-combustion CO 2 capture in IGCC plants Many Rectisol and Selexol units in operation Efficiency penalty for CO 2 capture can be reduced Improved solvents, membrane contacters Reduction of steam demand for WGS Hot gas clean-up Process intensification (sorption-enhanced reactor) 41
Acknowledgements caesar.ecn.nl 42