Pre-combustion with Physical Absorption

Transcription

1 Pre-combustion with Physical Absorption Ed van Selow, Ruud van den Brink 2 nd ICEPE,

2 2

3 IGCC with carbon removal Gas treatment Oxygen Pulverised Coal H 2 Gas treatment steam Clean gas shift Sulphur absorption CO 2 absorption Gasifier 3

4 Exergy losses in gas treatment (IGCC with CCS) Kunze et al (2010) 4 th Int Freiberg Conf, Dresden 4

5 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 steam High temperature gas Clean clean up gas shift Reaction/separation Sulphur absorption integration: SEWGS Pilot at Buggenum IGCC Gas treatment CO 2 absorption H 2 5

6 6 Sour vs sweet WGS

7 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 8 Existing sour gas treating processes

9 Gas treatment requirements (example) syngas Selective De S syngas H 2 S+COS < 30 ppm sulphur removal CO 2 +H 2 S H 2 S > 20% syngas Sulphur + carbon H 2 H 2 S+COS < 30 ppm, CO+CO 2 < 3% removal CO 2 +H 2 S syngas Selective H 2 H 2 S+COS < 30 ppm, CO+CO 2 < 3% sulphur + carbon removal CO 2 H 2 S < 200 ppm CO 2 +H 2 S H 2 S > 20% 9

10 Selecting the absorbent Chemical solvents (amines) Mixed (hybrid) solvents Physical solvents More efficient at low pressure More efficient at high pressure Sulphur removal 98% Very high sulphur recoveries Sulphur removal 99% can be achieved. High selectivity for H 2 S Higher energy penalty due to Higher investment costs steam stripping May form heat stable salts Low coabsorption Stable solvent Remove additional impurities such as HCN, NH 3 Co adsorption of H 2 10

11 Selecting the absorption process Ullmann s Encyclopedia Trade-off at p CO2 ~ 6 bar between solvent loading/recirculation (lean vs. rich) and equipment sizing i 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

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 12

13 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

14 Gas solubility data at 1 atm, 25 C ( 30 C methanol), vol gas/vol liq Gas Selexol Fluor solvent Purisol Methanol H CO C C CO C COS NH H 2 S nc H 2 O HCN Bucklin and Schendel (1985) Hochgesand (1970) 14

15 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 C C OPEX, CAPEX Higher OPEX and CAPEX: complex scheme and need to refrigerate Other COS hydrolysis needed High vapor losses 15

16 Absorber/desorber column design Absorption Stripping 16

17 Regeneration of solvents Flashing Stripping Reboiling 17

18 18 Source: UOP

19 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

20 IGCC/CCS studies NETL/Parsons Evaluation of Fossil Fuel Power Plants with CO 2 Recovery Cost and Performance Baseline for Fossil Energy Plants. DOE/NETL 2007/1281. Foster Wheeler Potential for improvement in gasification combined cycle power generation with CO 2 capture. IEA report No. PH4/19, Co production of hydrogen and electricity by coal gasification with CO 2 capture. IEA Greenhouse Gas Program report Politecnico i di Milano / Alstom UK European best practice guidelines for assessment of CO 2 capture technologies. 20

21 21 New Developments

22 Improvements in CO 2 solvent process Shell/Procede TNO New combinations of amines Membrane assisted desorption TU Delft Ionic liquids 22

23 Advanced Shift (Sweet/Sour) Carbo et al (2009) Int J Greenhouse Gas Ctrl 3 (6)

24 24 Low-Steam Sour Shift

25 Sour H 2 PSA US

26 Drivers for high-temperature gas clean-up The higher h process efficiency i without t 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 d 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)

27 CO + H O CO + H Syngas WGS 2%-6% CO H 2 & CO 2 WGS Separation H 2 CO 2 27

28 CO + H O CO + H Syngas WGS 2%-6% CO H 2 SEWGS 400 C 25 bar CO 2 28

29 CO + H 2 O H 2 CO 2 CO CO 2 sorbent CO CO 2 2 CO catalyst sorbent 2 CO 2 CO 2 2 Meis et al. (2008) K promoted Hydrotalcite (layered clay) Fe-Cr Mg 6 Al 2 (OH) 16 CO 3.4H 2 O 29

30 Formation of MgCO 3 Relative mass loss (%) sity Relative intens 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) Temperature ( C) /g) f CO2 desorbed (mmol/ cumulative amount of 10 reference sorbent new sorbent cumulative amount of steam fed (mmol/g) 30

31 31

32 FIC 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 2d product 32

33 33 SEWGS process development unit at ECN

34 Alkasorb sorbent is stable 1 Van Selow et al (2010) GHGT 10, Amsterdam 0.75 top product (% dry) 0.5 CO2 in cycle no. 34

35 Effect of feed pressure Wright et al (2010) GHGT 10, Amsterdam 35

36 0.0E E-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 E-09 N 2 9.0E E E-12 MS res sponse [a.u.] 5.0E E E-09 H 2 S H 2 O K-AL 7.0E E-12 50E E 4.0E C 1.5 bar 2.0E E-09 CO 2 3.0E E E E Time [min] Van Dijk et al (2011) Int J Greenhouse Gas Cntrl 5 (3)

37 Sufficient WGS activity before CO 2 breakthrough 400 C 30 bar 40 % H 2 O 17 % CO 17 % H 2 20% CO ppm H 2 S Van Dijk et al (2011) Int J Greenhouse Gas Cntrl 5 (3)

38 Performance comparison IGCC, ~400 MW e No cap Selexol SEWGS Net Efficiency % CO 2 avoidance % Specific energy use GJ/ton avoid Gazzani et al. GHGT 10 38

39 Catch-Up Pilot Plant, Buggenum Picture: Vattenfall 39

40 Catch-Up Pilot Plant, Buggenum Damen et al. GHGT 10 40

41 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

42 Acknowledgements caesar.ecn.nl 42