Pre-combustion with Physical Absorption -...
Transcript of Pre-combustion with Physical Absorption -...
Pre-combustion with Physical AbsorptionEd van Selow, Ruud van den Brink
2nd ICEPE, 2011
www.ecn.nl
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IGCC with carbon removal Gas treatment
Oxygen
H2PulverisedCoal
Gas treatment
Cl hiftsteam
Sulphur absorptionClean gas shift
CO2 absorption
G ifiGasifier
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Exergy losses in gas treatment (IGCC with CCS)
Kunze et al (2010) 4th Int Freiberg Conf, Dresden
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IGCC with carbon removal Gas treatment
Sour vs sweet WGSExisting sour gas treating technologies
Chemical physical hybrid absorbents
Oxygen
Chemical, physical, hybrid absorbentsPhysical sorbents and processes
Developments
H2PulverisedCoal
pAdvanced solventsAdvanced shift
Gas treatment
Cl hiftsteam
Low steam sour shiftSour PSAHigh‐temperature gas clean‐up
Sulphur absorptionClean gas shift
CO2 absorption
G ifi
High‐temperature gas clean‐upReaction/separation integration: SEWGSPilot at Buggenum IGCC
Gasifiergg
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Sour vs sweet WGSSour vs sweet WGS
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Sour vs sweet (clean) WGS arrangement
Sour ShiftSour Shift Sweet ShiftSweet ShiftSour Shift Retains steam Hydrolysis COS Operates in a wider temperature range
Sour Shift Retains steam Hydrolysis COS Operates in a wider temperature range
Sweet ShiftMore selective sulphur removal Smaller reactorCheaper catalyst
Sweet ShiftMore selective sulphur removal Smaller reactorCheaper catalyst
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Existing sour gas treating processesExisting sour gas treating processes
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Gas treatment requirements (example)
SelectiveSelectivesyngas De S syngas H2S+COS < 30 ppmSelective sulphur removal
Selective sulphur removal
syngas De‐S syngas
CO2+H2S
H2S+COS < 30 ppm
H2S > 20%
Sulphur + Sulphur + syngas H2H2S+COS < 30 ppm, CO+CO2 < 3%p
carbon removal
pcarbon removal
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CO2+H2S
Selectivesulphur + Selectivesulphur +
syngas H2H2S+COS < 30 ppm, CO+CO2 < 3%
carbon removalcarbon removalCO2
H2S > 20%CO +H S
H2S < 200 ppm
H2S > 20%CO2+H2S
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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 H2S
Higher energy penalty due to steam stripping
Higher investment costssteam stripping
May form heat‐stable salts Stable solvent
Low coabsorption Remove additional impurities p psuch as HCN, NH3
Co‐adsorption of H2
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Selecting the absorption process
Trade-off at pCO2 ~ 6 bar between solvent loading/recirculation (lean vs. i h) d i t i i
Trade-off at pCO2 ~ 6 bar between solvent loading/recirculation (lean vs. i h) d i t i i
Ullmann’s Encyclopedia
Selection of suitable CO2
rich) and equipment sizingrich) and equipment sizing
Selection of suitable CO2absorption process:a) Physical solvent + amineb) Physical solvent, physical solvent +
amine or activated hot K2CO3
c) Physical solventd) Physical solvent or activated hot K2CO3
e) Activated hot K CO or concentratede) Activated hot K2CO3 or concentrated amine
f) Activated hot K2CO3 or amineg) Amine
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Monoethanolamine MEA O O O
Diethanolamine DEA O
Chem
Diisopropanolamine ADIP O
Methyldiethanolamine MDEA O O O
Potassium carbonate Hotpot O O O
ical
MMethanol+MDEA/DEA Amisol O
XXX+MDEA Flexsorb O
Sulfolane+MDEA/DIPA Sulfinol O
Mixed
DME of PE glycol Selexol O
Methanol Rectisol O O
N‐Methylpyrrolidone Purisol O
Phys
d
330 MWe NGCC Power Plant. Based on January 2006 prices.
PE glycol + dialkyl ether Sepasolv O
Propylene carbonate Fluor solvent OTetrahydrothiophenedioxide Sulfolane O
ical
Tributyl phosphate Estasolvan O
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Monoethanolamine MEA O O O
Diethanolamine DEA O
Chem
Diisopropanolamine ADIP O
Methyldiethanolamine MDEA O O O
Potassium carbonate Hotpot O O O
ical
MMethanol+MDEA/DEA Amisol O
XXX+MDEA Flexsorb O
Sulfolane+MDEA/DIPA Sulfinol O
Mixed
DME of PE glycol Selexol O
Methanol Rectisol O O
N‐Methylpyrrolidone Purisol O
Phys
d
330 MWe NGCC Power Plant. Based on January 2006 prices.
PE glycol + dialkyl ether Sepasolv O
Propylene carbonate Fluor solvent OTetrahydrothiophenedioxide Sulfolane O
ical
Tributyl phosphate Estasolvan O
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Gas Selexol Fluor solvent
Purisol MethanolGas solubility data at 1 atm, 25 °C (‐30 °C methanol), vol gas/vol liq
solventH2 0.047 0.027 0.02 -CO 0.10 0.072 0.075 -C1 0.24 0.13 0.26 -C2 1.52 0.58 1.36 -CO 3 63 3 41 3 57 15
Bucklin and Schendel (1985)Hochgesand (1970)
CO2 3.63 3.41 3.57 15C3 3.7 1.74 3.82 -COS 8 46 6 41 9 73 -COS 8.46 6.41 9.73NH3 17.7 - - -H2S 32.4 11.2 36.4 92nC6 39.9 46.0 - -H2O 2661 13640 14280 -HCN 4356 - - -
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Comparing Selexol and Rectisol processes
Selexol Rectisol
H2S selectivity 9 6
H S+COS removal< 0.1 ppm H2S + COSH2S+COS removalFew ppm CO2
Temperature ‐5 .. 175 °C ‐60 .. ‐15 °C
OPEX, CAPEXHigher OPEX and CAPEX: complex scheme and need to refrigerate
Other COS hydrolysis needed High vapor losses
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Absorber/desorber column design
Absorption Stripping
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Regeneration of solvents
Flashing Stripping Reboiling
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Source: UOP
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Selecting the absorption process in IGCC
Sulphur removal (notstringent) w/o CO2 removalSulphur removal (notstringent) w/o CO2 removal
Chemical solventChemical solvent
Low CapexLow Capexg ) / 2g ) / 2
Physical solventPhysical solvent
Low steam requirementsLow steam requirementsqq
Sulphur + CO2 removalSulphur + CO2 removal2‐stage Selexol2‐stage Selexol
Quoted as preferredQuoted as preferred
OtherOtherDepending on requirementsDepending on requirements
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IGCC/CCS studiesNETL/PNETL/PNETL/Parsons 2002. Evaluation of Fossil Fuel Power Plants with CO2 Recovery. 2007. Cost and Performance Baseline for Fossil Energy Plants. DOE/NETL‐2007/1281
NETL/Parsons 2002. Evaluation of Fossil Fuel Power Plants with CO2 Recovery. 2007. Cost and Performance Baseline for Fossil Energy Plants. DOE/NETL‐2007/12812007/1281. 2007/1281.
Foster WheelerFoster WheelerFoster Wheeler2003. Potential for improvement in gasification combined cycle power generation with CO2 capture. IEA report No. PH4/19, 2003. 2007. Co‐production of hydrogen and electricity by coal gasification with CO2
Foster Wheeler2003. Potential for improvement in gasification combined cycle power generation with CO2 capture. IEA report No. PH4/19, 2003. 2007. Co‐production of hydrogen and electricity by coal gasification with CO22007. Co production of hydrogen and electricity by coal gasification with CO2capture. IEA Greenhouse Gas Program report 2007‐13. 2007. Co production of hydrogen and electricity by coal gasification with CO2capture. IEA Greenhouse Gas Program report 2007‐13.
P lit i di Mil / Al t UKP lit i di Mil / Al t UKPolitecnico di Milano / Alstom UK2011. European best practice guidelines for assessment of CO2 capture technologies.
Politecnico di Milano / Alstom UK2011. European best practice guidelines for assessment of CO2 capture technologies.
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New DevelopmentsNew Developments
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Improvements in CO2 solvent process
New combinations of aminesNew combinations of aminesShell/ProcedeShell/Procede
Membrane‐assisted desorptionMembrane‐assisted desorptionTNOTNO
Ionic liquidsIonic liquidsTU DelftTU Delft
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Advanced Shift (Sweet/Sour)Carbo et al (2009) Int J Greenhouse Gas Ctrl 3 (6) 712
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Low-Steam Sour Shift
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Sour H2 PSA
US2010.011955US2010.011955
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Drivers for high-temperature gas clean-up
Th hi h ffi i ith t li dTh hi h ffi i ith t li dThe higher process efficiency without syngas cooling and removal of water from the syngas: +5.2%‐points*.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 sour water treating.
h l f h bl k d d dh l f h bl k d d dThe elimination of the black mud produced in wet scrubbing of particulates from the syngas.The elimination of the black mud produced in wet scrubbing of particulates from the syngas.
The potential related Capex and Opex savings.The potential related Capex and Opex savings.
The viability of air‐blown gasifiers.The viability of air‐blown gasifiers.
* Exergetic efficiency Kunze et al Energy 36 (2011) 1480
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Exergetic efficiency. Kunze et al. Energy 36 (2011) 1480
CO2 + H2CO + H2O CO2 H2CO H2O2% 6% COSyngas WGS 2%-6% CO
WGSH2 & CO2
S ti HCO
Separation H2
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CO2
→CO2 + H2CO + H2O CO2 H2CO H2O2% 6% COSyngas WGS 2%-6% CO
SEWGSH SEWGSH2
400 °C CO2400 °C25 bar
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CO + H2O H2
CO CO2CO2 COCO2
CO22
CO2
CO2
sorbent sorbentcatalyst
CO2
Meis et al. (2008)
Fe-CrK‐promoted Hydrotalcite (layered clay)
( )
Mg6Al2(OH)16CO3.4H2O
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Formation of MgCO3
sity
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xx x
3) Pressurisation(dry CO2)
Rel
ativ
e in
tens
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◊4) Feed
CO2+steam (10 bar)
x x
x
x
x
xx
x
x
xx
x x
x x
x
40
50
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2)RegenerationLow pressure N2
1) End of feed step
xxx
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30Relative mass loss (%)
2 θ (degrees)
0
10
0 200 400 600 10
12
/g)
0 200 400 600
Temperature (°C)
6
8
f C
O2
des
orb
ed (
mm
ol/
reference sorbent
0
2
4
0 50 100 150 200 250 300
cum
ula
tive
am
oun
t of
new sorbent
0 50 100 150 200 250 300
cumulative amount of steam fed (mmol/g)
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FICFIC
SEWGS multi-column unit at ECNFICFIC
FICFIC
FICFIC
H2 product
PCVPCV FIFI
Steam
rinse
H2 FICFIC
FICFIC
purge
CO2
repressurization
FICFIC
FICFIC
N2
FICFIC
FICFIC
feed
CH4
CO
CO2d t
depressurization
FIFI
PCVPCV
purge
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productp g
SEWGS process development unit at ECN
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Alkasorb sorbent is stable1
Van Selow et al (2010) GHGT‐10, Amsterdam1
0.75
t (%
dry
)
0.5
top
pro
duct
0.25
CO
2 in
0
250 300 350 400 450 500
cycle no.
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Effect of feed pressure Wright et al (2010) GHGT‐10, Amsterdam
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Co-capture of H2SH2S does not change CO2 sorption capacity or kinetics
8.0E-09 1.0E-11
H2S does not change CO2 sorption capacity or kinetics
11% CO2, 17% H2O, N2, (500 ppm H2S) 17% H2O, 83% Ar
6.0E-09
7.0E-09
8.0E-12
9.0E-12N2
4.0E-09
5.0E-09
spon
se [a
.u.]
5 0E-12
6.0E-12
7.0E-12
K-ALH2S
400 °C
2.0E-09
3.0E-09
MS
res
3.0E-12
4.0E-12
5.0E 12
H2O
CO2
1.5 bar
0.0E+00
1.0E-09
1340 1345 1350 1355 1360 1365 1370 1375 1380 1385 13901.0E-12
2.0E-122
0.0E+00 1.0E-12
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Time [min] Van Dijk et al (2011) Int J Greenhouse Gas Cntrl 5 (3) 505
Sufficient WGS activity before CO2 breakthrough
400 °C
30 bar
40 % H2O
17 % CO
17 % H2
20% CO2
200 ppm H2S
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Van Dijk et al (2011) Int J Greenhouse Gas Cntrl 5 (3) 505
Performance comparison
IGCC, ~400 MWe No cap Selexol SEWGS, e p
Net Efficiency % 47.7 36.5 38.4y
CO2 avoidance % - 87.6 98.0
Specific energy use GJ/tonavoid - 3.7 2.6
G i l GHG 10Gazzani et al. GHGT‐10
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Catch-Up Pilot Plant, Buggenum
Picture: VattenfallPicture: Vattenfall
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Catch-Up Pilot Plant, Buggenum
Damen et al. GHGT‐10
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Conclusions
Physical solvents are attractive for pre‐combustion CO2 capture in IGCC plantsPhysical solvents are attractive for pre‐combustion CO2 capture in IGCC plants
Many Rectisol and Selexol units in operationMany Rectisol and Selexol units in operation
Efficiency penalty for CO2 capture can be reducedEfficiency penalty for CO2 capture can be reduced
Improved solvents, membrane contactersReduction of steam demand for WGSH t l
Improved solvents, membrane contactersReduction of steam demand for WGSH t lHot gas clean‐upProcess intensification (sorption‐enhanced reactor)Hot gas clean‐upProcess intensification (sorption‐enhanced reactor)
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Acknowledgements
caesar.ecn.nl
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