Pre-combustion with Physical AbsorptionEd van Selow, Ruud van den Brink

2nd ICEPE, 2011

www.ecn.nl

2

IGCC with carbon removal Gas treatment

Oxygen

H2PulverisedCoal

Gas treatment

Cl hiftsteam

Sulphur absorptionClean gas shift

CO2 absorption

G ifiGasifier

3

Exergy losses in gas treatment (IGCC with CCS)

Kunze et al (2010) 4th Int Freiberg Conf, Dresden

4

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

5

Sour vs sweet WGSSour vs sweet WGS

6

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

7

Existing sour gas treating processesExisting sour gas treating processes

8

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

2

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

9

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

10

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

11

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

12

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

13

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 - - -

14

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

15

Absorber/desorber column design

Absorption Stripping

16

Regeneration of solvents

Flashing Stripping Reboiling

17

Source: UOP

18

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

19

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. 

20

New DevelopmentsNew Developments

21

Improvements in CO2 solvent process

New combinations of aminesNew combinations of aminesShell/ProcedeShell/Procede

Membrane‐assisted desorptionMembrane‐assisted desorptionTNOTNO

Ionic liquidsIonic liquidsTU DelftTU Delft

22

Advanced Shift (Sweet/Sour)Carbo et al (2009) Int J Greenhouse Gas Ctrl  3 (6) 712

23

Low-Steam Sour Shift

24

Sour H2 PSA

US2010.011955US2010.011955

25

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

26

 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

27

CO2

→CO2 + H2CO + H2O CO2 H2CO H2O2% 6% COSyngas WGS 2%-6% CO

SEWGSH SEWGSH2

400 °C CO2400 °C25 bar

28

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

29

Formation of MgCO3

sity

◊

◊

◊◊◊

◊

◊

◊

◊

◊

xx x

3) Pressurisation(dry CO2)

Rel

ativ

e in

tens

◊

◊◊

◊

◊ ◊◊

◊

◊4) Feed

CO2+steam (10 bar)

x x

x

x

x

xx

x

x

xx

x x

x x

x

40

50

◊

◊

◊◊

◊◊◊

◊

◊◊ ◊◊

2)RegenerationLow pressure N2

1) End of feed step

xxx

20

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)

30

31

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

32

productp g

SEWGS process development unit at ECN

33

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.

34

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

35

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

36

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

37

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

38

Catch-Up Pilot Plant, Buggenum

Picture: VattenfallPicture: Vattenfall

39

Catch-Up Pilot Plant, Buggenum

Damen et al. GHGT‐10

40

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)

41

Acknowledgements

caesar.ecn.nl

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