Pre-combustion with Physical Absorption

E.R. van Selow

R.W. van den Brink

Presented at the 2nd ICEPE, 18 November 2011, Frankfurt, Germany

ECN-L--11-126 November 2011

www.ecn.nl

Pre-combustion with Physical Absorption

Ed van Selow, Ruud van den Brink2nd ICEPE, 2011

2

IGCC with carbon removal

Oxygen

Gas treatment

Sulphur absorption

Clean gas shiftsteam

CO2 absorption

H2Pulverised

Coal

Gasifier

Gas treatment

3

Exergy losses in gas treatment (IGCC with CCS)

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

4

IGCC with carbon removal

Oxygen

Gas treatment

Sulphur absorption

Clean gas shiftsteam

CO2 absorption

H2Pulverised

Coal

Gasifier

Gas treatment

Sour vs sweet WGSExisting sour gas treating technologies

Chemical, physical, hybrid absorbentsPhysical sorbents and processes

DevelopmentsAdvanced solventsAdvanced shiftLow steam sour shiftSour PSAHigh-temperature gas clean-upReaction/separation integration: SEWGSPilot at Buggenum IGCC

5

Sour vs sweet WGS

6

Sour vs sweet (clean) WGS arrangement

Sour Shift Retains steam Hydrolysis COS Operates in a wider temperature range

Sweet ShiftMore selective sulphur removal Smaller reactorCheaper catalyst

7

Existing sour gas treating processes

8

Gas treatment requirements (example)

Selective sulphur removal

syngas De-S syngas

CO2+H2S

H2S+COS < 30 ppm

H2S > 20%

Sulphur + carbon

removal

syngas H2

CO2+H2S

H2S+COS < 30 ppm, CO+CO2 < 3%

Selectivesulphur +

carbon removal

syngas H2

CO2

H2S+COS < 30 ppm, CO+CO2 < 3%

H2S > 20%CO2+H2S

H2S < 200 ppm

9

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

can be achieved.

Sulphur removal 99%

High selectivity for H2S

Higher energy penalty due to

steam stripping

Higher investment costs

May form heat-stable salts Stable solvent

Low coabsorption Remove additional impurities

such as HCN, NH3

Co-adsorption of H2

Selecting the absorbent

10

Selecting the absorption process

Selection of suitable CO2

absorption process:

a) Physical solvent + amine

b) Physical solvent, physical solvent +

amine or activated hot K2CO3

c) Physical solvent

d) Physical solvent or activated hot K2CO3

e) Activated hot K2CO3 or concentrated

amine

f) Activated hot K2CO3 or amine

g) Amine

Trade-off at pCO2 ~ 6 bar between

solvent loading/recirculation (lean vs.

rich) and equipment sizing

Ullmann’s Encyclopedia

11

330 MWe NGCC Power Plant.

Based on January 2006 prices.

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

Propylene carbonate Fluor solvent O

Tetrahydrothiophenedioxide Sulfolane O

Tributyl phosphate Estasolvan O

C

h

e

m

i

c

a

l

P

h

y

s

i

c

a

l

M

i

x

e

d

12

330 MWe NGCC Power Plant.

Based on January 2006 prices.

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

Propylene carbonate Fluor solvent O

Tetrahydrothiophenedioxide Sulfolane O

Tributyl phosphate Estasolvan O

C

h

e

m

i

c

a

l

P

h

y

s

i

c

a

l

M

i

x

e

d

13

Gas Selexol Fluor

solvent

Purisol Methanol

H2 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 -

CO2 3.63 3.41 3.57 15

C3 3.7 1.74 3.82 -

COS 8.46 6.41 9.73 -

NH3 17.7 - - -

H2S 32.4 11.2 36.4 92

nC6 39.9 46.0 - -

H2O 2661 13640 14280 -

HCN 4356 - - -

Gas solubility data at 1 atm, 25 °C (-30 °C methanol), vol gas/vol liq

Bucklin and Schendel (1985)Hochgesand (1970)

14

Selexol Rectisol

H2S selectivity 9 6

H2S+COS removal< 0.1 ppm H2S + COS

Few ppm CO2

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

Comparing Selexol and Rectisol processes

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 (notstringent) w/o CO2 removal

Chemical solvent

Physical solvent

Low Capex

Low steam requirements

Sulphur + CO2 removal2-stage Selexol

Other

Quoted as preferred

Depending on requirements

19

IGCC/CCS studies

NETL/Parsons 2002. Evaluation of Fossil Fuel Power Plants with CO2 Recovery. 2007. Cost and Performance Baseline for Fossil Energy Plants. DOE/NETL-2007/1281.

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 CO2

capture. IEA Greenhouse Gas Program report 2007-13.

Politecnico di Milano / Alstom UK2011. European best practice guidelines for assessment of CO2 capture technologies.

20

New Developments

21

Improvements in CO2 solvent process

New combinations of aminesShell/Procede

Membrane-assisted desorptionTNO

Ionic liquidsTU 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

US2010.011955

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.

26

* Exergetic efficiency. Kunze et al. Energy 36 (2011) 1480

27

CO2 + H2CO + H2O ⇌

CO2

Syngas WGS 2%-6% CO

WGSH2 & CO2

Separation H2

28

SEWGS

→CO2 + H2CO + H2O

Syngas WGS2%-6% CO

CO2

H2

400 °C

25 bar

29

CO + H2O H2

CO2

CO2

CO2

CO2

CO2

CO2

sorbent sorbentcatalyst

CO2

Fe-Cr

Mg6Al2(OH)16CO3.4H2O

K-promoted Hydrotalcite (layered clay)

Meis et al. (2008)

Formation of MgCO3

3) Pressurisation

(dry CO2)

Re

lati

ve

inte

ns

ity

2 θ (degrees)

◊

◊

◊◊◊

◊

◊

◊

◊

◊

◊ ◊

◊

◊

◊

◊

◊

◊

◊

◊◊

◊◊◊

◊

◊◊ ◊

◊

2)Regeneration

Low pressure N2

4) Feed

CO2+steam (10 bar)

1) End of feed step

x

x

xx

x

x

x

x

x

x

x

xx

x

xx

x x

x x

x

0

10

20

30

40

50

0 200 400 600

Relative mass loss (%)

Temperature (°C)

0

2

4

6

8

10

12

0 50 100 150 200 250 300

cu

mu

lati

ve a

mo

un

t o

f C

O2

deso

rbed

(m

mo

l/g

)

cumulative amount of steam fed (mmol/g)

reference sorbent

new sorbent

30

31

32

CO2

product

rinse

repressurization

depressurization

FICFIC

H2

FICFIC

FICFIC

FICFIC

FICFIC

FICFIC

FICFIC

FICFIC

H2 product

PCVPCV

feed

purge

FIFI

FIFI

Steam

CO2

N2

CH4

CO

PCVPCV

purge

SEWGS multi-column unit at ECN

SEWGS process development unit at ECN

33

Alkasorb sorbent is stable

0

0.25

0.5

0.75

1

250 300 350 400 450 500

CO

2 in

to

p p

rod

uct

(%

dry

)

cycle no.

Van Selow et al (2010) GHGT-10, Amsterdam

34

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

35

36

0.0E+00

1.0E-09

2.0E-09

3.0E-09

4.0E-09

5.0E-09

6.0E-09

7.0E-09

8.0E-09

1340 1345 1350 1355 1360 1365 1370 1375 1380 1385 1390

Time [min]

MS

re

sp

on

se

[a

.u.]

1.0E-12

2.0E-12

3.0E-12

4.0E-12

5.0E-12

6.0E-12

7.0E-12

8.0E-12

9.0E-12

1.0E-11

Co-capture of H2S

H2S does not change CO2 sorption capacity or kinetics

K-AL

N2

H2O

CO2

0.0E+00 1.0E-12

H2S

Van Dijk et al (2011) Int J Greenhouse Gas Cntrl 5 (3) 505

400 °C

1.5 bar

11% CO2, 17% H2O, N2, (500 ppm H2S) 17% H2O, 83% Ar

37

Sufficient WGS activity before CO2 breakthrough

400 °C

30 bar

40 % H2O

17 % CO

17 % H2

20% CO2

200 ppm H2S

Van Dijk et al (2011) Int J Greenhouse Gas Cntrl 5 (3) 505

IGCC, ~400 MWeNo cap Selexol SEWGS

Net Efficiency % 47.7 36.5 38.4

CO2 avoidance % - 87.6 98.0

Specific energy use GJ/tonavoid - 3.7 2.6

Gazzani et al. GHGT-10

Performance comparison

38

Catch-Up Pilot Plant, Buggenum

Picture: Vattenfall

39

Catch-Up Pilot Plant, Buggenum

simultaneous optimization

of solvent and processes

molecular

mapping

solvent

parameters

solvent

candidates

process

specifications

and constraints

optimized

process

Damen et al. GHGT-10

40

Conclusions

Many Rectisol and Selexol units in operation

Physical solvents are attractive for pre-combustion CO2 capture in IGCC plants

Efficiency penalty for CO2 capture can be reduced

Improved solvents, membrane contactersReduction of steam demand for WGSHot gas clean-upProcess intensification (sorption-enhanced reactor)

41

Acknowledgements

42

caesar.ecn.nl