Techno-economic evaluation of a low-temperature CO2 capture unit for IGCC Plants

David Berstad, Simon Roussanaly, Rahul Anantharaman, Petter Nekså, Jana Jakobsen

SINTEF Energy Research

8th International Freiberg Conference on IGCC & XtL Technologies

Köln, 12–16 June 2016

Outline

• Background and motivation

• CO2 capture conditions – implications on capture technology

• Syngas data in consideration

• Process principles and design

• Techno-economic performance

• Concluding remarks, further work

2

Background and motivation

• Generally: Different CO2 separation technologies have different

optimal operating conditions

• In the lower range of CO2 concentration, chemical sorption with high binding

energy is generally the prevailing technology

• Above a certain CO2 concentration, bulk separation technologies such as e.g.

condensation or membranes will become more efficient than solvents and

sorbents

• Specifically: The high CO2 concentration and partial pressure for

typical IGCC syngas (shifted) can be utilised to achieve highly energy-

and cost-efficient capture units by low-temperature condensation

3

CO2 capture conditions for IGCC

4

0.01

0.1

1

10

100

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

CO

2p

arti

al p

ress

ure

[b

ar]

CO2 concentration

Post-combustion, NGCC

Post-combustion, NG boiler

Post-combustion, Coal

Pre-combustion, Coal

Oxy-combustion, NG

Oxy-combustion, coal

Pre-combustion, NG

Steel, before expansion

Steel, after expansion

Aluminium

Refinery

Cement

CO2 transport spec.

Oxy-combustion, refinery

Post-combustion, NGCC+MCFC

Ammonia production

5.2 bar

1 atm

Based on: Berstad D., Anantharaman R., Nekså P. Low-temperature CO2 capture technologies – Applications and potential.International Journal of Refrigeration, 36(5) 2013, 1403–1416

Figure: CO2 capture conditions for large point-source processes

IGCC process

5

Oxygen

Production

Fuel

Preparation

compression+ inter- / after--cooling

coal-wet-01

dry-coal-01

air-01 oxygen-05nitrogen-07

Desulphur.Rectisol

Rect-steam-02

syngas-01 syngas-11

FP-steam-01

GT

flue-gas-01

H2S-11slag-01 ash-01 prod-steam-01

sg-cond-01

Rect-DW-01

ASU-power

FP-power-01

FP-cond-01

ASU-cool

Compr-power

GT-power

Compr-cool

Gasification+quench

syngas-04

power-sg-refriggasif-power

air-11MeOH-makeup

gasif-cool

Steamcycle

flue-gas-11

SC-power SC-steam-out

SC-steam-inH2O-makeup

ASU-cond-01

power-rect-refrig

syngas-02 syngas-22

streams

utilities / steam

cool(optional)

syngas-12C 2 Ocapture

syngas-21

N2-H2

N2-H2

H2-preheat-1(optional)Σ utilities

CO2 stream Waste etc.

cooling 460-200°C

WGS

steam ~40 bar

cooling 225-30°C

c-syngas

steam 130 bar

heat recovery

recuperated heat

syngas-11A

IGCC process

6

Oxygen

Production

Fuel

Preparation

compression+ inter- / after--cooling

coal-wet-01

dry-coal-01

air-01 oxygen-05nitrogen-07

Desulphur.Rectisol

Rect-steam-02

syngas-01 syngas-11

FP-steam-01

GT

flue-gas-01

H2S-11slag-01 ash-01 prod-steam-01

sg-cond-01

Rect-DW-01

ASU-power

FP-power-01

FP-cond-01

ASU-cool

Compr-power

GT-power

Compr-cool

Gasification+quench

syngas-04

power-sg-refriggasif-power

air-11MeOH-makeup

gasif-cool

Steamcycle

flue-gas-11

SC-power SC-steam-out

SC-steam-inH2O-makeup

ASU-cond-01

power-rect-refrig

syngas-02 syngas-22

streams

utilities / steam

cool(optional)

syngas-12C 2 Ocapture

syngas-21

N2-H2

N2-H2

H2-preheat-1(optional)Σ utilities

CO2 stream Waste etc.

cooling 460-200°C

WGS

steam ~40 bar

cooling 225-30°C

c-syngas

steam 130 bar

heat recovery

recuperated heat

syngas-11A

Syngas dataT [°C] 30.0P [bar] 28.0m [kg/s] 68.0CO2 38.68 %H2 53.47 %N2 5.90 %H2S 0.00 %CO 1.09 %COS 0.01 %H2O 0.03 %O2 0.00 %AR 0.80 %

Vapour–liquid equilibrium for CO2/H2

7

220 K

225 K

235 K

237 K

245 K

250 K

260 K

270 K

280 K

290 K

225 K

220 K

0

200

400

600

800

1000

1200

1400

1600

1800

0 0.2 0.4 0.6 0.8 1

Pre

ssu

re [

bar

]

← Vapour phase CO2 mole fraction Liquid phase →

Vapour–liquid equilibria for the binary H2/CO2 system. Plot based on experimental data from Tsang and Streett (1981)

Shifted syngasY0 (CO2 fraction in feed)

Liquid CO2

X (CO2 fraction in liquid phase)

Hydrogen-rich fuelY (CO2 fraction in vapour phase)

CO2 capture ratio: CCR =𝑋 𝑌0 − 𝑌

𝑌0 𝑋 − 𝑌

XYT, P

Vapour–liquid equilibrium for CO2/H2

8 Estimated CCR for binary mixtures of H2 and CO2 separated at -53°C (Berstad et al., 2013)

0

10

20

30

40

50

60

70

80

90

100

10 20 30 40 50 60 70 80 90 100 110 120

CC

R [

%]

Separation pressure [bar]

Peng–Robinson: 42% CO2, 58% H2Peng–Robinson: 40% CO2, 60% H2Peng–Robinson: 38% CO2, 62% H2Spano et al.: 40% CO2, 60% H2Tsang & Streett: 40% CO2, 60% H2

Syngas dataT [°C] 30.0P [bar] 28.0m [kg/s] 68.0CO2 38.68 %H2S 0.00 %CO 1.09 %N2 5.90 %COS 0.01 %H2 53.47 %H2O 0.03 %O2 0.00 %AR 0.80 %

Process design principles – 84% CCR

• Feed dehydration

• Syngas compression from 28

bar to 105 bar

• High- and low-pressure

separation stages at -55°C

• Energy recuperation

• Process-to-process heat recuperation

• Gas expanders (power recovery and

additional heat recuperation)

• Auxiliary refrigeration

• Liquid pumping of CO2 to

transport pressure9

Shifted

syngas

Dehydration

Compression

Hydrogen fuel

CO2/H2 recycle

CO2 to

transport

LT CO2 pumpHT CO2 pump

Utility

refrigeration

Utility

refrigeration

Hydrogen expanders

HX1

HX2a

HX2b

M

G

HX3HX4

HX5

M

90 bar

15 bar

110 bar

-55°C

-55°C

Shifted

syngas

Dehydration

Hydrogen fuel

CO2/H2 recycle

CO2 to

transport

LT CO2 pumpHT CO2 pump

Utility

refrigeration

Utility

refrigeration

M

Process design principles – 51% CCR (1)

• No additional syngas

compression

• No gas expander

10

26 bar

110 bar

-55°C

-55°C

0

10

20

30

40

50

60

70

80

90

100

10 20 30 40 50 60 70 80 90 100 110 120

CC

R [

%]

Separation pressure [bar]

Peng–Robinson: 42% CO2, 58% H2Peng–Robinson: 40% CO2, 60% H2Peng–Robinson: 38% CO2, 62% H2Spano et al.: 40% CO2, 60% H2Tsang & Streett: 40% CO2, 60% H2

Process design principles – 51% CCR (2)

• No additional syngas

compression

• Gas expander for max

energy recovery

11

15 bar

110 bar

-55°C

-55°C

0

10

20

30

40

50

60

70

80

90

100

10 20 30 40 50 60 70 80 90 100 110 120

CC

R [

%]

Separation pressure [bar]

Peng–Robinson: 42% CO2, 58% H2Peng–Robinson: 40% CO2, 60% H2Peng–Robinson: 38% CO2, 62% H2Spano et al.: 40% CO2, 60% H2Tsang & Streett: 40% CO2, 60% H2

Shifted

syngas

Dehydration

Hydrogen fuel

CO2/H2 recycle

CO2 to

transport

LT CO2 pumpHT CO2 pump

Utility

refrigeration

Utility

refrigeration

M

Waste heat

exchangerG

Expander

Energy results – decomposed

12

-200

-100

0

100

200

300

400

500

84% CCR 51% CCR (No gasexp.)

51% CCR (with gasexp.)

Spe

cifi

c C

O2

sep

arat

ion

an

d

com

pre

ssio

n w

ork

[kJ

/kg C

O2]

CO2 pumping

Recycle compression

Cooling water pumping

Aux. refrigeration

Syngas compression

Expansion recovery

Net specific work

Overall cost results (84% CCR vs. no CCS)

13

IGCC plantwithout CCS

IGCC plantwith 84%

capture ratio

Total plant cost (€) 100% 114%

Fixed + variable operating cost (€/a) 100% 110%

Net power plant output MW 276 215 (-22%)

Installed power cost (€/MWinst) 100% 147%

Electricity cost (€/MWh) 100% 143%

Specific emissions kgCO2/MWh 764 139

CO2 avoidance cost €/tonCO2 – 42.1

Discussion – cost results

• The cost evaluation accounts for level of

technology maturity

• The current case study is not the most

favourable for low-temperature CO2

separation

• The gasification pressure for the current

case is rather low

• Increases need for installed compression capacity

• Increases cost for low-temperature CO2 separation

considerably14

Berstad, Roussanaly et al.Energy and cost evaluation of a low-temperature CO2 capture unit for IGCC plants(GHGT-12 Conference, Energy Procedia, 2014)

Concluding remarks and further work

• High CO2 concentration and pressure is favourable for CO2 separation

processes by liquefaction and phase separation

• CO2 capture ratio in the range of 85% can be obtained for shifted

syngas with around 40% CO2 concentration – this requires further

compression of the syngas (up to around 100 bar)

• Lower capture ratios ("partial capture") can be achieved with lower

investment and power requirement without syngas compression

prior to cooling and condensation

• Further work includes lab pilot testing of the technology

15

Acknowledgements

This work is supported by the Norway Grants, as part of the

project NF-CZ08-OV-1-003-2015

16

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