1

1

Bolland

TEP03 CO2 capture in power plants

Part 7 – Oxy-combustion CO2capture

Olav BollandProfessor

Norwegian University of Science and TechnologyDepartment of Energy and Process Engineering

September 2013

2

Oxy-combustion – the method

CO₂separation

CO₂ compression & conditioning

N₂/O₂

CO₂

ShiftH₂

CO₂

Powerplant

Air

O₂N₂

CO₂

N₂/O₂CO₂ compression

& conditioning

Powerplant

Gasification

Reforming

CO₂separation

H₂

CO₂

CO/H₂

Air separation

CO/H₂

Coa

l, O

il, N

atur

al G

as,

Bio

mas

s Powerplant

Post-combustion

Pre-combustion

Oxy-combustion

3

OHCOOCH 2224 22

2222

22

77.344

)1(2

)77.3(4

Nn

mOn

mOHn

COm

NOn

mHC nm

AirAir excess ratio

Reactants

Products’exhaust’’flue gas’

3-14%

Oxy-combustion

4

OHCOOCH2224

22

Oxy-combustion CO2 capture

kg4kg1

32216

/dayO tons 4150

MJ/kg 50/skg 12MW600

)efficiency (50%MW600MW 300

2

CHCHfuel

fuele

44

)(@

Largest ASU train sizePossible in 2009

Combustion in oxygen high temp Recycle back to combustion zone• Recycle of CO2

• Recycle of H2O• Recycle of CO2+H2O

5

Oxy-combustion CO2 capture

0

1

2

3

4

5

6

7

8

9

H2 Hydrogen

CO Carbon

monoxide

CH4 Methane

C2H6 Ethane

C3H8 Propane

C4H10 Butane

CH3OH Methanol

C2H5OH Ethanol

Lignite B(Rheinl.)

DraytonHigh-vol

bituminous

Pet-coke

kg O

2/kg

fue

l

0

10

20

30

40

50

60

70

80

90

kg O

2/G

J fu

el L

HV

kg O2/kg fuel (wide bars)

kg O2/GJ LHV (narrow bars)

6

Oxy-combustion - air separation?

Cryogenic distillation

AdsorptionMembrane

Polymeric membrane

Ceramic membrane

Vacuum Swing Adsorption

(VSA)

Vacuum Pressure Swing Adsorption

(VPSA)

Pressure Swing Adsorption

(PSA)

Electrically driven

membrane

Partial pressure driven

membrane

Air Separation Technologies

7

Air separation - composition

Component Volume-% Molar weight

Nitrogen N2 78.08 28.013

Oxygen O2 20.95 31.999

Argon Ar 0.93 39.948

Carbon dioxide CO2 0.038 44.010

Other gases - <0.002

Molecular weight of dry air 28.964 kg/kmolH2O, varies, but typically about 1%

Other gases constitute a small fraction; neon (Ne), helium (He), krypton (Kr), sulfur dioxide (SO2), methane (CH4), hydrogen (H2), nitrous oxide (N2O), xenon (Xe), ozone (O3), nitrogen dioxide (NO2), iodine (I2) and very small traces of carbon monoxide (CO) and ammonia (NH3)

8

Air separation - composition

At atmospheric pressure the boiling point of:

nitrogen is -195.8 C, oxygen -182.9 C,argon -185.9 C

CO2 sublimes (gas-to-solid phase change) at -78.46 C

H2O

9

Air separation - Boiling point diagram for oxygen-nitrogen

-198

-197

-196

-195

-194

-193

-192

-191

-190

-189

-188

-187

-186

-185

-184

-183

-182

-198

-197

-196

-195

-194

-193

-192

-191

-190

-189

-188

-187

-186

-185

-184

-183

-182

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Tem

per

atur

e [

C]

Composition, mole fraction oxygen, (p = 1.0132 bar)

10

Air separation - Boiling point diagram for oxygen-argon

-186.0

-185.5

-185.0

-184.5

-184.0

-183.5

-183.0

-182.5

-182.0

-186.0

-185.5

-185.0

-184.5

-184.0

-183.5

-183.0

-182.5

-182.0

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Tem

per

atur

e [

C]

Composition, mole fraction oxygen, (p = 1.0132 bar)

11

Air

Main aircompressorAir pre-

treatment

H2O CO2

Booster air compressor

Oxygen

Wastenitrogen

ExpanderOxygenpump

HP Column

LP Column

Subcooler

ASU – liquid O2 pumping

Cooler

1

2

3

12 9

10

11

13

6

4

8

7

5

8

12

ASU – condenser/reboiler between columns

Gaseousoxygen

Exchanger

Liquid oxygen

Gaseousnitrogen

LP column

HP column

Liquidnitrogen

Liquid oxygen

13

ASU – liquid O2 pumpingAir (1) is compressed in a multi-stage intercooled compressor to about 4-6 bar. The air (2) is cooled using cooling water. The air can be further cooled by cold water which has been chilled by evaporative cooling, utilizing the waste nitrogen stream (8).

The compressed air is purified by removal of water vapour and CO2, which otherwise would solidify at low temperature and block the flow of air. The air purification consists of two adsorber vessels, and the air flow is periodically switched (1-6 hrs) between the two, allowing regeneration of adsorbed gases. The active materials in the adsorber are zeolites and alumina activated with alkali metals and ammonia compounds. The regeneration is done with heated nitrogen.

The air (3) is then cooled in the main heat exchanger and enters the bottom (4) of the HP column. At this point the air is at its dew point temperature or may be partially liquefied. In the HP column the vapour rising is flowing counter-current to down-flowing liquid, is enriched in nitrogen. The vapour reaching the HP condenser (5) is almost pure nitrogen. From the condenser liquid nitrogen is split into a reflux stream (6) for the HP columns, and a reflux stream (7) for the LP column.

14

ASU – liquid O2 pumpingFrom the bottom of the HP column, a mixture of liquid nitrogen and oxygen (60/40%) is fed into the LP column (8). From the top of the LP column high-purity gaseous nitrogen leaves (9) and from the bottom liquid oxygen is taken out (10). The nitrogen from the top of the LP column (9) is used to cool down the stream (7) ensuring there is down-flowing liquid from the top of the LP column. Stream (8) could also be cooled in the sub-cooler.

The liquid oxygen (10) is compressed in a pump to the pressure required by the downstream process using the oxygen. The pressurised oxygen is heated and evaporated in the main heat exchanger before leaving the process (11). Being pressurised, the evaporation of oxygen takes place at a temperature higher than would be the case with close to atmospheric pressure. In order to utilise the heat of evaporation of the oxygen for condensation of air, the main incoming air stream is split so that about 30% (12) is compressed to a pressure in the range 60-90 bar, which depends on the oxygen delivery pressure (11). This has to be done to fulfil the energy balance and ensure sufficient refrigeration duty is produced. The high-pressure air is after the main heat exchanger throttled and mixed with the main air stream going to the HP column (4). For the energy balance it is also necessary to extract a smaller fraction of the air stream (13) in the main heat exchanger and reduce the enthalpy of the stream by expanding it in a turbine.

15

ASU – liquid O2 pumpingThe power consumption for state-of-the-art large plants is in the range 210-250 kWh/tonne O2 at a delivery pressure slightly above atmospheric pressure.

The purity of the oxygen influences to some extent the energy consumption.Comparing 95% purity to 99.5%, there is a difference in energy consumption of about 20 kWh/tonne O2 or about 10%

The maximum load change for an ASU is typically 5 % per minute, which is also a realistic load change rate in an oxy-combustion power plant. Experience shows that for IGCC plants, the load change rate of 2% per minute is achievable. The start-up for an ASU after a shut down of less than 24 hours is approximately 2-3 hours, since the cold box is so well insulated.

The standard minimum load of an ASU is 50% but this value can go down to 30% if necessary. The limitation comes from the compressor design and operation. There is no problem for the distillation column to go down to 30% load. If high part-load flexibility is required, a two-train solution for the ASU can be used.

ASUs based on cryogenic distillation have a very high reliability of over 99% and an overall time availability of over 98%. Every 3-4 year the ASU has to be shut down for defrosting and cleaning for about a 10 day period.

16

ASU – gaseous O2 compression

Air

Main aircompressor

Oxygencompressor

Expander

HP Column

LP Column

Subcooler

Air pre-treatment

H2O CO2

Oxygen

Wastenitrogen

17

17

Oxygen production energy requirement

0.2

0.22

0.24

0.26

0.28

0.3

0.32

0.34

0.36

0.38

0 10 20 30 40 50 60 70 80 90 100

Delivery pressure [bar]

Wo

rk [

kW

h/k

g p

ure

O2]

500 tons/day

1000 tons/day2000 tons/day

3000 tons/day4000 tons/day

5000 tons/day

Up to 75 bara, the oxygen delivery temperature is 15 °C. Above 75 bara, the oxygen delivery temperature is calculated using a compressor with an isentropic efficiency of 80 % (compression from 75 bara & 15 °C to the delivery pressure). The energy requirement for the oxygen production and compression is still calculated with Equation (1).

Figure 1 Work requirement [kWh/kg pure O2] for oxygen production and compression (95 mol-%

O2) calculated with the diagram on the left-hand side of Error! Reference source not found. and Equation (Error! Reference source not found.). The unit for the mass flow rate in the figure is [tons O2/day].

18

18

Oxygen production energy requirementImpact on power plant efficiency

2 2

2

MJ for O production kg O×

kg O MJ fuel heating value

Oxygen production

0.2 0.25 KWh/kg O2

0.72 0.9 MJ/kg O2

Oxygen compression

0.01 0.05 KWh/kg O2

0.036 0.18 MJ/kg O2

0.066528 0.09504 MJ_O2/MJ_fuel

6.7 % 9.5 % delta_efficiency

Fuel energy (heating value)

50 MJ fuel/kg

Need for oxygen

0.088 kg O2/MJ fuel

88 kg O2/GJ fuel

19

Oxy-combustion – the principle

20

Oxy-combustion –External air separationusing an air separation plant

21

Oxy-combustion – the principle

Conversion system

Air SeparationUnit

O2

hydrocarbonC,H

CO2 to storage

H2O extraction

Flue gasCO2 + H2O

CO2 or H2O recycle

22

Oxy-combustion principlesRecirculation of gaseous CO2 – atmospheric cycle

Combustion

To CO2

compression & conditioning

OxygenCO2(g) + H2O(g)

Fuel

CO2(g)+ H2O(g)

H2O(l)

CWCooler

Fan

Preheater

Steam power cycle

CO2(g) + H2O(g)

23

Oxy-combustion CO2 capture – coalPulverised coal combustion – recycle of flue gas

24

Oxy-combustion CO2 capture – coalCirculating fluidised bed combustion

25

Oxy-combustion principlesRecirculation of gaseous CO2

26

Oxy-combustion principlesRecirculation of liquid H2O

27

Principle of the Clean Energy Systems cycle. The combustion of the fuel and oxygen is cooled by injection of liquid water, which is recycled in the process.

Gas orOil

* CH4, CO, H2, etc.

Recycle Water

Multi-stage Turbines

ElectricalGeneratorGas Generator IP LP

Con-den-ser

Steam/CO2 (~90/10 % vol)

Recov-Heat

ery

Air

Nitrogen

Fuel*

Oxygen

CrudeFuel

AirSeparation

Plant

FuelProcessing

Plant

Coal, RefineryResidues, or

Biomass

Excess Water

CarbonDioxide

Recovery

or Sequestration

CO2

EOR, ECBM,

DirectSales

HP

Reheater

Clean Energy Systems, Inc.

28

Combustor

Clean Energy Systems, Inc.Combustion

Chamber H2O 4.98 #/sec

Cooldown Chamber H2O

4.39 #/sec

Diluent Injector Feed Manifold

Turbine Simulator H2OCH4 Inlet

0.86#/sec

O2 Inlet3.46 #/sec

Option H2O Out

0.89 #/sec 1.06 #/sec 1.29 #/sec 1.15 #/sec

29

Combustor

Clean Energy Systems, Inc.

30

Oxy-combustion principlesRecirculation of liquid CO2

31

1-2: Intercooled staged compressor 2-3: Upper pressure cycle 3-4: HP Combustor chamber 4-5: HP Expander. 5-6: LP Combustion chamber. 6-7: LP Expander. 7-8: Internal regeneration. 8-1: Water cooler/separator.

The Regenerative Ericsson-like MATIANT Gas Cycle

127

30

127

30

130

30

142

607

1127

1300

707

306

300

200

400

600

800

1000

1200

1400

-40000 -30000 -20000 -10000 0 10000 20000 30000 40000 50000 60000

S (J/kmol.K)

T (

ºC)

3

2

7

6

5Fuel

110bar

Internal Regeneration

ASU O2

H2O + (dissolved CO2)

8

CO2 from combustion

40 bar

4

Recycled CO2

1

Fuel LHV=45 MJ/kg

Preheat=40 bar

Pupper=110bar

TiT=1300ºC

TET = 700 °C

η = 45%

700

32

Oxy-combustion principlesRecirculation of liquid H2O and gaseous CO2 – Graz cycle

33

Oxy-combustion demo plants

34Oxy-combustion coal 30 MWthermal

Schwarze Pumpe

Commissioning Sept 9, 2008

VattenfallGermany

35

36

Callide Oxyfuel Project, Australia

37

Oxy-combustion –Internal air separation

38

Membranes – O2 separationDense electrolytes and mixed conducting (ionic and

electronic) membranes for O2 or H2 separation

Principles for electrolytes (left) and ion transport membranes (right):

(a) OSOFC cell producing electrical power

(b) mixed conducting membrane for syngas production

(c) HSOFC cell producing electrical power

(d) mixed conducting membrane in N2 and heat production.

39

Membranes – O2 separationDense electrolytes and mixed conducting (ionic and

electronic) membranes for O2 or H2 separation

O2

Examples:- ZrO2 with 8-10% Y2O3

- Bi2O2

- Perovskites such as BaCeO3-d, SrCeO3-d

and BaZrO3-d

H2

Example: Perovskites such as BaCeO3-d, SrCeO3-d

and BaZrO3-d

40

Oxy-combustion - AZEP

Gas turbine process + steam turbine process

The GT combustor is replaced with a mixed conductive membrane reactor (MCM)

Separation of O2 from air by the membrane

Combustion of fuel without presence of N2

Heat exchange (combustion heat to depleted air)

Source: Sven Gunnar Sundkvist, Oct. 2003

41

SOFC basics

eOHOH

eCOOCO

2

2

22

2

22

22 482 OeO

222

224 3

HCOOHCO

HCOOHCH

Figure from Sulzer HEXIS.

Designed to run on methane

Overall anode reaction

Overall cathode reaction

42

Natural gas

Air

CO2,H2OSOFC unit

4

’After-burner’

Cathode side

Anode side

9

5

3 8 12

10

Depleted air6

11

13

1

Exit air

14

Air turbineCompressor

Flue gas turbine

Flue gas

Pre-reformer

2

7

Generator

Generator

DC/AC

Anode recycle

Solid Oxide Fuel Cell (SOFC)with CO2 capture

43Solid Oxide Fuel Cell (SOFC)

with CO2 captureNatural gas

Air

CO2,H2OSOFC unit

4

’After-burner’

Cathode side

Anode side

9

5

3 8 12

10

Depleted air6

11

13

1

Exit air

14

Air turbineCompressor

Flue gas turbine

Flue gas

Pre-reformer

2

7

Generator

Generator

DC/AC

Anode recycle

7Cathode exit

Anode exit

Second SOFC

8Anode inlet

Cathode inlet

Oxygen separation membrane reactor

22 2O4eO

Hydrogen separation membrane reactor

2O7

Retentate

Permeate8

Sweep

Feed 2

2 2O4eO

2Oe

7Permeate

Retentate8

Feed

Sweep

He

O2H4e4HO

2

2

e

4 2 2

2 2 2

22 2

3

2

CH H O CO H

CO H O H CO

H O H O e

4 2 2

2 2 2

22 2

3

2

CH H O CO H

CO H O H CO

H O H O e

4 2 2

2 2 2

2

3

2 2

CH H O CO H

CO H O H CO

H H e

Efficiency 65% (Natural gas)

44

SOFC afterburner for CO2 captureAnode and cathode stream needs be to kept separated

22 2O4eO

2O 2

2 2O4eO

2Oe

He

O2H4e4HO

2

2

e

4 2 2

2 2 2

22 2

3

2

CH H O CO H

CO H O H CO

H O H O e

4 2 2

2 2 2

22 2

3

2

CH H O CO H

CO H O H CO

H O H O e

4 2 2

2 2 2

2

3

2 2

CH H O CO H

CO H O H CO

H H e

45

Chemical Looping Combustion (CLC)

Metaloxidation

Metal oxidereduction

Metal Metal oxide

Air

FuelCO2 + H2O

C

T

TOxygen

depleted air 14% O2

Compressionand storage

Cooling and H2O

condensation

H2O

CO2

Reduction4 2 2

Oxidation2

CH ( ) 4MeO(s) CO ( ) 2H O(g) 4Me(s)

Me(s) 1/2 ( ) ( )

g g

O g MeO s

MeO=NiO supported on NiAl2O4

Other alternatives: Cu, Fe, Mg

46

)s(MeO)g(O2/1Me(s)

4Me(s)O(g)2H)g(CO4MeO(s))g(CHOxidation

2

22ductionRe

4

Air Reactor

Fuel Reactor

(Oxygen depleted air)CLC reactor

Steam

MethaneAir

CO2

Nitrogen

Nickel

Oxygen

Cyclone

47

CLC – Combined cycle

Air

Metal/metal oxide

Steam

Fuel (Natural Gas)

Compressor

Fuel Preheater

Ox

Air Turbine

Red

CO2-Turbine

S1

S2

S3

S6

S8

S9

CLC-Reactors

Cooling water

MeO

Me

Cooling air

(CO2 + H 2O)

G

CO2 rich exhaust

S4

S7

S10

S11

To CO2 dehydration and compression plant

Condensate/Water

Oxygen depleted air

HP

IP

Condenser

HRSG

Steam Turbine

Condensate Pump

S5

48

CLC – Reheat to avoid very hightemperatures

Entropy

Tem

pera

ture

No Reheat

Single Reheat

Reheat

TIT-1

TIT-2

TET-1

TET-2

Pexhaust

Pambient

Primary heat addition

Pin

Preheat

49

CLC – Reheat combined cycleCompressor

Fuel Preheater

Ox Ox

AT1 AT2

Red Red

CO2-TurbineS1

S2

S3

S5

S6

S9

S10

S12S13

S15

HP-CLC-Reactors LP-CLC-Reactors

MeO MeO

Me Me

Cooling air S13

G

S4 S7

S11

S16

(CO2 + H2O)

To CO2 dehydration andcompression plant

Reheat

Air

Metal/metal oxide

Steam

Fuel (Natural Gas)

CO2 rich exhaust

Condensate/Water

S8

S14

Condensate PumpS6

Oxygen depleted air

HP

IP

S17Condenser

HRSG

Steam Turbine

50

Coal-fired power cycles

45.4

40.838.437.8

43.142.539.1

48.9

0

5

10

15

20

25

30

35

40

45

50

55

Lignite-AIR

Lignite-OXYFUEL

Lignite-OTM

IGCC-Ref IGCC-Ref ASU IGCC-CA IGCC-CA ASU IGCC-OTM

Net

pla

nt

effi

cien

cy [

%]

Ligniteoxy-fuel cases

IGCC referencesno fullASU/GT integration

IGCC with CO2 capture

Lignitereference case

51

Natural gas-fired power cycles

48.6

43.147.7 48.9

50.0 52.0 53.0

45.342.9

0

5

10

15

20

25

30

35

40

45

50

55

60N

et e

ffic

ien

cy

[%

]

Oxy-fuel cycles CLC-cycles

52

Dilution of CO2 – Oxy-combustion

• Nitrogen and other non-CO2 gases originating from the fuel

• Impurities from air separation (argon, nitrogen)

• Oxygen excess in the combustion process

• In-leakage of air

53

Dilution of CO2 – Oxy-combustion

Pressure 1 atmCO2 partial pressure 0.6-0.8 atm

Oxy-combustioncoal

Ar; 1.9 %

SO2; 0.3 %H2O; 16.9 %

O2; 4.9 %

CO2; 62.5 %

N2; 13.5 %

Oxy-combustionnatural gas

N2; 3.2 %

CO2; 75.7 %

O2; 2.0 %

Ar; 4.8 %

H2O; 14.3 %

54

0.1

1

10

100

1000

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

Pre

ssu

re [b

ar]

Temperature [C]

LiquidSolid

Vapour

Sublimatio

n

Boiling/condensation

Melting/freezing

Critical point

Triple point

Sublimation point

Phase diagram CO2

5.18 bar-56.6 C

Post-combustion

Oxy-combustion

Pre-combustionsyngas

Transport & Storagecondition

55

Compression CO2Straight intercooled compression and H2O removal

56

Gas Technology Centre NTNU – SINTEFOlav Bolland

0.1

1

10

100

1000

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

Pre

ssu

re [b

ar]

Temperature [C]

LiquidSolid

Vapour

Sublimatio

n

Boiling/condensation

Melting/freezing

Critical point

Triple point

Sublimation point

5.18 bar-56.6 C

Transport & Storagecondition

Gas-phase separation

Cooling

Cooling

AbsorptionAdsorption

Oxy-combustionMembraneSorbents

57

Compression CO2

COMP_1

IC_1

COMP_2

IC_2

COMP_3

IC_3

FLASH_1

FLASH_2

FLASH_3

FLASH_4

WORK PRC

PUMP_4

DP

FEED C1_EXIT

FLASH_2_IN

C2_EXIT

FLASH_3_IN

C3_EXIT

FLASH_4_IN

C1_IN

DRAIN_1

C2_IN

DRAIN_2

C3_IN

DRAIN_3

PUMP4_IN

DRAIN_4

FINAL_L

Compressor NameWork (Actual) KW

COMP_152.7301

COMP_249.0688

COMP_348.1641

Stream NameStream Description

Phase

TemperaturePressure

Flowrate

Composition CO2 H2O

CBAR

KG-MOL/SEC

FEED

Mixed

30.0001.013

1.000

0.0100.990

DRAIN_1

Water

30.0001.013

0.990

0.0001.000

C1_IN

Vapor

30.0001.013

0.010

0.9580.042

C1_EXIT

Vapor

158.6784.346

0.010

0.9580.042

FLASH_2_IN

Mixed

22.0004.303

0.010

0.9580.042

DRAIN_2

Water

22.0004.303

0.000

0.0001.000

C2_IN

Vapor

22.0004.303

0.010

0.9940.006

C2_EXIT

Vapor

150.82218.646

0.010

0.9940.006

Calculator NameCalculator Description

Result 1Result 2Result 3Result 4Result 5

WORK

152.0957345.5935

n/an/an/a

Pump NameWork KW

PUMP_42.1327

Stream NameStream Description

Phase

TemperaturePressure

Flowrate

Composition CO2 H2O

CBAR

KG-MOL/SEC

FLASH_3_IN

Mixed

22.00018.460

0.010

0.9940.006

DRAIN_3

Water

22.00018.460

0.000

0.0001.000

C3_IN

Vapor

22.00018.460

0.010

0.9990.001

C3_EXIT

Vapor

163.05180.000

0.010

0.9990.001

FLASH_4_IN

Liquid

22.00079.200

0.010

0.9990.001

DRAIN_4

Unknown

n/an/a

n/a

n/an/a

PUMP4_IN

Liquid

22.00079.200

0.010

0.9990.001

FINAL_L

Liquid

27.512110.000

0.010

0.9990.001

58

Compression CO2Straight intercooled compression and H2O removal 

0.28

0.29

0.30

0.31

0.32

0.33

0.34

0.35

0.36

0.37

0.38

0.39

0.40

40 60 80 100 120 140 160 180 200 220

CO2 end pressure [bar]

com

pres

sion

wor

k [M

J/kg

CO

2 ]

0.0778

0.0828

0.0878

0.0928

0.0978

0.1028

0.1078

com

pres

sion

wor

k [k

Wh/

kg C

O2 ]

Peng-Robinson

Soave-Redlich-Kwong

Work for compression CO2 from 1.013 bar and 30 °C, saturated with water, to a given end pressure. Compression with 3 aftercooled (22 °C) compressors up to 80 bar, with equal pressure ratios, and a pump from 80 bar and up to the end pressure. Water is removed after each aftercooler, according to the water dew point. Compressor isentropic efficiencies for compressor 1 is 85%, for comp. 2 is 85%, for compr. 3 is 80%, and for the pump 75%. Aftercooler pressure drop is for each assumed 1%. Pressure loss for CO2 drying is not included.

59

Compression CO2Straight intercooled compression and H2O removal

Work for compression CO2 from a given inlet pressure and 30 °C to a fixed end pressure of 110 bar. The upper curve assumes that the CO2 feed is saturated with water at 30 °C, and the lower curve assumes pure CO2. Compression with 3 aftercooled (22 °C) compressors up to 80 bar, with equal pressure ratios, and a pump from 80 bar and up to the end pressure. Water is removed after each aftercooler, according to the water dew point. Compressor isentropic efficiencies for compressor 1 is 85%, for comp. 2 is 85%, for compr. 3 is 80%, and for the pump 75%. Aftercooler pressure drop is for each assumed 1%. Pressure loss for CO2 drying is not included. Use with caution at low pressures because the water vapour content may get very high and cause a very high compression work per kg of CO2.

 

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

0.01 0.1 1 10 100

CO2 starting pressure [bar]

com

pres

sion

wor

k [

MJ/

kg C

O2]

0.0000

0.0500

0.1000

0.1500

0.2000

0.2500

com

pre

ssio

n w

ork

[k

Wh

/kg

CO

2]

60 CO2 compression energy requirementImpact on power plant efficiency

CO2 from the fuel

Coal Natural gas

0.35 0.198 kg CO2/kWh

0.097222 0.055 kg CO2/MJ

CO2 compression

0.36 0.36 MJ/kg CO2

0.1 0.1 kWh/kg CO2

0.035 0.0198 MJ CO2/MJ fuel

3.5 % 2.0 % delta_efficiency2

2

kg CO MJ compression work×

MJ fuel heating value kg CO

61

Volatility

• Components more volatile then CO2

– N2, O2, NO, Ar

• Components less volatile then CO2

– SO2, H2S, COS, NO2

62

Sea-water washing (?)Other methods also availableDesulfurization may take pace before compression

Purification integrated with CO2

compression

63

Purification using flashes

Gas feed33 bar

-27 °C

Transport & storage

-54 °C

rich in CO2

rich in CO2

64

Purification using flash

Before entering into the separation plant, the exhaust gas is compressed up to 33 atm, water is first removed using a flash, and then it passes through the adsorption unit in order to avoid ice formation in the next step. The adopted system is made by two large heat exchangers (units E-1 and E-2) and two flashes (units F-1 and F-2). Exhaust gas (stream 1) is cooled down to -27 °C in unit E-1, separation occurs at -27 °C in unit F-1, the result is a liquid stream richer in CO2 (stream 18) and a vapour stream richer in volatiles (stream 3) with still a large amount of CO2. Vapour (stream 3) enters now in the second heat exchanger (unit E-2) where temperature sinks to -54 °C, the resulting liquid is separated in a second flash (unit F-2). The necessary refrigeration for plant operation is obtained by evaporating the purified liquid CO2 streams coming out from both flashes (streams 7 and 18). Purified CO2 (streams 12 and 17) now is vapour, and is compressed and liquefied with seawater (outlet conditions P = 110 atm T = 25 °C) (stream 16).

65

Oxy-combustion – outlook

• Coal: plants are being built!– Purification of CO2 before transport/storage

• Natural gas– oxy-combustion gas turbines less likely, though cost may

be rather low• Air separation

– Cryogenic distillation dominating for the foreseeable future– Ceramic mixed ion/electron conducting membranes –

progress?• Chemical Looping Combustion

– Power generation – Process heating

66

67

Oxy-combustion CO2 capture – coalPulverised coal combustion – recycle of flue gas

Oxygen

PF Boiler

Precipitator

Mill

Coal

Air Separation Unit

BFW

Direct Water Cooling

Water

Desiccant Drier

Inerts and Acid Gas Removal

Inerts SO2 NOx HCl

CO2Product

Dust

Steam Turbines

Power

Oxygen

PF BoilerPF Boiler

Precipitator

Mill

Coal

Air Separation Unit

BFW

Direct Water Cooling

Water

Desiccant Drier

Inerts and Acid Gas Removal

Inerts SO2 NOx HCl

CO2Product

Dust

Steam Turbines

Power

68

69

70

http://www.sciencedirect.com/science/article/pii/S0016236111004364

71

Compression CO2Straight intercooled compression and H2O removal

72

Compression CO2Intercooled compression and H2O removaland inert gas removal