tep03 co capture in power plants part 6 – pre …...1 1 bolland tep03 co2 capture in power plants...

1

1

Bolland

TEP03 CO2 capture in power plants

Part 6 – Pre-combustion CO2capture

Olav BollandProfessor

Norwegian University of Science and TechnologyDepartment of Energy and Process Engineering

Sept 2013

2

Pre-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

Pre-combustion - principle

GasifierReformer

Coal

Shift

H2

COH2

CO2

CO2

capture

H2

CO2

Split the CxHy-molecules into H2 and CO2

Transfer heating value from CxHy to H2

Separate CO2 from H2

to combustion

OxidizerH2OO2

Oil

Naturalgas

4

Pre-combustion - stepsReformer

H2-richgasPre-

reformerHydrogenatorDesulfurizer

Syngascooling

Water-gasshift

CO2

removal

Naturalgas

CO2

H2-richgas

GasifierSyngascooling

Sour water-gas shift

H2S/CO2

removal

Coal

CO2H2S

H2-richgas

GasifierSyngascooling

Sweet water-gas shift

CO2

removal

CO2

H2Sremoval

H2S

Particleremoval

Particleremoval

Clausprocess

S

Clausprocess

S

Grinding &slurrying

Coal Grinding &slurrying

5

Pre-combustion – pre-reforming

• It allows reducing the steam-to-carbon ratio in the main reformer and may contribute to less energy use in the main reformer

• Pre-reformer can act as a “sulfur guard” by removing all sulfur to protect the main reformer catalyst and so increase its life time. The pre-reformer catalyst is Nickel based on either a magnesium oxide or magnesium alumina, of which the latter at low temperatures favours the chemisorption of sulfur.

• Increased fuel feed flexibility, as the pre-reformer smoothes out variations in the feed composition

2 4 2 /m nC H H O CH CO CO

6

Pre-combustion – Reforming - 1

• Reaction with steam - steam reforming – heat is supplied from outside the reformer

• Reaction with oxygen - partial oxidation – heat is generated within the reformer– Partial oxidation with no catalyst - POX

– Autothermal reforming (ATR) – combination of POX and SR

– Catalytic Partial Oxidation (CPO)

7


SR

Steam reforming

8


ATR

Auto-thermal reforming

9


Formation of coke

4 2 23 205.9 [kJ/mol]CH H O CO H H

2 2 2 41.2 [kJ/mol]CO H O H CO H

4 2 22 2 247 [kJ/mol]CH CO CO H H

4 2 21 2 35.9 [kJ/mol]2CH O CO H H

4 2 23( 2 O 519.6 [kJ/mol])2CH O CO H H

4 22 74.6 [kJ/mol]CH C H H

22 172.5 [kJ/mol]CO C CO H

Steam-to-carbon ratio (based on moles) or S/C-ratio.

Typical values in the range 1.3-3.0.

10Natural gas steam reforming= decomposition of methane by steam, to produce synthesis gas (CO+H2)

-14 2 2 2983 ( H 206 kJ mol )CH H O CO H

-12 2 2 298 ( H -41 kJ mol )CO H O CO H

CH4, H2O Syngas

Q

Heat added externally

feed gasprereformed and desulphurised

Steam reformerreactor

Typicalpressure 30-40 bartemp. 900-1000 ºC

(H2, CO, H2O, CO2, CH4)

11

Natural gas auto-thermal reforming

-14 2 2 2983 ( H 206 kJ mol )CH H O CO H

-12 2 2 298 ( H -41 kJ mol )CO H O CO H

CH4, H2OSyngas

feed gasprereformed and desulphurised

Auto-termal reformerreactor

Typicalpressure 30-40 bartemp. 900-1000 ºC

(H2, CO, H2O, CO2, CH4)

-14 2 2 298

1 2 ( H -36 kJ mol )2CH O CO H

O2

12


0 %

10 %

20 %

30 %

40 %

50 %

60 %

70 %

80 %

90 %

100 %

500 550 600 650 700 750 800 850 900 950 1000 1050 1100 1150 1200

Unc

onve

rted

met

hane

rati

o [%

]

Reformer equilibrium temperature [C]

Steam/C-ratio=1, P=1 barSteam/C-ratio=2, P=1 barSteam/C-ratio=3, P=1 barSteam/C-ratio=2, P=15 barSteam/C-ratio=3, P=15 barSteam/C-ratio=2, P=30 barSteam/C-ratio=3, P=30 bar

Steam reforming of methane for different steam-to-carbon ratios and pressures.

13

0 %

5 %

10 %

15 %

20 %

25 %

30 %

35 %

40 %

45 %

0.35 0.4 0.45 0.5 0.55 0.6 0.65 0.7 0.75 0.8 0.85

Unc

onve

rted

met

hane

rati

o [%

]

O2/CH4 molar ratio [-]

Steam/C-ratio=0, P=1 barSteam/C-ratio=1.6, P=1 barSteam/C-ratio=0, P=15 barSteam/C-ratio=1.6, P=15 barSteam/C-ratio=0, P=30 barSteam/C-ratio=1.6, P=30 bar


Oxygen-blown partial oxidation of methane for different steam-to-carbon ratios and pressures

4 2 22CH xO CO H

14


Achievable H2/CO ratios of reforming technologies. The values within an interval depend mainly on steam-to-carbon ratio and reforming temperature.

H2/CO ratio

Combinedreforming

SMR

ATR

POX

0.0 1.0 2.0 3.0 4.0 5.0

15

Pre-combustion – Gasification - 1

Involving carbon

Steam-to-carbon ratio (based on moles) or S/C-ratio.

Typical values in the range 1.3-3.0.

2 42 74.6 [kJ/mol]C H CH H

2 2 172.5 [kJ/mol]C CO CO H

21 110.5 [kJ/mol]2C O CO H

2 ( ) 2 =131.3 [kJ/mol]gC H O CO H H

2 21 283.0 [kJ/mol]2CO O CO H

2 2 2 ( )1 O 241.8 [kJ/mol]2 gH O H H

Involving oxygen

16


Unconverted solid CCarbon conversion = 1 -

Carbon in coal feed

Chemical energy in syngasCold gas efficiency =

Chemical energy in coal

17


Entrained Flow

FluidisedBed

Coal Flow Direction Gas Flow Direction

Moving/fixed Bed

18

Pre-combustion – Gasification - 4 Flow Regime Moving/Fixed Bed Fluidized Bed Entrained Flow

Combustion analogy grate fired combustors fluidized bed combustors pulverized coal combustorsFuel Types solids only solids only solids or liquidsFuel Size 5 - 50 mm 0.5 - 10 mm < 500 m

Residence time 15 - 30 minutes 5 - 50 seconds 1 - 10 secondsOxidant air- or oxygen-blown air- or oxygen-blown almost always oxygen-blown

Gas Outlet Temperature 400 - 600 °C 700 – 1000 °C 900 – 1600 °CPressure 10-35 bar 10-25 bar 25-80 bar

Ash Handling slagging and non-slagging non-slagging always slaggingAcceptability of fines Limited Good Unlimited

Commercial ExamplesSasol-Lurgi dry-ash,

BGL (slagging)HTW, KRW

GE, Shell, ConocoPhillipsE-Gas, Siemens

Comments

Moving beds aremechanically stirred,

fixed beds are notGas and solid flows arealways countercurrent in

moving bed gasifiersMethane, tars and oils

present in syngas

Bed temperature below ashfusion point to prevent

agglomerationPreferred for high-ash

feedstocks and waste fuelsLow carbon conversion

Some methane and tars in syngas

Not preferred for high-ashfuels due to energy penalty

of ash-meltingUnsuitable for fuels that arehard to atomize or pulverize

Pure syngas, high carbon conversion

19

Pre-combustion – Gasification - 5Pressurized waterinlet

Pressurized wateroutlet

Fuel Oxygen, steam

Cooling screen

Quenchwater

Granulated slag

Gas outlet

Cooling jacket

Burner

Siemens SFG gasifier

20


BGL gasifier

21

Pre-combustion – Syngas cooling

• Radiant syngas cooling

• Water quench

• Gas recycle quench

• Chemical quench

22

Pre-combustion – Syngas cooling

High-Temperature

Winkler

Siemens

23

Pre-combustion – WGS -1

0

10

20

30

40

50

60

70

80

90

100

1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0

H2/

CO

rati

o at

WG

S e

xit [

-]

H2/CO ratio at WGS inlet [-]

Temperature=200, Steam/CO-ratio=1 Temperature=200, Steam/CO-ratio=2 Temperature=200, Steam/CO-ratio=3 Temperature=200, Steam/CO-ratio=4 Temperature=400, Steam/CO-ratio=2 Temperature=400, Steam/CO-ratio=4

Water-gas shift:

Fixed-bed reactor with catalyst, 185-500 C

2 2 2 41.2 [kJ/mol]CO H O H CO H

24

Pre-combustion – WGS -2WGS catalysts are

High-temperature shift catalyst

Active component: Fe3O4 with Cr2O3 as stabiliser

Operating conditions: 350-500 ºC

Sulfur content in feed gas < 100 ppmv

Low-temperature shift catalysts

Active component: Cu supported by ZnO and Al2O3


Sulfur content in feed gas < 0.1 ppmv

Sour shift catalysts

Active component: Sulfided Co and Mo (CoMoS)


Sulfur content in feed gas > 300 ppmv

25

Pre-combustion – CO2 capture

Pressure 20-70 barCO2 partial pressure 3.5-27 bar

N2; 34.6 %

CO2; 17.4 %

Ar; 0.4 %

H2O; 0.1 %

SO2; CH4; 0.2 %

H2; 46.8 %

CO; 0.5 %

Pre-combustionnatural gas,

air-blown reforming

N2; 2.5 %

CO2; 38.3 %

Ar; 0.5 %

H2O; 0.2 %CH4; 0.1 %

H2; 56.1 %

CO; 2.2 %

Pre-combustion -IGCC

26

Pre-combustion – CO2 capture

CO2 separation from syngas:

Selexol, Rectisol, Purisol, (MDEA) are most commonly used

27 Pre-combustion – CO2 captureSelexol

28

Pre-combustion –

29

Pre-combustion – IGCC without CO2 capture

ST

Generator

HRSG

Air

GT

Gasifier

AirSeparation

UnitCompressed air

N2

O2

Quench/ heat

recovery

Particulate removal

Sulfur removal

Coal feed

Raw syngas

Hydrogen-rich gas

Quench water

Recovered heat

H2S

Recovered heat

30

Pre-combustion – IGCC without CO2 capture

31

Hydrogen Combustion in Gas Turbines

• Existing fuel distribution system and fuel nozzles not dimensioned for a fuel with a low volumetric heating value – high velocities, high pressure drop, choking of the fuel flow– Hydrogen-rich fuels require a significant design modification of fuel

injection systems

• High formation of NOX because of very high flame temperatures locally in the flame

• Location of the flame inside the combustor and an increase in the H2O concentration on the product side may cause a too high heat flux on combustor walls or on fuel nozzles

32

Consequences – Dilution of H2 (N2, H2O)

• Maximum temperature at exhaust or power turbine inlet

• Maximum torque or power output to load

• Mechanically limited compressor discharge pressure

• Mechanically limited compressor discharge temperature

• Mechanical overspeeding of a free compressor on a multi-shaft machine

• Aerodynamically limited maximum compressor discharge pressure, leading to surge

• Aerodynamic overspeeding of a free compressor on a two-shaft machine, leading to choke

33

Consequences – Dilution of H2 (N2, H2O)

Lines of constantefficiency

Reduced flow rate m T

p

Lines of constant N

T

N

RT

m T R

p

34

Wobbe index

• The Wobbe index is used to compare the combustion energy output of different composition fuel gases in a burner

• Main indicator of the interchangeability of various fuels

• If two fuels have similar Wobbe index then it is likely that a given burner can change between the two fuels and operate in a similar manner

• Wobbe index does not relate flame temperature, heat transfer coefficients or temperature gradients

Wobbe index

gas gas air

air air gas

LHV LHV

MW T

MW T

35

0 %

10 %

20 %

30 %

40 %

50 %

60 %

70 %

80 %

90 %

100 %

0

5

10

15

20

25

30

35

40

45

50

0 10 20 30 40 50 60 70 80 90 100

Rel

ativ

e to

met

hane

CH

4

Wob

be in

dex

base

d on

Low

er H

eati

ng V

alue

[MJ/

Sm

3 ]

Hydrogen (H2) molar percentage in fuel [%]

Wobbe index, H2 diluted with H2OWobbe index, H2 diluted with N2Wobbe index, H2 diluted with COWobbe index, H2 diluted with CO2Wobbe index, H2 diluted with CH4

Wobbe index typical for IGCC-processes, max CO2 capture, no dilution

Wobbe index typical forIGCC-processes, no CO2 capture

Wobbe index fornatural gas

CO2

H2-rich fuel in GT: NOX, Wobbe-index

Wobbe index for mixtures of hydrogen with methane (CH4), nitrogen (N2), steam (H2O), carbon monoxide (CO) and CO2. The temperatures of the air and fuel are both set to 15 C for the calculation of the Wobbe index

36

NOx formation in GT combustion

Relation between NOX emission and stoichiometric flame temperature, progressively reduced by steam dilution, for gas turbine diffusive combustion at 12–16 bar with different fuels. Nitrogen is the balance gas for 56% and 95% hydrogen

37

Source : “HydroPower - Emission Free Gas to Power”, Sigurd Andenæs, SPE Applied Technology Workshop Gas to Power, Trinidad, 12 - 13 July 2001See also Todd and Battista, 2000

NOX emissions for H2-rich fuel

1

10

100

1000

0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0

Steam/Fuel Ratio

NO

x @

15%

O2,

ppm

vd

Primary-Nominal 46% H2/13% H20/Bal.N2

56-60%H2/Bal. N2

73-77% H2/Bal.N2

85-90%H2/Bal.N2

Lesson :

With a Target Steam/Fuel Ratio of 0.13 a NOx level of 10 ppm. can be achieved without special measures

Tests in a 6FA IGCC Multi - Nozzle Combustor

38 Hydrogen Combustion in Gas TurbinesFrom Norm Schilling, GE

39

Pre-combustion – Natural gas

PSACO2 capture

(amine, Selexol)WGSReformerNG

CO2

High-purity H2 for other purposes such as fuel cells

Hydrogen-rich fuelto power plant

Steam

SteamReformer

NG

Steam

ASUAir

Auto-Thermaloxygen-blown

Reformer

NG

Nitrogen

Steam Steam

Air

Auto-Thermalair-blownReformer

NG

ReformingWGS

CO2 capture

NG

CO2

steam, water,air, nitrogen

heat

CombinedCycle

NG

ExhaustH2

40

HRSG

ABS WR

LTSHTSATR

PRE

COND

ST

COMPT

FC

26 292728

25

3433

31

30

3

1

2

32

54

24

9 7

8

6

36

42

11 15141312

41

16 17

18

40

10

21c

21b

21a

21a

20 19

22 23

3739

steam generationpre-

heating

G

H1

H5

H4

H3H2

CO2

EXHAUST

MIX

GT

SF

NATURAL GAS

AIR/EXHAUSTSTEAM/WATERNATURAL GASSYNGASH2-RICH FUEL

T = TURBINE, COMP = COMPRESSORSF = SUPPLEMENTARY FIRING, HRSG = HEAT RECOVERY STEAM GENERATORST = STEAM TURBINE, COND = STEAM CONDENSER, PRE = PREREFORMERATR = AUTO-THERMAL REFORMER, HTS = HIGH TEMPERATURE SHIFT-REACTOR,LTS = LOW TEMPERATURE SHIFT-REACTOR, WR = WATER REMOVAL,ABS = CO2 ABSORBER, FC = FUEL COMPRESSOR

REFORMER

CO2 capture

Reforming/Shift

Gas turbine

Steam cycle

Pre-combustion – Gas Turbine Combined Cycle with Auto-Thermal Reforming

41

Pre-combustion – Gas Turbine Combined Cycle with Auto-Thermal Reforming

42

Pre-combustion – sorption-enhanced WGS

Integration of water gas-shift and CO2 capture processes. By removing continuously CO2 or hydrogen from the reactor, the equilibrium is shifted to the product side. The CO2 or hydrogen is separated using a membrane integrated with the catalyst in the reactor.

GasifierReformer

Watergas-shift(WGS)

H2

COH2O

H2

CO2

CO2

capture

H2

CO2

Fuel

GasifierReformer

WGS +gas separation

H2

CO2

Fuel2 2 2CO H O H CO

H2

COH2O

43

Pre-combustion – sorption-enhanced reforming

Integration of the reforming/gasification, water gas-shift and CO2 capture processes. By removing continuously CO2 or hydrogen from the reactor, the equilibrium is shifted to the product side. The hydrogen (or CO2) may be separated using a membrane. Heat may be transferred to the reactor or heat may be generated in the reactor by supplying oxygen to it.

GasifierReformer

Watergas-shift(WGS)

H2

COH2O

H2

CO2

CO2

capture

H2

CO2

Fuel

H2

Fuel+H2O4 2 2

2 2 2

3CH H O CO H

CO H O H CO

2 ( ) 2

2 4

2

2

2

gC H O CO H

C H CH

C CO CO

2 2 2CO H O H CO

Sweep gas, e.g. H2O, N2, airSweep gas +H2

H2 H2

Q Q Q

CO2

O2 O2 O2

MembraneQQ Q

tep03 co capture in power plants part 6 – pre …...1 1 bolland tep03 co2 capture in power plants...

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