tep03 co capture in power plants part 6 – pre …...1 1 bolland tep03 co2 capture in power plants...
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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)
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Pre-combustion – Reforming - 2
SR
Steam reforming
8
Pre-combustion – Reforming - 3
ATR
Auto-thermal reforming
9
Pre-combustion – Reforming - 4
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)
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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
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Pre-combustion – Reforming - 5
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.
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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
Pre-combustion – Reforming - 6
Oxygen-blown partial oxidation of methane for different steam-to-carbon ratios and pressures
4 2 22CH xO CO H
14
Pre-combustion – Reforming - 7
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
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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
Pre-combustion – Gasification - 2
Unconverted solid CCarbon conversion = 1 -
Carbon in coal feed
Chemical energy in syngasCold gas efficiency =
Chemical energy in coal
17
Pre-combustion – Gasification - 3
Entrained Flow
FluidisedBed
Coal Flow Direction Gas Flow Direction
Moving/fixed Bed
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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
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Pre-combustion – Gasification - 5Pressurized waterinlet
Pressurized wateroutlet
Fuel Oxygen, steam
Cooling screen
Quenchwater
Granulated slag
Gas outlet
Cooling jacket
Burner
Siemens SFG gasifier
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Pre-combustion – Gasification - 6
BGL gasifier
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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
Operating conditions: 185-275 ºC
Sulfur content in feed gas < 0.1 ppmv
Sour shift catalysts
Active component: Sulfided Co and Mo (CoMoS)
Operating conditions: 250-500 ºC
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