Pre-combustion – the method

TEP03
CO2 capture in power plants
Part 6 – Pre-combustion CO2
capture
Olav Bolland
Professor
Norwegian University of Science and Technology
Department of Energy and Process Engineering
Sept 2013
1
1
Bolland
2
Pre-combustion – the method
N₂/O₂
Coal, Oil, Natural Gas, Biomass
Post-combustion
Power
plant
CO₂
CO₂
separation
CO₂
Gasification
CO/H₂
H₂
Shift
Reforming
CO/H₂
H₂ Power
CO₂
plant
CO₂ separation
Pre-combustion
Power
plant
CO₂
Oxy-combustion
O₂
Air
Air separation
N₂
N₂/O₂
CO₂ compression
& conditioning
3
Pre-combustion - principle
Split the CxHy-molecules into H2 and CO2
Transfer heating value from CxHy to H2
Separate CO2 from H2
Coal
Oil
Natural
gas
H2
CO
H2
CO2
Gasifier
Reformer
CO2
capture
Shift
Oxidizer
H2O
O2
H2
to
combustion
CO2
4
Pre-combustion - steps
Natural
gas
Hydrogenator
Desulfurizer
Coal Grinding &
slurrying
Prereformer
Gasifier
Reformer
Syngas
cooling
Particle
removal
Syngas
cooling
Water-gas
shift
Sour watergas shift
H2-rich
CO2 gas
removal
CO2
H2-rich
H2S/CO2 gas
removal
H 2S
CO2
Claus
process
S
Coal Grinding &
slurrying
Gasifier
Syngas
cooling
Particle
removal
H 2S
removal
H 2S
Claus
process
S
Sweet watergas shift
H2-rich
CO2 gas
removal
CO2
5
Pre-combustion – pre-reforming
Cm H n  H 2O  CH 4  CO2 / CO
• 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
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
Pre-combustion – Reforming - 2
SR
Steam reforming
8
Pre-combustion – Reforming - 3
ATR
Auto-thermal reforming
9
Pre-combustion – Reforming - 4
CH 4  H 2O  CO  3H 2
H  205.9 [kJ/mol]
CO  H 2O  H 2  CO2
H  41.2 [kJ/mol]
CH 4  CO2  2CO  2 H 2
CH 4  1 O2  CO  2 H 2
2
(CH 4  3 O2  CO  2 H 2 O
2
H  247 [kJ/mol]
H  35.9 [kJ/mol]
H  519.6 [kJ/mol])
Formation of coke
CH 4  C  2 H 2
H  74.6 [kJ/mol]
2CO  C  CO2
H  172.5 [kJ/mol]
Steam-to-carbon ratio (based on moles) or S/C-ratio.
Typical values in the range 1.3-3.0.
10
Natural gas steam reforming
= decomposition of methane by steam, to
produce synthesis gas (CO+H2)
CH 4  H 2O  CO  3H 2
(H 298  206 kJ mol -1 )
CO  H 2O  CO2  H 2
(H 298  -41 kJ mol -1 )
Heat added externally
Q
CH4, H2O
feed gas
prereformed
and
desulphurised
Steam reformer
reactor
Typical
pressure 30-40 bar
temp. 900-1000 ºC
Syngas
(H2, CO, H2O, CO2, CH4)
11
Natural gas auto-thermal reforming
CH 4  1 O2  CO  2 H 2
2
CH 4  H 2O  CO  3H 2
(H 298  -36 kJ mol -1 )
(H 298  206 kJ mol -1 )
CO  H 2O  CO2  H 2
(H 298  -41 kJ mol-1 )
Auto-termal reformer
reactor
O2
CH4, H2O
feed gas
Syngas
(H2, CO, H2O, CO2, CH4)
Typical
pressure 30-40 bar
temp. 900-1000 ºC
prereformed
and
desulphurised
12
Pre-combustion – Reforming - 5
100 %
Steam/C-ratio=1,
Steam/C-ratio=2,
Steam/C-ratio=3,
Steam/C-ratio=2,
Steam/C-ratio=3,
Steam/C-ratio=2,
Steam/C-ratio=3,
90 %
80 %
Unconverted methane ratio [%]
70 %
P=1 bar
P=1 bar
P=1 bar
P=15 bar
P=15 bar
P=30 bar
P=30 bar
60 %
Steam reforming of methane
for different steam-to-carbon
ratios and pressures.
50 %
40 %
30 %
20 %
10 %
0%
500
550
600
650
700
750
800
850
900
950 1000
Reformer equilibrium temperature [C]
1050
1100
1150
1200
13
Pre-combustion – Reforming - 6
45 %
Steam/C-ratio=0, P=1 bar
Steam/C-ratio=1.6, P=1 bar
Steam/C-ratio=0, P=15 bar
Steam/C-ratio=1.6, P=15 bar
Steam/C-ratio=0, P=30 bar
Steam/C-ratio=1.6, P=30 bar
40 %
Unconverted methane ratio [%]
35 %
30 %
25 %
Oxygen-blown partial oxidation
of methane for different steamto-carbon ratios and pressures
20 %
15 %
10 %
5%
0%
0.35
0.4
0.45
0.5
0.55
0.6
0.65
O2/CH4 molar ratio [-]
0.7
0.75
0.8
0.85
CH 4  xO2  CO  2 H 2
14
Pre-combustion – Reforming - 7
SMR
Combined
reforming
ATR
POX
0.0
1.0
2.0
3.0
4.0
H2/CO ratio
Achievable H2/CO ratios of reforming technologies.
The values within an interval depend mainly on
steam-to-carbon ratio and reforming temperature.
5.0
15
Pre-combustion – Gasification - 1
Involving carbon
C  2 H 2  CH 4
H  74.6 [kJ/mol]
C  CO2  2CO
H  172.5 [kJ/mol]
C  H 2O( g )  CO  H 2
C  1 O2  CO
2
Involving oxygen
CO  1 O2  CO2
2
H 2  1 O2  H 2O( g )
2
H =131.3 [kJ/mol]
H  110.5 [kJ/mol]
H  283.0 [kJ/mol]
H  241.8 [kJ/mol]
Steam-to-carbon ratio (based on moles) or S/C-ratio.
Typical values in the range 1.3-3.0.
16
Pre-combustion – Gasification - 2
Carbon conversion = 1 -
Cold gas efficiency =
Unconverted solid C
Carbon in coal feed
Chemical energy in syngas
Chemical energy in coal
17
Pre-combustion – Gasification - 3
Entrained
Flow
Coal Flow Direction
Fluidised
Bed
Moving/fixed
Bed
Gas Flow Direction
18
Pre-combustion – Gasification - 4
Flow Regime
Moving/Fixed Bed
Fluidized Bed
Entrained Flow
Combustion analogy
grate fired combustors
fluidized bed combustors
pulverized coal combustors
Fuel Types
solids only
solids only
solids or liquids
Fuel Size
5 - 50 mm
0.5 - 10 mm
< 500 m
Residence time
15 - 30 minutes
5 - 50 seconds
1 - 10 seconds
Oxidant
air- or oxygen-blown
air- or oxygen-blown
almost always oxygen-blown
Gas Outlet Temperature
400 - 600 °C
700 – 1000 °C
900 – 1600 °C
Pressure
10-35 bar
10-25 bar
25-80 bar
Ash Handling
slagging and non-slagging
non-slagging
always slagging
Acceptability of fines
Limited
Good
Unlimited
GE, Shell, ConocoPhillips
Sasol-Lurgi dry-ash,
HTW, KRW
Commercial Examples
E-Gas, Siemens
BGL (slagging)
Bed temperature below ash
Moving beds are
Not preferred for high-ash
fusion point to prevent
mechanically stirred,
fuels due to energy penalty
agglomeration
fixed beds are not
of ash-melting
Preferred for high-ash
Gas and solid flows are
Unsuitable for fuels that are
Comments
always countercurrent in feedstocks and waste fuels
hard to atomize or pulverize
Low carbon conversion
moving bed gasifiers
Pure syngas,
Some methane and tars in
Methane, tars and oils
high carbon conversion
syngas
present in syngas
19
Pre-combustion – Gasification - 5
Fuel
Pressurized water
inlet
Oxygen, steam
Pressurized water
outlet
Burner
Cooling screen
Siemens SFG
gasifier
Cooling jacket
Quench
water
Gas outlet
Granulated slag
20
Pre-combustion – Gasification - 6
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
Water-gas shift:
Fixed-bed reactor with catalyst, 185-500 C
100
Temperature=200,
Temperature=200,
Temperature=200,
Temperature=200,
Temperature=400,
Temperature=400,
90
H2/CO ratio at WGS exit [-]
80
Steam/CO-ratio=1
Steam/CO-ratio=2
Steam/CO-ratio=3
Steam/CO-ratio=4
Steam/CO-ratio=2
Steam/CO-ratio=4
70
CO  H 2O  H 2  CO2
60
H  41.2 [kJ/mol]
50
40
30
20
10
0
1.0
1.5
2.0
2.5
3.0
3.5
H2/CO ratio at WGS inlet [-]
24
Pre-combustion – WGS -2
WGS 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
4.0
4.5
5.0
25
Pre-combustion – CO2 capture
CO; 2.2 %
CO; 0.5 %
Pre-combustion
natural gas,
air-blown reforming
N2; 34.6 %
N2; 2.5 %
Pre-combustion IGCC
CO2; 38.3 %
H2; 46.8 %
H2; 56.1 %
Ar; 0.5 %
H2O; 0.1 %
CH4; 0.2 %
SO2;
CO2; 17.4 %
Ar; 0.4 %
CH4; 0.1 %
Pressure  20-70 bar
CO2 partial pressure 3.5-27 bar
26
Pre-combustion – CO2 capture
CO2 separation
from syngas:
Selexol,
Rectisol, Purisol,
(MDEA) are
most commonly
used
H2O; 0.2 %
27
Pre-combustion – CO2 capture
Selexol
28
Pre-combustion –
29
Pre-combustion – IGCC without CO
2
Quench
water
Recovered
heat
Particulate
removal
Quench/
heat
recovery
capture
Sulfur
removal
H2 S
Raw
syngas
Coal feed
Gasifier
O2
Air
Separation
Unit
Hydrogen-rich gas
N2
Recovered heat
HRSG
Compressed air
GT
ST
Air
Generator
30
Pre-combustion – IGCC without CO
2
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 constant
efficiency
Lines of constant
N
N
T
 RT
Reduced flow rate
 T
m
p
 T
m
p
R

34
Wobbe index
LHV
Wobbe index 

 gas
 air
LHV
MW gas Tair
MWair Tgas
• 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
35
50
Wobbe index for
natural gas
45
100 %
40
90 %
80 %
35
Wobbe index,
Wobbe index,
Wobbe index,
Wobbe index,
Wobbe index,
30
25
20
H2 diluted with H2O
H2 diluted with N2
H2 diluted with CO
H2 diluted with CO2
H2 diluted with CH4
70 %
Wobbe index typical for IGCC-processes,
max CO2 capture, no dilution
60 %
50 %
40 %
15
30 %
10
Wobbe index typical for
IGCC-processes, no CO 2 capture
CO2
20 %
5
10 %
0
0%
0
10
20
30
40
50
60
70
80
90
100
Hydrogen
(H
)
molar
percentage
in
fuel
[%]
2
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
Relative to methane CH4
Wobbe index based on Lower Heating Value
[MJ/Sm3]
H2-rich fuel in GT: NOX, Wobbe-index
37
NOX emissions for H2-rich fuel
NOx @15% O2, ppmvd
1000
Tests in a 6FA IGCC Multi - Nozzle Combustor
Lesson :
With a Target
Steam/Fuel Ratio of
0.13 a NOx level of 10
ppm. can be achieved
without special
measures
100
Primary-Nominal
46% H2/13% H20/Bal.N2
10
56-60%H2/Bal. N2
73-77% H2/Bal.N2
85-90%H2/Bal.N2
1
0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
Steam/Fuel Ratio
Source : “HydroPower - Emission Free Gas to Power”, Sigurd Andenæs, SPE Applied
Technology Workshop Gas to Power, Trinidad, 12 - 13 July 2001
See also Todd and Battista, 2000
38
Hydrogen Combustion in Gas Turbines
From Norm Schilling, GE
39
Pre-combustion – Natural gas
Steam
NG
NG
Reformer
Steam
Reformer
Hydrogen-rich fuel
to power plant
CO2
CO2 capture
(amine, Selexol)
WGS
Auto-Thermal
oxygen-blown
Reformer
NG
Steam
High-purity H2 for
other purposes
such as fuel cells
PSA
Auto-Thermal
air-blown
Reformer
NG
Steam
Steam
Air
Air
ASU
Nitrogen
CO2
NG
Reforming
WGS
CO2 capture
NG
Combined
Cycle
H2
Exhaust
steam, water,
air, nitrogen
heat
40
Pre-combustion – Gas Turbine Combined
Cycle with Auto-Thermal Reforming
CO2 23
22
CO2 capture
21a
21b
20
ABS 19
39
REFORMER
Reforming/
Shift
ATR
11
37
H1
12
13
HTS
H2
41
14
H3
WR
FC
15
LTS
16
H5
18
17
H4
40
21c
7
9
Gas turbine
T
COMP
GT
42
G
AIR/EXHAUST
STEAM/WATER
NATURAL GAS
SYNGAS
H2-RICH FUEL
36
8
24
10
25 EXHAUST
6
Steam cycle
SF
PRE
4
5
HRSG
3
21a
MIX
NATURAL GAS 1
34
preheating steam generation
26
2
33
31
28 27 29
ST
30
T = TURBINE, COMP = COMPRESSOR
SF = SUPPLEMENTARY FIRING, HRSG = HEAT RECOVERY STEAM GENERATOR
ST = STEAM TURBINE, COND = STEAM CONDENSER, PRE = PREREFORMER
ATR = AUTO-THERMAL REFORMER, HTS = HIGH TEMPERATURE SHIFT-REACTOR,
LTS = LOW TEMPERATURE SHIFT-REACTOR, WR = WATER REMOVAL,
ABS = CO2 ABSORBER, FC = FUEL COMPRESSOR
COND 32
41
Pre-combustion – Gas Turbine Combined
Cycle with Auto-Thermal Reforming
42
Pre-combustion – sorption-enhanced WGS
Fuel
Gasifier
Reformer
H2
CO
H2O
Water
gas-shift
(WGS)
H2
CO2
CO2
capture
H2
CO2
Fuel
Gasifier
Reformer
H2
CO
H2O
CO  H 2O  H 2  CO2
WGS +
gas separation
H2
CO2
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.
43
Pre-combustion – sorption-enhanced reforming
Fuel
H2
CO
H 2O
Gasifier
Reformer
H2
CO2
Water
gas-shift
(WGS)
CO2
capture
H2
CO2
O2 Q
Fuel+H2O
Membrane
O2 Q
CH 4  H 2O  CO  3H 2
C  H 2O( g )  CO  H 2
CO  H 2O  H 2  CO2
C  2H 2  CH 4
CO2
CO  H2O  H2  CO2 C  CO2  2CO
Q
Sweep gas +H2
O2 Q
H2
Q
H2 Q
H2
Sweep gas, e.g.
H2O, N2, air
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.