tep03 oxy-combustion co2 capture - iv - ntnu · the lp column (8). from the top of the lp column...
TRANSCRIPT
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