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Session 2A - Lecture 1:
Oxy-Pulverised Coal Combustion Technology for Power Generation with CO 2 Capture
(Engineering Principles)
Stanley SantosIEA Greenhouse Gas R&D Programme
2nd APP Oxyfuel Working Group Capacity Building CourseBeijing, China
15th March 2010
Overview• Introduction – Oxyfuel Combustion• Overview to the Boiler and Burner Development
• Recycle of Flue Gas• Emissions (NOx and SOx)
• Overview to the Oxygen Production• 2 column design – “Oxyton Cycle”
2
• 2 column design – “Oxyton Cycle”• Double reboiler design
• Overview to the CO2 Processing Unit• NOx and SOx reaction during compression• Removal of Inerts
• Concluding Remarks
3
OXY-PULVERIZED COAL COMBUSTION FOR POWER GENERATION
Introduction
IntroductionOxyfuel Combustion for Coal Fired Power Plant with CO2 Capture
4
Where Can You Extract the Recycled Flue Gas (RFG)(For some practical application using low S coal)
5
6
IMPACT OF RECYCLE FLUE GAS TO THE BOILER OPERATION
Overview to Boiler and Burner Development
Factors affecting Recycle Ratio
• Critical factors affecting the optimum amount of recycled flue gas• Burner and boiler design (heat transfer and flame
stability – oxygen distribution through burner)
7
stability – oxygen distribution through burner)• Air ingress• Purity of oxygen from the ASU• Coal type• Level of moisture content in comburent• Comburent (oxidant) temperature
7
Mass balance calculation should have a firm basis!! !
• Primary control of the boiler is in the oxygen content of the flue gas (~3.5%vd)
• Requirements of the coal mill should define the quality of the primary RFG
• Defining how the burners should operate is a
8http://www.ieagreen.org.uk
• Defining how the burners should operate is a required step… We need to establish criteria that would result to good combustion. An important element to your process control.
• Criteria for heat transfer profile should define the quality of secondary RFG• Molar ratio of the oxidant• O2 concentration in the secondary
comburent
8
Data from ANL studies (1989)
Optimum Recycle Ratio
~29%
~31%
9http://www.ieagreen.org.uk 9
~48%
32% - 36%
~48%
~31%
Impact of the moisture content of the Recycled Flue Gas
70.0
75.0
80.0
85.0
in t
he
Flu
e G
as
fro
m B
oil
er
[%v
-w
et]
10http://www.ieagreen.org.uk 10
50.0
55.0
60.0
65.0
70.0
26.5 28.0 29.5 31.0 32.5 34.0 35.5 37.0 38.5 40.0 41.5
CO
2 in
th
e F
lue
Ga
s fr
om
Bo
ile
r [%
v
O2 in the comburent [%v -dry]
Wet RFG (H2O ~ 33.4%v)
Dried RFG (H2O ~ 18.6%v)
Data from ANL studies (1987)
Flame Description – Impact of Recycle Ratio(Courtesy of IFRF)
11Figur e 3(c): O2-RFG flame with recycle ratio = 0.76 Figure 3(d): O 2-RFG flame with recycle ratio = 0.52
Figure 3(a): normal air -fired operation Figure 3(b): O 2-RFG flame with recycle ratio = 0.58
Coal Flame Photos:Air Fired vs Oxy-Fired(Courtesy of IHI)
1212
Air mode ((((O2::::21%))))
Oxy mode ((((O2::::21%)))) Oxy mode ((((O2::::30%))))
Coal Flame Photos:Impact of Recycled Flue Gas(Courtesy of IFRF)
1313
Recycle Ratio = 0.76Recycle Ratio = 0.58(~ 0.61 include the CO 2 to transport coal)
Normalised Convective & Radiativeheat flux – Russian Coal - Dry Recycle
Dry Oxyfuel Operation Normalised to Air OperationPeak Radiation Flux, Convective heat transfer and c alculated flame temperature
Russian coal
1.2
1.4
1.6
Nor
mal
ised
Adi
abat
ic
Fla
me
Tem
pera
ture 1.2
1.4
1.6
Nor
mal
ised
Rad
iativ
e an
d C
onve
ctiv
e H
eat F
lux
Normalised Flame Temperature (calculated)
Peak Normalised Heat Flux (measured)
Normalised Convective HTC (measured)
Measured Convective Heat Transfer Coefficient indicates 74% Recycle is "Air-equivalent"
Measured Peak Radiative data indicates 74%
New Build Retrofit Avoid
14
0.4
0.6
0.8
1
1.2
60% 65% 70% 75% 80%Effective Recycle Ratio
Nor
mal
ised
Adi
abat
ic
Fla
me
Tem
pera
ture
0.4
0.6
0.8
1
1.2
Nor
mal
ised
Rad
iativ
e an
d C
onve
ctiv
e H
eat F
lux
Calculated dry oxyfuel adiabatic flame temperatures are equivalent to air at 69% recycle
data indicates 74% Recycle is "Air-equivalent"
15
Considerations in the Boiler Operation
O2 Purity and Air Ingress
(a.) Why not 99+% O 2 Purity(b.) Air Ingress… A Challenge for the Operator
Issue of Air Ingress (Air In-leakage)
Air Ingress in the boiler is a fact of life!!!
16
fact of life!!!
1st Large Scale Demonstration of Oxy-Coal Combustion (35MWth) – What Are the Lesson Learned...
Problem with Air Ingress1st Large Scale Oxy-Coal Combustion Burner Test Experience - International Combustion Lt d.
17
� 30 MWth Low NOx burner
� Because of Air Ingress the desired CO2
composition (only ~ 28% dry basis).
� Air Ingress in boilers
� approx. 3 % of flue gas flow fora new conventional power plant
� up to 10 % over the years forpower plants in use
CO2 Recovery Depends On Feed Composition
Recovery
0.4
0.6
0.8
1
18
At -55°C, 30 barFeed Composition
0
0.2
0.4
0 0.2 0.4 0.6 0.8
NOx Emissions
- We have quite a good confidence in knowing the trend of these emissions
NOx Emissions(Results from ANL-EERC and IFRF)
2020
Results from IFRF study (APG4)
21
SO2 Emissions
- Highly dependent on how - Highly dependent on how sulphur is captured in ash...
- without the removal of SO 2 in the secondary RFG, it should noted that a maximum of ~30% reduction could be exp ected
(on mass per unit energy input basis)
SO2 Emissions(Results from ANL-EERC and IFRF)
0.5
0.6
0.7
0.8
Em
issio
ns (lb
/M
MB
tu
)
2323
0
0.1
0.2
0.3
0.4
0.5
1.5 2 2.5 3 3.5 4
SO
2E
mis
sio
ns (lb
/M
MB
tu
)
[CO2 + H2O]/[O2] Molar Ratio of Comburent
EERC-ANL (Wet RFG)
EERC-ANL (Dry RFG)
Air Fired Case
Sulphur in ash
2424
Fundamental question in attempt to explain the reduction of SO 2…
• Reduction of SO 2 under oxy-coal combustion conditions - Could this observations due to 2 competing phenomena in the furnace and in the convective section???• High temperature sulfation of the ash (as proposed by
25
• High temperature sulfation of the ash (as proposed by Okazaki et. al.) - which could be in agreement base on the data of IFRF (APG2 Trials).
• Sulfur capture in ash at convective section enhanced by higher SO3 formation, higher deposition rate and lower carbon in ash.
25
2626
2727
2828
2929
3030Results from IFRF study (APG2)
Issue of SO 3
- The confirmation of the ANL results as presented from the results of IVD Stuttgart, IHI/Calide Project, Vattenfall, Stuttgart, IHI/Calide Project, Vattenfall, Chalmers University.
- Nonetheless, there are still a lot of confirmation to be done!!!
Oxy-Combustion: KEY ISSUES
• SO3 issue is a big missing link! (4 years ago)
• ANL study (1985) have indicated that SO
32http://www.ieagreen.org.uk 32
indicated that SO 3
formation is 3 to 5 times greater as compared to conventional air – firing mode
• We need to know more about the potential operational issue.
From Chemical Engineering Progress (Vol. 70)
SO3 Emissions(Results from ANL-EERC, IVD Stuttgart, Callide/IHI)
10
12
14
16
18
20
Con
cent
ratio
n (p
pm)
ANL - Air ANL - Oxy
IVD Stuttgart - Air IVD Stuttgart - Oxy
Callide IHI - Coal A - Air Callide IHI - Coal A - Oxy
Callide IHI - Coal B - Air Callide IHI - Coal B - Oxy
33
0
2
4
6
8
10
0 250 500 750 1000 1250 1500 1750 2000 2250
SO
3 C
once
ntra
tion
(ppm
)
SO2 Concentration (ppm)
My Background Analysis…
• SO2 to SO3 conversion will most likely to occur at the convect ive section…
3434Marrier and Dibbs (1974) Thermochmica Act (Vol. 8)
SO3 formation is increased in the presence of iron oxide in the ash
3535
Marrier and Dibbs (1974) Thermochmica Act (Vol. 8)
SO2 captured along the convective part(down to 450°C) by different inlet concentrations
300
400
500
cap
ture
d @
flu
e-ga
s
path
[pp
m]
KK_Captured RH_Captured LA_Captured EN_Captured
36
Oxy-fuel 27 % O2
0
100
200
0 1000 2000 3000 4000
SO2 measured at the end of radiative section [ppm]
SO
2 ca
ptur
ed @
flu
e-ga
s
path
[pp
m]
SO2 injection increased
IHI – Callide Project Results (SO2 Emissions)
300
400
500
SO2, O
xy mode (mg/MJ)
C oal A
Coal B
Coal C
IFRF (APG1 Trials) – Gottelborg coal
0
100
200
0 100 200 300 400 500
SO 2, Air m ode (m g/M J)
SO2, O
xy mode (mg/MJ)
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
1.5 2 2.5 3 3.5 4
SO
2E
mis
sio
ns (
lb/
MM
Btu
)
[CO2 + H2O]/[O2] Molar Ratio of Comburent
EERC-ANL (Wet RFG)
EERC-ANL (Dry RFG)
Air Fired Case
ANL-EERC Trials – Blk. Thunder coal
Would the capture of SO 2 / SO3 in the ash enhanced by lower carbon in ash?
Marrier and Dibbs (1974) Thermochmica Act (Vol. 8)
E.ON UK Results at 26%O2
38
38
Emissions – SO2
© 2004 E.ON 2010年2月22日, E.ON UK, Page 39
Ash Related Issue
40
Data from the trials taken by:
MBEL (Doosan Babcock), Air Products, Ulster University and Naples University (1995)
Summary SO 2/SO3 and Sulphur in Ash – (1)• Capture of sulphur in ash at the furnace section is primarily due to
the high temperature direct sulphation mechanism as suggested by Okazaki et. al. (2001) as shown in their experim ental results. This is pretty much in agreement to the in-flame SO 2
measurements done by IFRF during their APG2 trials. • Okazaki et. al. suggested that this is due to promotion of capture of sulphur
by CaO species and the inhibition of the decomposition of CaSO
41
by CaO species and the inhibition of the decomposition of CaSO4
• This mechanism is further supported from the results of IVD Stuttgart (Maier et. al.) and Imperial College (Wrigley et. al.) indicating the occurrence of both carbonation and sulphation in the ash collected from oxy-coal combustion trials. This could indicate that equilibrium reactions promoting the formation of CaCO3 and CaSO4 are probably favoured (or highly enhanced) under CO2
rich environment.• These results established the feasibility of using in-furnace SO2 reduction by
using Ca(OH)2 or CaO injection.
Summary SO 2/SO3 and Sulphur in Ash – (2)• Additional sulphur capture in ash could also be
promoted by increased formation of SO 3. • It should be recognised that both results from ANL-EERC and IVD
Stuttgart confirms that SO3 formation is higher (about 4-5 times – in terms of mass SO3 emissions per unit energy input) as compared to air fired case. However, it is not yet clear if level of recycled SO2 has
42
air fired case. However, it is not yet clear if level of recycled SO2 has it impact to the level of SO3 formation.
• Capture of sulphur by this mechanism would occur along the flue gas path (during the convective section) as shown in the results by IVD-Stuttgart.
o Furthermore, IVD-Stuttgart results indicated that the higher the level of SO2 are recycled , the capture efficiency of sulphur in ash is more efficient.
o Nonetheless, it should be noted that that this observation in sulphur capture efficiency is coal dependent.
Summary SO 2/SO3 and Sulphur in Ash – (3)• Results from Marrier and Dibbs (1974) further suppo rt the observations
made by IVD Sttuttgart:• maximum conversion of SO2 to SO3 would occur around 700-800oC.• Capture of sulphur in ash could be dependent on the concentration of CaO and MgO
in the ash. (This could probably be one of the reasons why capture efficiency of sulphur becomes coal dependent)
• Iron oxides could enhanced the formation of SO3 therefore promoting the capture of
43
• Iron oxides could enhanced the formation of SO therefore promoting the capture of sulphur in the ash at the convective section. (This could probably be one of the reasons why capture efficiency of sulphur becomes coal dependent).
• Carbon in ash could diminish the efficiency in the capture of sulphur in ash. This is supported by various studies indicating a lower carbon in ash during oxy-coal combustion trials (IHI, IFRF, ANL-EERC) showed a lower SO2 emissions (i.e. higher degree of sulphur capture in ash). A higher carbon in ash by E.ON UK experimental results indicated a nearly similar SO2 emissions to the air fired case.
• Higher ash deposition rate under the wet RFG trials could also promote higher sulphur capture in the convective section. This should be further validated!
44
CHALLENGES TO THE DESIGN AND ENGINEERING OF THE AIR SEPARATION UNIT
Oxygen Production
Challenges to Oxygen Production• As of today, the only available technology for
oxygen production in large quantities is cryogenic air separation .
• Advances and Development in ASU could result to 25% less energy consumption.
45
result to 25% less energy consumption.• These design would be based on either a
3 column design or dual reboiler design.
• Challenges are:• Cost of production of oxygen (energy
consumption)• Utilisation of nitrogen within power plant.
Air Separation PlantsSimplified Air Separation Process
Bey/L/092009/Cottbus.pptLinde AG Engineering Division 46
Air compression, -precooling and -purification
heat exchange, refrigeration,rectification and internal compression
productdistribution
Cryogenic Air Separation – Capacity Increase
Bey/L/092009/Cottbus.pptLinde AG Engineering Division 47
1902 :5 kg/h(0,1 ton/day)
2006 :1,250 Mio kg/h(30.000 ton/day)
Air Separation Plants – Shell „Pearl“ GTL Project Qatar30.000 tons/day Oxygen
Bey/L/092009/Cottbus.pptLinde AG Engineering Division 48
Process Description: Oxygen Supply
• Optimum oxygen purity suggested:• 95% - 97%• @ 95% O2 you will have 2% N2 and 3% Ar
49
• higher purity not worthwhile due to:o Excess O2 requirement (19%)o Boiler air in leakage (1%)o ESP air in leakage (2%)
30 years of continuous Cryogenic ASU improvements
1,5
2,0
2,5
Nor
mai
lzed
Ene
rgy
Effi
cien
cy
2»/
kWh)
1998
2001 2003
1998
2001 2003
IEAGHG International Oxy-Combustion Network 05-03-2008PROPRIETARY World leader in industrial and medical gases 50
0,5
1,0
0 1 000 2 000 3 000 4 000 5 000
Normalized Productivity (« O2 »/m2)
Nor
mai
lzed
Ene
rgy
Effi
cien
cy(«
O2
1971
1976
1988
1971
1976 1971-2003� Energy efficiency : x 1,75� Productivity : x 2,8
Specific energy of separation in kWh per ton of oxygen
200
kWh/t
160
-20%� Impact on HHV
efficiency : +1 %
� Impact on COE :- 3.5%
IEAGHG International Oxy-Combustion Network 05-03-2008PROPRIETARY World leader in industrial and medical gases 51
Theoretical energy of separation (O2&N2)
50
Losses 150
2007
50
110
2008
52
Tonnage Air Separation PlantsMega Plants for new Applications
Cryogenic Air Separation Process Optimization
Bey/L/092009/Cottbus.pptLinde AG Engineering Division 53
Air Separation Process Conventional Design (mit Einblaseturbine)
tauscher
PGAN
GOX
derdruckkolonne
5.5-6 bar
1.05 bar
Bey/L/092009/Cottbus.pptLinde AG Engineering Division 54
Wärmet
Booster
Turbine
Kondensator
Nied
Hochdruckkolonne
UKG
5.3-5.8 bar
� Oxygen: 95%, gaseous, at ambient pressure
Features:
� PNitrogen: up to 30% of airflow available
Air Separation Process Advanced Alternative Design (mit warmer PGAN-Turbine)
cher
PGAN
GOX
Vorkühlung Adsorber
ruckkolonne
G
Restgas
POWER
Power Wärme/Abwärme
AIR5.5-6 bar
1.2-1.3 bar
1.05 bar
5.2-5.7 bar
Bey/L/092009/Cottbus.pptLinde AG Engineering Division 55
Wärmetausc
Booster
Turbine
1
1
Kondensator
Niederdr
Hochdruckkolonne
UKG
5.3-5.8 bar
� Oxygen: 95%, gaseous, at ambient pressure
Features:
� reduced energy consumption/power recovery by expanding PGAN
� heat integration
Air Separation Process Advanced Alternative Design (“Dual Reboiler”-Design)
metauscher
GOX
Niederdruckkolonne
4.5 bar
1.05 bar
Bey/L/092009/Cottbus.pptLinde AG Engineering Division 56
Wärm
Booster
Turbine
Kondensator 2
Hochdruckkolonne
UKG
Kondensator 1
4.3 bar
� Oxygen: 95%, gaseous, at ambient pressure
Features:
� reduced process air pressure
� reduced power consumption
Air Separation Process Advanced Alternative Design (3-column Design)
rmetauscher
GOX
4.5 bar
1.05 bar
sator 2
ne 2
Bey/L/092009/Cottbus.pptLinde AG Engineering Division 57
Wär
Booster
Turbine
Kondens
Niederdruckkolonn
Hochdruckkolonne
UKG
Kondensator 1
4.3 bar
Niederdruckkolonne 1
� Oxygen: 95%, gaseous, at ambient pressure
Features:
� reduced process air pressure
� reduced power consumtion
What are the remaining issues…• ~10,000 TPD of O 2 is required for a 500MWe
(net) oxy-coal power plant with CCS.• This means that you will need 2 single trains of 5000
TPD ASU
• Remaining Issues
58
• Remaining Issues• What could be the maximum capacity of oxygen
production per train?• Operation flexibility (i.e. load following, etc…)• What will you do about the large volume of Nitrogen
produced from this ASU?
58
Where are the other gaps in R&D for oxygen production?• Non-conventional oxygen production
• ITM – ions transport membrane (Air Products)• OTM – oxygen transport membrane (Praxair)• CAR – ceramics autothermal recovery (Linde /
59
• CAR – ceramics autothermal recovery (Linde / BOC)
• Chemical Looping Combustion
59
60
WHAT ARE THE KEY ISSUES IN DETERMINING THE DESIGN PRINCIPLES OF A CO2 PROCESSING UNIT
CO2 Processing Unit
Challenges to CO 2 Processing Unit• The CO2 processing unit could be very competitive
business (an important growth area) for industrial gas companies.
• Challenges are:• Demand of the quality requirements of the CO2 from the power plant
61
• Demand of the quality requirements of the CO2 from the power plant for transport and storage. What are the Required Specification?
• Further recovery of CO2 from the vent will make oxyfuel more competitive if high recovery of CO2 is required!
• Further recovery of energy through integration with ASU or boiler would provide further energy savings.
• Need a large scale demonstration of the CO 2 processing unit using impure CO 2 as refrigerant.
Purification of Oxyfuel-Derived CO2 for Sequestration or EOR
• CO2 produced from oxyfuel requires purification• Cooling to remove water• Inert removal• Compression
• Current design has limitations
62
• Current design has limitations• SOx/NOx removal• Oxygen removal• Recovery limited by phase separation
• Necessary to define CO 2 quality requirement!!!
Air Product’s “Sour Compression Process”“Sour Compression Process”
NOx SO2 Reactions in the CO2Compression System� We realised that SO 2, NOx and Hg can be removed in the CO 2
compression process, in the presence of water and o xygen.
� SO2 is converted to Sulphuric Acid, NO 2 converted to Nitric Acid:
– NO + ½ O2 = NO2 (1) Slow– 2 NO2 = N2O4 (2) Fast– 2 NO2 + H2O = HNO2 + HNO3 (3) Slow
64
– 2 NO2 + H2O = HNO2 + HNO3 (3) Slow– 3 HNO2 = HNO3 + 2 NO + H2O (4) Fast– NO2 + SO2 = NO + SO3 (5) Fast– SO3 + H2O = H2SO4 (6) Fast
� Rate increases with Pressure to the 3 rd power– only feasible at elevated pressure
� No Nitric Acid is formed until all the SO 2 is converted
� Pressure, reactor design and residence times, are i mportant.
CO2 Compression and Purification System –Removal of SO2, NOx and Hg
1.02 bar 30°C67% CO28% H2O25% InertsSOx NOx
30 bar to DriersSaturated 30°C76% CO224% Inerts
� SO2 removal: 100% NOx removal: 90-99%
BFW15 bar
30 bar
Water
65
NOx
Dilute H 2SO4 HNO3
Hg
BFW
Condensate
cw
30 bar
cwcw
Dilute HNO 3
Air Product’s Suggested Process Design for Suggested Process Design for Various Purity…
76%mol CO2
24% inerts (~ 5 - 6% O2)
96%mol CO2
4% inerts (~ 0.95% O2)
25%mol CO2
75% inerts (~ 15% O2)
72%mol CO2
28% inerts(~ 5 - 6% O2)
98%mol CO2
2% inerts(~ 0.6% O2)
25%mol CO2
75% inerts(~ 19% O2)
25%mol CO2
67
72%mol CO2
28% inerts(~ 5 - 6% O2)
99.999%mol CO2
0.001% inerts(~ .0005% O2)
25%mol CO2
75% inerts (~ 15% O2)
72%mol CO2
28% inerts(~ 5 - 6% O2)
99.95%mol CO2
0.05% inerts(~ .01% O2)
25%mol CO2
75% inerts(~ 15% O2)
Air Product’s “Use of Membrane for further
68
“Use of Membrane for further recovery of oxygen and CO2”
Use of Membrane to recover CO2 and O2 at the vent
Vent:7% CO293% inerts (~10% O2)
Product
69
Product96% CO24% inerts (~0.75% O2)
Issues involving CO 2
purification process• We need to establish what is appropriate and
acceptable level of impurities in our CO 2 based on aspects of:• Health, Safety and Environment considerations
o What are the regulations to be established without disadvantaging any capture technology (What is acceptable!!!)
70
technology (What is acceptable!!!)
• Quality specifications defined by transportation/delivery of CO2 to the storage sites
o Also to consider the changes to the CO2 properties by the impurities and its possible reactions
• Quality specifications defined by the storage CO2 for different storage options
• The quality of CO 2 (specific level of impurities) should be openly discussed!
70
Summary and Conclusions(CO2 Processing Unit)
• Depending on the requirement of the oxygen content, processes are now available to produce CO 2 purity from 95% - 99.999%. • It should be noted that higher the purity you reduce the CO2 capture rate.• Higher purity means higher CAPEX and OPEX.
• Downstream removal of SOx and NOx depends on the
71
• Downstream removal of SOx and NOx depends on the taking advantage of the “lead chamber reaction” which naturally occur during wet compression.
• Removal could be achieve by compressions and direct contact acid water wash. This should be demonstrate d in the large scale.
71
SUMMARY AND CONCLUSIONS- BURNER AND BOILER DEVELOPMENT
72
- BURNER AND BOILER DEVELOPMENT- OXYGEN PRODUCTION- CO2 PROCESSING UNIT
Burner & Boiler Development• Demonstration via large scale burner testing is
essential to the development of oxy-combustion.
• Key areas of R&D should focus on:• Heat transfer and flame properties
73
• Heat transfer and flame properties• Coal devolatilisatoin and char combustion• Slagging, fouling deposition characteristics• Emissions (sulphur chemistry, PM and Hg + trace
metals)
• Development in CFD modelling is an essential tools to help design of future burners and boilers.
ASU & CPU
• Air Separation Unit : improvement in performance is available now
• CO2 CPU : feasibility is confirmed but design will remain conservative until pilot plants are started ; significant improvements in performance are
74
achievable for cryogenic unit• Integration of ASU and CO 2 Processing Unit in the
overall oxyfuel combustion plant are key to achieve high efficiency and low capital expenditure
• Should also consider looking at novel oxygen production
74
Concluding Remarks• Oxyfuel Combustion Technology is a viable option
for any coal fired power plant with CO2 Capture.• Oxyfuel Combustion Technology is an option for
new build or retrofit cases.• We need to demonstrate Oxyfuel Combustion
75
• We need to demonstrate Oxyfuel Combustion Technology to build our confidence.
• Business sense, it could have a simple business model for power generation companies wherein the operation of the ASU and CO2 processing could be outsourced with a long term supply contract from the industrial gas companies.
Footprint of Capture plant – DTI Project 407
1 x ASC BT Amine Unit:- 2 x SO2 removal towers
• Oxyfuel and amine scrubbing have similar footprints
Page 76
- 2 x SO2 removal towers (reduces SO2 from 10ppm at FGD outlet to 1 ppm at CO2 absorber inlet)
- 2 x Fans / Blowers- 2 x CO2 Absorber Towers
(12.5m Dia x 45m Height)- 1 x CO2 Stripper Tower (10m Dia)
1 x ASC BT Oxyfuel Unit:- 2 x ASU trains- CO2 Compression- Maximum Height – 68m
Amine Scrubbing &CO2 Compression
23,825m2
ASU &CO2 Compression
24,500m2
Acknowledgement
Gerard Beysel, LINDE EngineeringGerry Hesselman , Doosan BabcockGerry Hesselman , Doosan Babcock
Robin Iron, EOn EngineeringMinish Shah, Praxair
Jean Pierre Tranier, Air LiquideVince White, Air Products
Thank you
Email: [email protected]: http://www.ieaghg.org