High-Temperature Sulfur Removal in Gasification Applications
Raghubir GuptaResearch Director
Center for Energy TechnologyRTI International
August 23, 2007
2
+
Air
Oxygen (95-99%)
N2
Coal + Water
What is Gasification? Gasifier Section:•Controlled chemical reaction•Typically > 2300 deg F•Up to 1200 psig•Organics Destroyed•Short residence time (seconds)•Reduced O 2 Environment
Quench Section:•Gas and molten ash quenched
in circulating water bath•Ash/slag discharged as inert, glassy frit (saleable product)
Slag (Inert Minerals/Ash from Coal)
GasClean-Up
BeforeProduct
Use!
ASU
Products (syngas):•CO •H2
By-products:•H2S •CO2
•Ash (slag)•Steam
CO/H2 ratio can be adjustedGasifier
(quench)
3
Gasification Chemistry
Gasification with OxygenC + 1/2 O2 CO
Combustion with OxygenC + O2 CO2
Gasification with Carbon DioxideC + CO2 2CO
Gasification with SteamC + H2O CO + H2
Gasification with HydrogenC + 2H2 CH4
Water-Gas ShiftCO + H2O H2 + CO2
MethanationCO + 3H2 CH4 + H2O
Coal
Oxygen
Steam
Gasifier GasComposition
(Vol %)
H2 25 - 30CO 30 - 60CO2 5 - 15H2O 2 - 30CH4 0 - 5
H2S 0.2 - 1COS 0 - 0.1N2 0.5 - 4Ar 0.2 - 1
NH3 + HCN 0 -0.3
Ash/Slag/PM
4
Coal
Dimethyl EtherMethanol
Fischer-Tropsch Liquids
Fuel/Town Gas
Power & Steam
Acetic AcidEthylene
&Propylene
Methyl Acetate
VAM
Acetic Anhydride
Ketene
Diketene & Derivatives
PVAPolyolefins
Diesel/Jet/Gas Fuels
Polygeneration Potential of Gasification
Ammonia& Urea
H2
Oxo Chemicals
Synthesis GasWaxes
GasificationNaphtha
Acetate Esters
Iron Reduction
Synthetic Natural Gas
5
Sulfur
CO2
Low Temp Gas Cooling
Shift Rxn(optional)
MercuryRemoval
ParticulateScrubberGasifier
(quench)
Slag/Frit
Coal
H2O
+
Air Separation Unit (ASU)
O2
SulfurRemoval &Recovery
CO/H2 (Syngas)
Fines/Char
What is IGCC ?
Flexibility for CO 2Capture/Sequestration (concentrated stream)
PRE-COMBUSTIONTreatment of Pollutants
•High pressure•Low Volume•Concentrated stream(easier to treat)
Air
Combustion Turbine
Compressed Air to ASU
HRSG
Steam Turbine
Electricity
Electricity
> 90-95%Removal
98-99.9+%Removal
Non-LeachableHeavy MetalRemoval
CO + H2O CO2 + H2Water-Gas Shift Reaction
6
Contaminants in Coal-Derived Syngas
the Target Elemental Contaminants
Element Species
S H2S, COS, CS2 N NH3, HCN Cl HCl, metal chlorides Hg Hg (g)1,2, Hg(CH3)2
1 As As2 (g)1,2, As4 (g)1,2, AsH3 (g)1,2, AsS (g)2, and
other FeAs species1 Se H2Se (g)1,2 Cd Cd (g)1, CdS (condensed)1, CdCl2 (g)1
1 Equilibrium calculations by Diaz-Somoano (2003) at 572 to 932°F.
2 Equilibrium calculations by Helble (1996) at 621 to 1341°F
Species
Range of Concentrations in
Coal Range of Concentrations in
Syngas
S 0.3 – 3.6 wt%1 750-7000 ppmv as H2S and 25-200 ppmv as COS2
N 1.1 – 1.6 wt%1 50-800 ppmv as NH32
Cl 0.0032-0.37 wt%3 170-830 ppmv as HCl2 Hg 0.02-1 µg/g3 1.3-63 ppbv4 As 0.5-80 µg/g3 84-1300 ppbv4 Se 0.2-1.6 µg/g3 32-2600 ppbv4 Cd 0.1-3 µg/g3 11-340 ppbv4
1 Determined in Canadian feed-coals (Goodarzi, 2002). 2 Data survey of four types of gasifiers conducted by Bakker (1998). 3 Typical concentrations in the world's coal as examine by Swaine
(1990). 4 Calculated concentrations based on elemental concentration in coal
and assuming complete vaporization.
7
"Dirty Syngas"CO,H2,CO2,H2S
Clean Solvent
Dirty Solvent
"Clean Syngas"CO, H2
Major Technology Options :
• MDEA (methyldiethanolamine) – Chemical absorption, 98% to 99+% S removal, large CO2 slip (unless use a second stage for CO2 recovery), moderate operating temperature, lowest AGR capital cost
• Selexol tm (primarily dimethyl ethers of polyethylene glycol, DEPE) – Physical absorption, 99+% S removal, variable CO2 slip (based on design), higher AGR cost than MDEA but overall AGR/SRU system costs similar
• Rectisol tm (methanol) - Physical absorption, 99.5% to 99.9+% S removal, complete CO2 removal possible, highest AGR cost, coldest operating temperatures
• Warm Syngas Cleanup - New technologies (e.g., RTI/Eastman) being developed that operate at high temperatures (300-600°C) and at sub to low ppm (<10) sulfur levels. Lowest capital and operating cost option with significant improvement in overall efficiency.
AGR Technologies Can Provide Near 100% Sulfur Removal If Required
(AGR = Acid Gas Removal)
8
Integrated Gasification Combined Cycle (IGCC)
R&D objective: Platform of warm syngas cleaning technologies providing improved efficiency, environmental performance, and cost
9
Syngas Cleaning Technology Platform
Regenerable CO2 sorbents
Sulfur
Regenerable ZnO sorbents
Transport reactor
DSRP
Hg, As, Se, Cd, HCl adsorbents (disposable)
Ammonia/HCN
Selective catalytic oxidation
Acidic adsorbents
Operating Temperatures > 300 °C
Contaminants removed by high-temperature syngas cleaning technology platform include
� Sulfur (H2S, COS)
� Contaminant heavy metals
� Acid gases (CO2)
Key Feature
Thermal efficiency is maintained by avoiding condensation of steam.
10
Warm Gas Sulfur Removal
� Sorbent Development
� Process Development
� Compatibility with other contaminant removal processes
� Process Integration
� IGCC (power generation)
� Chemical/fuels applications
11
Sulfur Sorbents
� Metal oxides react with H2S and COS to form metal sulfides [MeO + H2S = MeS + H2O]
� Most of these metal sulfides are regenerable with air [MeS + 3/2O2 → MeO + SO2]
� Thermodynamic and kinetic limitations provide a list of suitablecandidates (ZnO, Fe2O3, CuO, MnO2, CeO2, SnO2, etc.)
� Zinc oxide and iron oxide-based sorbents are most developed.
� ZnO-based materials provide the best overall performance.
12
Desulfurization Chemistry for ZnO Sorbents
� Desulfurization (Absorber)
ZnO + H2S → ZnS + H2O [∆G = -73 kJ]
� Regeneration (Regenerator)
ZnS + 3/2 O2 → ZnO + SO2 [∆G = -423 kJ]
� Sulfur Recovery Options� Claus Process� Direct Sulfur Recovery Process (DSRP)
SO2 + H2 (or CO) → 1/n Sn + H2O (or CO2)
� Sulfuric acid
13
Equilibrium H2S Concentration in Syngas as a Function of Temperature and H2O Content
Phosphoric Acid Fuel Cell
MCFC
Solid Oxide Fuel Cell
Chemical Production
1.00 E+3
1.00 E+1
1.00 E+0
1.00 E-1
1.00 E-2
1.00 E-3
1.00 E-4
1.00 E-5
1.00 E-6
1.00 E-7
1.00 E+2
1%
20%40%
2%5%10%
0.5%
0.1%
1%
14
Challenges with ZnO Sorbents
� ZnO based materials are extensively used in chemical industry as guard beds. They work very well, but cannot be regenerated.
� Regeneration of the ZnS to ZnO is highly exothermic (∆H ~ 445 kJ). Heat removal and reactor design become very important.
� Reduction of ZnO into metallic Zn with highly reducing syngas (e.g., Shell) at high temperatures (>500°C) present s serious problems.
� Sorbent needs to maintain long-term (1-2 year) life time without significant deactivation and attrition.
15
Potential Solutions
� Support ZnO on an inert matrix to provide strength and surface area. Potential supports include: silica, titania, alumina, etc.
� Use a fluidized-bed reactor design to deal with exothermicity of the regeneration reaction
� Develop a fluidizable sorbent material (50-200 micron particle size) with high reactivity and attrition resistance.
16
RTI Innovations
� Development of RTI-3 Sorbent
� Development of a fast fluidized-bed reactor or transport reactorsystem for desulfurization
� Integration of the process with a commercial gasifier
� Development of ancillary technologies to deal with other contaminants and CO2 at high-temperature, high-pressure conditions.
� Maximize thermal efficiency, and reduce overall capital and operating costs over the conventional systems.
� Demonstrate the operability and reliability of the process with real syngas over extended period of time.
17
Transport Reactor Desulfurization System
� Reactor design identical to a conventional FCC design
� Smaller inventory needed
� Gas residence time of 1-2 seconds for absorption and regeneration
� Handles fines in feed gas
� Easier temperature control
� Need for high sulfur capacity eliminated
� Smaller foot-print, less capital costs
� Need a sorbent with high reactivity and attrition resistance
19
RTI-3 Sorbent
� ZnO supported on zinc aluminate
� Unique nanostructure with grain size <50 nm and high dispersion of ZnO in the matrix
� Produced by spray drying in commercial size equipment
� US patent granted to RTI (US Patent: 6,951,635)
21
Effluent Sulfur Concentrations
0
20
40
60
80
100
120
140
160
180
200
0 50 100 150 200 250 300
Batch 1Batch 2Batch 3Batch 4Field Test Sorbent
0
10
20
30
40
50
60
70
80
0 50 100 150 200 250 300
Batch 1Batch 2Batch 3Batch 4Field Test Sorbent
Eff
luen
t C
o nc e
n tra
tio n
(p p
mv)
CO
SH
2S
Time (min)
Time (min)
Temperature: 600ºF
Pressure: 280 psig
Composition (vol%)
CO 21.1
H2 14.5
CO2 4.4
H2S 0.5
H2O 59.5
22
RTI-3 Regeneration Profiles
900
950
1000
1050
1100
1150
1200
1250
1300
1350
1400
1450
0 5 10 15 20 25
ReacBed 1Bed 3
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
0 5 10 15 20 25
SO2
O2
Time (min)
Time (min)
Tem
pera
ture
(ºF
)E
fflue
nt C
once
ntra
tion
(vol
%)
Temperature: 1000 ºF
Pressure: 280 psig
Composition (vol%)
N2 91.0
O2 9.0
23
Sorbent Attrition Data
0
5
10
15
20
25
RTI E-Cat
% C
hang
e% D dpsv
% D dp50
PSRI AI (< 45 micron)
Rel AI (< 45 micron)
DI (< 20 micron)
RTI vs E-CatJet Cup AttritionTemp: AmbientCup Velocity: 600 ft/s (183 m/s)1 hour test
Figure 3. Attrition indices results from attrition resistance testing of RTI-3 and ECAT
24
RTI-3 Sorbent Scale-Up
� 1 lb - NIRO spray dryer (RTI)
� 100 lb (pilot plant)
� 600 lb (manufacturing plant and 24 ft spray dryer )
� 2000 lb (manufacturing plant and 24 ft spray dryer)� Material field tested at ChevronTexaco
� 8,000 lb (manufacturing plant and 24 ft spray dryer ) � Material being field tested at Eastman
� Sorbent production scale up complete with demonstrated production� Using commercial scale equipment� By reputable catalyst manufacturer� In large batches
� Received R&D 100 Award (2004)
25
Sorbent : RTI-3; spray dried 80 microns
9 (Fresh)9 (used)
Attrition*
~8Sulfur Loading(wt%)
<1 (600ºF)< 10 (900ºF)
Sulfur Leak (ppmv)
N2/O2/H2O
PRODUCTGAS
RISER
MIXINGZONE
STANDPIPE
CYCLONE
SOLIDSWITHDRAWALTRANSPORT GAS
FUEL/STEAM
55Steam
0.71H2S + COS
Composition (vol%)
135135Pressure (psig)
6O2
1100-1300600-900Temperature (ºF)
RegenerationAdsorptionConditions
Operating Conditions:
Performance:
* Davison attrition index Fresh FCC Catalyst =10
RTI Sorbent Testing at KBR TRTUProof of Concept / Design Basis
26
Process Development Challenges
� No high-pressure, high-temperature fluidization data available in literature to design a prototype.
� Extensive cold flow testing was conducted.
� Hydrodynamics at high-pressures did not fit any available models.
� Stable sorbent circulation in controlled manner between absorber and regenerator became a major challenge.
� Mixing of syngas (in absorber) and oxygen (in the regenerator) had to be minimized.
� Control philosophy was developed to devise robust process control.
27
HTDS Schematic
REGENERATEDSORBENT
TO ABSORBER MIXING ZONE
REGENERATEDSORBENT
RAW SYNGAS
CLEAN SYNGAS
RISER
MIXINGZONE
CYCLONE
ZnO + H2S ����
ZnS+H2O
ZnO + COS ����ZnS + CO2
SORBENT RECYCLE
SULFIDEDSORBENT
STANDPIPE
SOLIDS WITHDRAWAL TO
REGEN LOOP N2/O2
SO2 / N2TO
SCRUBBEROR DSRP
RISER
MIXINGZONE
STANDPIPE
CYCLONE
ZnS+3/2O2 ����
ZnO+SO2
31
Sorbent Circulation in the Absorber
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
0:00:00 0:28:48 0:57:36 1:26:24 1:55:12 2:24:00 2:52:48 3:21:36 3:50:24
Time, h:mm:ss
Den
sity
, lb/
ft3
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
Flo
w, s
cfh
Mixing Zone Riser 1 Riser 2 "N2 Feed, scfh
Solids density in mixing zone
Solids density in riser
Gas flow
32
Desulfurized Syngas Composistion, GC ppbv20-Dec-06 598 psig 911 F Absorber
0
100
200
300
400
500
600
700
800
900
1,000
12/20/2005 6:00 12/20/2005 7:12 12/20/2005 8:24 12/20/2005 9:36 12/20/2005 10:48 12/20/2005 12:00 12/20/2005 13:12 12/20/2005 14:24
ppb
H2S COS SO2
Dirty Syngas Composition: H2S 9,400 ppmvCOS 22 ppmv
Typical Sulfur Concentrations in Effluent Syngas(Eastman 2005)
33
Typical Sulfur Concentrations in Effluent Syngas(Eastman 2006-2007)
Dirty syngas composition: 7,771 ppmv H2S
440 ppmv COS
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
Effl
uent
S c
once
ntra
tion
(ppb
v)
SO2
22 hours
H2S removal > 99.97%
COS removal > 99.96%
34
Desulfurization Process Stability
600 psig Absorber Temp. 939 F600 psig Absorber Temp. 939 F
H2S removal > 99.97%
Sul
fur
rate
(kg
/h)
0.00
0.91
1.36
1.81
0.45
2.72
2.27
1,000
0
6,000
4,000
5,000
2,000
3,000
Effl
uent
sul
fur
conc
entr
atio
n (p
pbv)Regeneration rate
Desulfurization rate
22 hours
35
HTDS Field-Testing at Eastman
All data are averages over multiple hours of operation.
HTDS operation time > 2,750 h of actual syngas desulfurization(cumulative to date)
8,3816,9358,661Inlet S concentration (ppmv)
99.9399.8999.93S removal (%)
4.84.24.1S absorbed (lb/h)
5.77.85.9Effluent S concentration (ppmv)
600450300Pressure (psig)
36
Particle Size Distributions
0
10
20
30
40
50
60
70
80
90
100
cum
ula
tive
dis
trib
utio
n Q
3(x
) / %
0
0.25
0.50
0.75
1.00
1.25
1.50
1.75
2.00
2.25
dens
ity d
istrib
utio
n q
3lg(
x)
0.100.10 0.5 1 5 10 50 100 500particle size / µm
Fresh
0
10
20
30
40
50
60
70
80
90
100
cum
ula
tive
dis
trib
utio
n Q
3(x
) / %
0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
dens
ity d
istrib
utio
n q
3lg(
x)
0.100.10 0.5 1 5 10 50 100 500particle size / µm
Used
37
75.560.4Particle Size Distribution [d50] (µm)
98Sulfur Loading (wt%)
127119Bulk Density (lb/ft3)
0.9
0.8
0.9
1.0
Relative Attrition Index* (KBR Test)
(EMN Test)
Spent Sorbent
Fresh Sorbent
* Relative Attrition Ratio = (Davison Index [target material])/(Davison Index [FCC catalyst])
Sorbent Characterization Results
38
Successful Process Demonstrations
� Stable operation of pressurized transport desulfurization system� 2,783 hours of Syngas Operations
� 346 hr longest continuous run� 61% On-stream availability from 2/18/07� Most downtime caused by support/ancillary equipment
� Desulfurization performance� H2S and COS removal� Effluent sulfur < 10 ppmv (Inlet sulfur ~8000 ppmv)
� Solids circulation� Attrition loss~ 10-50 kg/MM kg circulated (FCC ~50-100 kg/MM kg
circulated)
� Thermally neutral process operation over an acceptable temperature range
� Operating controls provide stable solids circulation and processperformance
� Commercial startup/shutdown plans being tested
39
Direct Sulfur Recovery Process (DSRP)
� Reaction chemistry:
SO2 + 2H2 → 1/n Sn + 2H2O
SO2 + 2CO → 1/n Sn + 2CO2
� Temperature: 500-600ºC
� Pressure: 300 psig (favors higher pressures)
� Catalyst: Molybdenum sulfide on alumina
� Reactor design: Fixed bed
41
DSRP Field-Testing at Eastman
Data are averages over multiple runs.
DSRP Integrated operation time ~50 h of actual syngas desulfurization55 lbs of sulfur collected (Predicted production 61 lb)
(cumulative to date)
72Syngas flow (SCFH)
99.91Conversion (%)
22SO2 Outlet Concentration (ppmv)
24,125SO2 Inlet Concentration (ppmv)
1256Regeneration Off gas (SCFH)
42
Chemical Nature of Gaseous Trace Element Species in a Coal Gas Stream
Element >1000°°°°C 400°°°° to 800°°°°C 100°°°° to 400°°°°C <100°°°°C
As AsO, AsS, As AsO, As, As2S3 Condensed Species
Condensed Species
Be Be(OH)2 Condensed Species
Condensed Species
Condensed Species
Hg Hg, HgS, HgO Hg Hg, HgCl2 Hg, HgCl2
B HBO HBO HBO -
V VO2 Condensed Species
Condensed Species
Condensed Species
Se H2Se, Se, SeO H2Se H2Se H2Se
Ni NiCl Condensed Species
Ni(CO)4 Ni(CO)4
Co CoCl2, CoCl Condensed Species
Condensed Species
Condensed Species
Sb SbO SbO Sb2S3 Sb4S3
Cd Cd Cd CdCl2 Condensed Species
Pb PbS, Pb, PbCl2 PbS, Pb, PbCl2 Condensed Species
Condensed Species
Zn Zn Zn, ZnCl2 Condensed Species
Condensed Species
43
Multicontaminant Control
In addition to sulfur, RTI and Eastman are pursuing removal of a host of other contaminants from syngas at high-temperature, high-pressure conditions:
� NH3, HCl, HCN
� Heavy metals (Hg, As, Cd, Se)
Removal of other pollutants from syngas is necessary to reduce the overall cost of IGCC-based systems.
Ammonia and trace metal test skid
44
Ammonia Effluent Profiles(1-inch Fixed-Bed Reactor Testing)
14.7752Regeneration
200392Adsorption
Pressure (psig)Temperature (°F)Process cycle
Adsorption
0
100
200
300
400
500
600
0 50 100 150 200 250
Cycle #1
Cycle #2
Cycle #3
Cycle #4
Time (min)
NH
3co
ncen
trat
ion
(ppm
v)
Regeneration
0
20
40
60
80
100
120
0 50 100 150 200
Cycle #1
Cycle #2
Cycle #3
Cycle #4
Time (min)
#1
#2
#3
#4
NH
3re
cove
red
(mg)
� Demonstrated highly acidic molecular sieves for regenerative NH3 adsorption/desorption process
45
HCl Removal Performance
� Demonstrated HCl removal to <50 ppbv with NaHCO3 supported on sepiolite20 30 40 60
Res
idua
l HC
l vap
or c
once
ntra
tion
(ppb
)
Time (h)
Sepiolite/NaHCO3sorbent150
200
350
400
0 10 5020 30 40 60
Diatomaceousearth sorbent
Space velocity = 2,000 h-1
Inlet HCl level = 50 ppmT = 350 °C
100
50
0
300
250
46
Schematic of Mercury Exposure Apparatus
Test Gas: Hg = 30 ppbV H2S = 0.5 vol. %H2 = 19 vol. % H2O = 1.5 vol. %CO = 27 vol. % CO2 = Balance
Compressed N 2or CO2
Hg Permeation Source
MFC #1
Tube Furnace
Sorbent Bed
QC Cartridge
Hg Trap
Water Impingers
Compressed Syngas
Components
MFC #2122 °F
47
Impregnated Carbon:Mercury Capacity Testing
Capacity values were determined when effluent Hg concentration was between 10% and 20% of feed concentration.
NitrogenReducing gas
Syngas
464
392
0.00
0.02
0.04
0.06
0.08
0.10
0.12
0.14
0.16
0.18
0.20
Gas reactivity
Tem
per
atu
re (
°F)
Cap
acit
y (w
t%)
48
Schematic of Arsine Exposure Apparatus
Tube Furnace
Sorbent Bed
QC Cartridge Primary Scrubber
Water Impingers
Compressed Syngas
Components
MFC #1
CompressedArsine Mixture
FlowRestrictor Valco Six
Port Valve
Components within dashed lineconfigured in chemical fume hood.
Secondary Scrubber
Flow Restrictor
NNNN2222 Purge GasPurge GasPurge GasPurge Gas
AsHAsHAsHAsH3333 = 10 ppm= 10 ppm= 10 ppm= 10 ppmCOCOCOCO2222 = 51.5%= 51.5%= 51.5%= 51.5%CO = 27%CO = 27%CO = 27%CO = 27%HHHH2222 = 20%= 20%= 20%= 20%HHHH2222O vapor = 1.5%O vapor = 1.5%O vapor = 1.5%O vapor = 1.5%HHHH2222S = 0.5%S = 0.5%S = 0.5%S = 0.5%
49
Sorbent Exposure temp. (°C) GHSV (h-1) Matrix Capacity (wt%) Removal (%)
RTI-8 250 15,000 Dirty syngas A 0.22 93
250 15,000 Clean syngas >1.35 -
Impregnated carbon 250 15,000 Dirty syngas A >1.5 -
200 15,000 Dirty syngas A >8.0 -
Commercial Sorbent A 200 15,000 Dirty syngas A 3.0 90
Süd-Chemie Sample A 200 15,000 Dirty syngas B > 6.0 -
200 15,000 Dirty syngas A >1.9 -
Summary of Arsine Capacity Tests
50
DOE Report "Major Environmental Aspects of Gasification-Based Power Generation Technologies", December 2002
IGCC: Low-Risk Option for Carbon Capture (~ 1/3 the cost for PC)
IGCC Minimizes Capital Cost Penalty of CO 2 Capture
5-10
51
High-Temperature CO2 Sorbent
Goal: Regenerable high-temperature CO2 sorbent with potential of producing high-pressure CO2 byproduct
� Sorbent development– 1 kg of fixed-bed material – Several promising
fluidized-bed formulations being tested
� Bench-scale testing – Multicycle
adsorption/regeneration – Real syngas exposure
Li4SiO4 + CO2 � Li2CO3 + Li2SiO3
∆H°298K = –142.0 kJ/mol
0.00
5.00
10.00
15.00
20.00
25.00
0 10 20 30 40 50 60 70 80
Time (min)
CO
2or
CO
con
cent
ratio
n (v
ol%
)
800
850
900
950
1000
1050
1100
1150
1200
1250
Tem
pera
ture
(°F
)
Clean syngas, 550 o C, dT=84 o CTemperature: 543 - 627 o C
(1010 - 1160 o F)Pressure: 280 psiSV: 2000 hr -1
Gas composition (vol%):CO 2 : 2, CO: 20, H 2: 15
H 2O: 18, H 2S: 0 , N 2 : 45
T1
CO
CO 2
T2
CO
2or
CO
con
cent
ratio
n(v
ol%
)
Time (min)
0.00
5.00
10.00
15.00
0 10 20 30 40 50 60 70 80
Time (min)
800
850
900
950
1000
1050
1100
1150
1200
1250
Tem
pera
ture
(°F
)Clean syngas, 550 o C, dT=84 o CTemperature: 543 - 627 o C
(1010 - 1160 o F)Pressure: 280 psiSV: 2000 hr -1
Gas composition (vol%):CO 2 : 2, CO: 20, H 2: 15
H 2O: 18, H 2S: 0 , N 2 : 45
T1
CO
CO 2
T2
0 10 20 30 40 50 60 70 80
Time (min)
800
850
900
950
1000
1050
1100
1150
1200
1250
Clean syngas, 550 o C, dT=84 o CTemperature: 543 - 627 o C
(1010 - 1160 o F)Pressure: 280 psiSV: 2000 hr -1
Gas composition (vol%):CO 2 : 2, CO: 20, H 2: 15
H 2O: 18, H 2S: 0 , N 2 : 45
T1
CO
CO2
T2
Time (min)
0.00
5.00
10.00
15.00
20.00
25.00
0 10 20 30 40 50 60 70 80
Time (min)
CO
2or
CO
con
cent
ratio
n (v
ol%
)
800
850
900
950
1000
1050
1100
1150
1200
1250
Tem
pera
ture
(°F
)
Clean syngas, 550 o C, dT=84 o CTemperature: 543 - 627 o C
(1010 - 1160 o F)Pressure: 280 psiSV: 2000 hr -1
Gas composition (vol%):CO 2 : 2, CO: 20, H 2: 15
H 2O: 18, H 2S: 0 , N 2 : 45
T1
CO
CO 2
T2
0.00
5.00
10.00
15.00
20.00
25.00
0 10 20 30 40 50 60 70 80
Time (min)
CO
2or
CO
con
cent
ratio
n (v
ol%
)
800
850
900
950
1000
1050
1100
1150
1200
1250
Tem
pera
ture
(°F
)
Clean syngas, 550 o C, dT=84 o CTemperature: 543 - 627 o C
(1010 - 1160 o F)Pressure: 280 psiSV: 2000 hr -1
Gas composition (vol%):CO 2 : 2, CO: 20, H 2: 15
H 2O: 18, H 2S: 0 , N 2 : 45
T1
CO
CO 2
T2
CO
2or
CO
con
cent
ratio
n(v
ol%
)
Time (min)
0.00
5.00
10.00
15.00
0 10 20 30 40 50 60 70 80
Time (min)
800
850
900
950
1000
1050
1100
1150
1200
1250
Tem
pera
ture
(°F
)Clean syngas, 550 o C, dT=84 o CTemperature: 543 - 627 o C
(1010 - 1160 o F)Pressure: 280 psiSV: 2000 hr -1
Gas composition (vol%):CO 2 : 2, CO: 20, H 2: 15
H 2O: 18, H 2S: 0 , N 2 : 45
T1
CO
CO 2
T2
0 10 20 30 40 50 60 70 80
Time (min)
800
850
900
950
1000
1050
1100
1150
1200
1250
Clean syngas, 550 o C, dT=84 o CTemperature: 543 - 627 o C
(1010 - 1160 o F)Pressure: 280 psiSV: 2000 hr -1
Gas composition (vol%):CO 2 : 2, CO: 20, H 2: 15
H 2O: 18, H 2S: 0 , N 2 : 45
T1
CO
CO2
T2
Time (min)
52
Regenerable CO2 Sorbent Candidate
CO2 / N2
Raw Syngas
Clean Syngas
0 . 9
0 . 9 5
1
1 . 0 5
1 . 1
1 . 1 5
1 . 2
1 . 2 5
3 5 8 5 1 3 5 1 8 5 2 3 5 2 8 5 3 3 5 3 8 5 4 3 5 4 8 5 5 3 5
T i m e ( m i n . )
Wei
ght F
ract
ion
0
1 0 0
2 0 0
3 0 0
4 0 0
5 0 0
6 0 0
Tem
pera
ture
(oC
)
0 . 9 5
1
1 . 0 5
1 . 1
1 . 1 5
1 . 2
1 . 2 5
1 . 3
2 5 0 3 0 0 3 5 0 4 0 0 4 5 0 5 0 0
T i m e ( m i n . )
Wei
ght F
ract
ion
0
1 0 0
2 0 0
3 0 0
4 0 0
5 0 0
Tem
pera
ture
(C
)
0 . 9 7
0 . 9 9
1 . 0 1
1 . 0 3
1 . 0 5
1 . 0 7
1 0 3 9 1 1 3 9 1 2 3 9 1 3 3 9 1 4 3 9 1 5 3 9 1 6 3 9
T i m e ( m i n . )
Wei
ght F
ract
ion
0
1 0 0
2 0 0
3 0 0
4 0 0
5 0 0
6 0 0
Tem
pera
ture
(oC
)
5 5 0 ° C i n 2 0 % C O 2 / N 2
53
CO2 Capacity
252216With Promoter A
302923With Promoter B
19179Without promoter
CO2 Capacity at 10 min. 550°C (wt%)
in raw syngasin clean syngasin 20% CO 2/N2
0
5
10
15
20
25
250 300 350 400 450 500 550
Temperature ( oC)
CO
2 C
apac
ity (
wt%
)
from Syngas
from CO Shift
Fixed-bed
TGA
54
Demonstration of High-Purity H2 Production
0
10
20
30
40
50
60
70
80
90
100
0 5 10 15 20 25 30 35Time (minute)
Gas
Com
posi
tion
(vol
%)
CO
H2
CO2
Time (min)
Gas
com
posi
tion
(vol
%)
H2
CO2
CO
Effluent Gas from Treatment with Regenerable CO2 Sorbent and WGS Catalyst
55
Acid Gas Removal Using Polymer Membranes
� Low temperature reverse selective membranes
� Can permeate CO2, H2S and COS from syngas
� Can be potentially combined with amine systems
Acid Gas Removal Using Polymer Membranes
56
Permeability in Rubbery and GlassyPolymers: Effect of Penetrant Size
DSP ×=
Solubility coefficient
Diffusion coefficient
1 barrer = 10 -10 cm 3(STP)·cm/(cm 2·s·cmHg)
He
10-3
10-2
10-1
100
101
102
103
104
0 100 200 300
Gas
per
mea
bilit
y (b
arre
r) Polydimethylsiloxane(Rubbery polymer)
Polysulfone(Glassy polymer)
H2
O2
N2
CO2
CH4
C2H6C3H8
C2Cl2F4CCl2F2
SF6
CH4N2
O2
CO2
NH3
H2
Critical volume (cm 3/mol)
==B
A
B
A
B
AA/B D
DSS
PPα
Solubility selectivity
Mobilityselectivity
57
Novel Reverse-Selective Membranes for Bulk H2S and CO2 Removal
0.01
0.1
1
10
100
1,000
10-2 10-1 100 101 102 103 104 105
H2S permeability (barrer)
XL-PEO (2)XL-PEO (1)
MEDAL 016
MEDAL 018
MEDAL 023XL-PEO (3)
Upper bound
H2S
/H2 s
elec
tivity
PEG-co-PU
PEG-co-PEs (#7-4)
PEG-co-PA
PEG-co-PEs (#7-5)
H2S/H2 Tradeoff
0.10
1.0
10
10-2 10-1 100 101 102 103 104
CO
2/H2 s
elec
tivity
CO2 permeability (barrer)
XL-PEO (1)
Upper bound
XL-PEO (2)
MEDAL 023
MEDAL 018
MEDAL 016
XL-PEO (3)
PEG-co-PU
PEG-co-PEs (#7-4)
PEG-co-PA
PEG-co-PEs (#7-5)
CO2/H2 Tradeoff
1 barrer = 10-10 cm3(STP)·cm/(cm2·s·cmHg)
Color points – New ether-containing polymers studied as dense films in this project; Mixture results
Black points – Conventional polymers reported in literature; Mostly pure-gas data
58
Membrane Development Accomplishments
� Created a reference source for mixed-gas permeabilities for various syngas species, including H2S, COS, SO2, and CO
� Synthesized polymer films with H2S/H2 selectivities >30
� Found strong dependence of selectivity on temperature
� Discovered unusual permeation properties of fluorinated polymers for H2S separation
� Published results in three peer-reviewed articles, with one in the journal Science
� Produced three bulk-desulfurization spiral-wound membrane modules (0.75-m2 membrane area each)
� Designed and constructed skid-mounted field-test membrane system
– Shipped to test site at Eastman Chemical
A spiral-wound membrane module to be used in field test
60
Technical and Economic Evaluation
� Process integration in an IGCC plant
� Process integration for chemicals/fuels
� Capital and operating cost estimation
� Thermal efficiency advantages
� Scale up issues/sizes for full commercial unit
� Technology risk analysis and mitigation
62
Commercially available
Thermal efficiency
>0.1~0.1Operating costs (¢/kWh)
Capital cost ($/kW)
COS hydrolysis required
Sulfur removal (ppmv)
Temperature (°C)
RectisolRTI/EastmanSelexol
Comparison of Desulfurization Processes
Syngas dew point to radiant cooler -40<20
<20 <10 0.1
Yes (?) No No
160 70-100 ~190
<0.1
Base 1.7–2.7% <Base
Now 2008 Now
Source: Eastman, ChevronTexaco, Nexant (2003)
63
Updated 2007 Cost Estimates(Nexant)
2005 IL#6 2005 IL#6 2006 IL#6 2006 IL#6 Base Case IGCC IGCC with WGCU IGCC WGCU
# of Trains
Installed Cost, $MM
(2006)# of
Trains
Installed Cost, $MM
(2006)
Installed Cost, $MM
(2006)
Installed Cost, $MM
(2006)Coal Handling & Storage 2 18.4 2 18.4 17.8 17.8Gasification & Slurry Preparation 2 159.0 2 159.0 151.5 151.5Spare Gasification Train 1 79.5 1 79.5 75.8 75.8ASU + O2 Compression 2 79.8 2 84.7 80.9 83LT Gas Cooling/COS Hydro./Hg Removal 2 36.8 37.2AGR (Selexol) & SWS 2 139.1 133.2SWS (Sour Water Stripper) Only 2 0.4 0.4Sulfur Recovery & TGT 2+1 57.5 37.0WGCU/DSRP Systems 2 184.3 146.8Fuel Gas System 1 4.2 1 5.3 4.3 5.2Plt. Instru. Air & N2 Systems 1 22.9 1 8.9 23.7 12.5Gas Turbine Generation 2 141.0 2 141.0 146.5 144.9HRSG/Boiler Plt./BFW/DM/Cond. Systems 2 47.8 2 56.6 48.8 49.6Steam Turbine Generation System 2 48.7 2 54.5 49.4 56.3CW Pumps & CT Fans 17.0 18.0 16.4 18.5BOP 161.3 161.9 175.5 163.1
Total Field Cost (TFC) 1013.0 972.5 998.0 925.4Home Office @ 10% of TFC 101.3 97.3 99.8 92.5
Contingency 0 0 0 0Total Installed Cost (TPC) 1114.3 1069.8 1097.8 1017.9
Installed Cost, $/Net kW 1997 1742 1967 1573
Net Reduction 12.7% 20%
64
IGCC Performances(Nexant)
2005 IL#6 2005 IL#6 2006 IL#6 2006 IL#6Base Case
IGCCIGCC with
WGCUBase Case
IGCCIGCC with
WGCUA. Import or Feeds
Coal Feed, STPD (AR) 5,763 5,763 5,467 5,46795% Oxygen, STPD 4,612 5,038 4,701 4,933Make Up Water, GPM 4,165 4,260 5,615 4,154
B. Export or ProductsElectrical Power, MW 558 614 588 647Sulfur, STPD 256 256 137 137Slag & Ash (Incl. Carbon), STPD (dry) 870 870 562 562Process Waste Water, GPM 1,248 1,047 2,763 1,039
C. Thermal EfficiencyHHV, % 36.0 39.6 37.8 41.6LHV, % 37.5 41.2 39.6 43.5
65
Technology Risks for Commercial Deployment
� Performance in real syngas
– Field testing has provided actual performance resulting from exposure to real coal-derived syngas
� Process reliability
– Sorbent performance• Extended testing to evaluate long-term chemical deactivation and mechanical attrition
– Process control and stability• Demonstrated and refined ability to control process at stable operating conditions
– Process integration• Demonstrated integrated operation of technology components of syngas cleaning platform
• Sorbent production scale-up
– Commercially manufactured 8,000 lbs of sorbent for pilot-plant testing
• Process scale-up
– Successfully scaled process up to 0.3 MW
– Actively working on 50-MW demonstration unit
66
HTDS Scale-Up Factors
1,000,000
80’H × 3.75’ID
80’H × 5.5’ID
3000
38,000
600
Commercial
62,000
80’H × 12”ID
80’H × 19”ID
1100
2,000
50
Prototype
Sorbent Circulation Rate (lb/h)
Regenerator
Mixing Zone
Riser
Absorber
Mixing Zone
Riser
Footprint (ft2)
Gas Flow (SCFH) (Thousands)
Size (MWe)
500
10’H × 1.5”ID
20’H × 1”ID
15’H × 2.5”ID
40’H × 1.5”ID
260
17
0.3
EMN Pilot Plant
67
Commercialization Plans
� Two major gasification technology vendors are evaluating warm syngas cleaning technologies for commercial package.
� Two additional gasification technology vendors have shown interest in this technology.
� Potential host site for a 50-MWe demonstration plant is being negotiated to demonstrate commercial feasibility of warm syngas cleaning technologies.
68
Gasification Technologies ProgramClean, Affordable Energy Systems
FeedstocksFeedstocksFlexibilityFlexibility
AirAirSeparationSeparation
Products/Products/ByproductsByproductsUtilizationUtilization
HH22/CO/CO22SeparationSeparation
Fuels/Chemicals
Fuel Cell
CoCo--ProductionProduction(co(co--funded activities)funded activities)
High Efficiency Turbine
Electricity
LiquidsConversion
ProcessHeat/SteamGasificationGasification
GasStreamCleanup
Power
FuelsCoal, biomass,
pet. coke
Gas CleaningGas Cleaning
OxygenMembrane
Gasifier
H2
CO2