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

18

Sorbent Development Criteria

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)

20

RTI’s high-temperature, high-pressure bench-scale sorbent test facility

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

28

Schematic of Eastman Field Test

29

Various Installations of HTDS

ChevronTexaco (2003) Eastman Chemical (2005)

30

Eastman Gasification Plant

RTI DesulfurizationUnit / DSRP

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

40

DSRP Field Test UnitGas Inlet and Preheater Side

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

59

Membrane Skid System

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

61

Potential Integration Schemes for Multicontaminant Cleanup

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

69

Project Team

� RTI

� Eastman Chemical Company

� BOC Gases

� ChevronTexaco (CVX)

� Kellogg Brown & Root (KBR)

� Süd-Chemie (SCI)

� SRI International (SRI)

� MEDAL

� The University of Texas at Austin

� DOE/NETL