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Gasification
Gasification is the conversion of a solid fuel to a
combustible syngas (CO+H2) Gasification enables
Coal to run gas turbines
Fuel gas clean up
Pre-combustion CO2 capture
Gasification is not a new technology
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Main features of the 3 gasifier types
Gasifier type Moving bed Fluidized bed Entrained flow
Outlet temperature Low
(425-600 C)
Moderate
(900-1050 C)
High
(1250-1600 C)
Oxidant demand Low Moderate High
Ash conditions Dry ash or slagging Dry ash oragglomerating
Slagging
Size of coal feed 6-50 mm 6-10 mm < 100 m
Acceptability of fines Limited Good Unlimited
Other characteristics Methane, tars and oilspresent in syngas
Low carbon conversion Pure syngas, highcarbon conversion
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Moving bed gasifier
Fluidized bed gasifier
Focus of commercial gasifier
technology providers:
Entrained flow
slagging gasifier
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Entrained flow slagging gasifiers
Outlet syngas temperature: 1250-1600 C
Slagging: Ash is a low viscosity liquid Pure gas
High carbon conversion
Can handle any coal type (technical perspective)
Coal is ground to < 100 microns particles
Particle residence time: a few seconds
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Maturity of
gasifiers
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3 major classes
Moving bed Fluidized bed
Entrained flow
Key modern gasifiers are of the entrained flow type: GE (formerly Texaco)
Shell
ConocoPhilips: E-gas process (formerly Destec) The moving bed type
The Lurgi dry ash gasifier (Sasol-Lurgi)
Fluidized bed type gasifiers less developed
Not fully commercialized
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GE Shell ConocoPhillips
Flow
direction
is really
upwards?!39
bar
~35
bar
70
bar
Source: www.netl.doe.gov
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Integrated Gasification Combined Cycle
(IGCC) What is an IGCC?
A combined cycle (CC) power plant with a
gasifier in front of it to provide the gaseous fuel
Gasification
Converts coal to syngas (CO+H2) Combined cycle
Converts the syngas to electricity Consists of
Gas turbine
Steam cycle (HRSG & steam turbine)
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Integrated gasification combined cycle
(IGCC) without CO2 capture
Air (15 atm)
Sulfur
removal
Gas turbine HRSG
Steam
turbine
ASU
GasifierCoal feed
Air Air
O2
N2
Hot raw syngas
Clean syngas
Exhaust
~600 C
Flue gas
~120 C
Hot
steam
Feed
water
Water
quench or
heat recov.
H2S
Particulateremoval
Depending on process
configurationHeat
Quench
water
~40 C~1500 C
~300
C
Gasification
Combined
cycle
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Experience with coal based IGCCs
Demonstration plants with government
support
Project participant/
Plant nameLocation
Electric
output
(net)
Gasifier type
(current
owner)
Gas turbine Dates of operation
Southern CaliforniaEdison/ Cool Water
Barstow, CA 100 MWGE with heat
recoveryGE 7E 1984 - 1988
Dow (Destec)/LGTIPlaquemine,
LA160 MW
ConocoPhillipsE-gas
SiemensSGT6-3000E
1987 - 1995
Nuon/ Nuon Power
Buggenum
Buggenum,The
Netherlands
253 MW ShellSiemens
SGT5-2000E
1994 - present
Destec and PSI Energy/Wabash River
West TerreHaute, IN
262 MWConocoPhillips
E-gasGE 7FA 1995 - present
Tampa Electric Company/Polk Power Station
Mulberry, FL 250 MWGE with heat
recoveryGE 7 FA 1996 - present
Elcogas/ PuertollanoPuertollano,
Spain298 MW Prenflo
Siemens
SGT5-4000F1998 - present
Sierra Pacific PowerCompany/Pinon Pine
Reno, NV 99 MWKRW air blown
fluidized bedGE 6FA
1998 2000(18 start-up attempts,
failed to achieve steadystate operation)
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Availability of IGCC demos
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
60.0%
70.0%
80.0%
90.0%
1st
year
2nd
year
3rd
year
4th
year
5th
year
6th
year
7th
year
8th
year
9th
year
10th
year
11th
year
Nuon Availability
Wabash Availability
TECO Availability
Elcogas AvailabilityCool Water Availability
LGTI Syngas Availability
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Increasing commercial interest in IGCC
Several alliances formed in 2004 aiming to provide IGCCcustomers one stop shopping (buy the package instead
of the pieces..) GE & Bechtel. GE purchased the Texaco gasifier from
ChevronTexaco
ConocoPhillips & Fluor Shell, Uhde and Black & Veatch
Main challenges are to demonstrate competitivenesstowards pulverized coal (PC) plants in the market
Capital cost
Availability
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IGCC with CO2 capture
Air (15 atm)
Steam
CO2 capture
Gas turbine HRSG
Steam
turbine
ASU
GasifierCoal feed
Air Air
O2
N2
Hot raw syngas
H2 rich fuel
Exhaust
~600 C
Flue gas
~120 C
Hot
steam
Feed
water
Steam
extraction to
shift reaction
Water
quench or
heat recov.
Sulfur
removal
H2S
CO2
Particulate
removal
ShiftCO+H2O
=CO2+H2
Heat
Quenchwater
~40 C
~40 C~1500 C
~300C
Depending on process
configuration
New blocks
added for CO2capture
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Sequence of gas clean up, shift and
capture:
Candle filters (250-350 C)
Water scrubber
Shift (if capture, 500 C & 200 C)
Water gas shift reaction: CO + H2O => H
2+ CO
2 Simultaneous hydrolysis
Exothermic, heat is released => chemical energy lost
Demands steam from steam cycle => electricity lost
Hydrolysis (if no capture, 180 C)
COS + H2O => H2S + CO2 Needed because sulfur removal is more effective forH2S
Negligible impact on energy balance (due to ppmlevel)
Sulfur removal
Acid gas removal (AGR), 40 C: MDEA, Selexol
Sulfur recovery unit (SRU): Claus plant, production ofsolid sulfur
Tail gas treatment (TGT): E.g. SCOT, treatment ofexit stream from SRU
CO2 capture, 40 C: MDEA, Selexol
Candle
filter
Scrubber
Shift
(sour)Hydrolysis
Sulfur
removal
CO2capture
Syngas from
gasifier
Syngas to
gas turbine
S lf l fi ti
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Sulfur removal configurations
NETL/MIT simulation:
Higman, 2003 (Gasification text book),
also IEA, 2003: Air blown SRU
Absorption process in TGT
Recycle of concentrated H2S to SRU
Oxygen blown SRU
No absorption process in TGT, only
conversion of sulfur compounds to H2S
Recycle of dilute H2S to AGR
Elimination of emission stream from TGT
AGR
SRU
TGT
Raw syngas Clean syngas
Solid sulfurAir
To incineratorRecycle
of H2S
H2S
Tail gas
AGR
SRU (Single
stage Claus )
Hydrogenation/
Quench
Raw syngas Clean syngas
Solid sulfurOxygen/Air
Recycle
of tail gas
with H2S
H2S
Tail gas
AGR Acid gas removal, SRU Sulfur recovery unit, TGT Tail gas treatment
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Increased turbine mass flowFuel
Compressor
air
Hot
exhaustGas turbine =
compressor +
combustor +
turbine
Because the heating value of syngas is lower, a higher mass flow rate offuel is added to the turbine
Potential increase in power (GE 7FA: From 172 to 192 MW, +12 %) Two ways to get more mass flow through the turbine:
Decreased firing temperature (reduces CC efficiency)
Higher pressure ratio (preferred)
Higher pressure ratio requires sufficient compressor surge margin Alternatively (if no margin), bleed air from compressor outlet to ASU
Gas turbine torque limit can be limiting
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Integration of ASU and GT
Degree of integration
Percentage of air needed in ASU which is bled from the
GT compressor outlet
A range from 0 % to 100 % is possible
No integration (0 %): availability (+), efficiency (-)
Full integration (100 %): availability (-), efficiency (+)
Optimal trade-off*: 25 % - 35 %* Neville Holt, Turbomachinery International, May/June 2004
Fuel
Compressor air
Air bleed to ASU
Nitrogen from ASU
Hot
exhaust
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IGCC turbines
Modern gas turbines use combustors where fuel
and air is premixed to reduce flame temperaturesand therefore NOx formation (dry low NOxburners)
Turbines in IGCC plants: Diffusion burners instead of DLN (avoiding the
danger of flashback)
Dilution with nitrogen and/or steam necessary,
nitrogen preferred
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Reduced GT firing temperature Increased % of H2O in the exhaust
Leads to higher heat transfer
Reduction of firing temperature (TIT) necessaryto maintain material lifetime
In order of increasing trouble: Natural gas
Syngas from IGCC
H2 rich syngas from IGCC with CO2 capture
For same reason, N2
dilution preferred over steaminjection
Hot
exhaust
What determines the
gas turbine firingtemperature/ turbine
inlet temperature
(TIT)?
Ans: The fuel supply
in MW or btu/hour
Fuel
Compressorair
~1300 C
~600 C
~400 C
~15 C
Graphics source: GE
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Steam cycles
Purpose: Utilize gas turbine exhaust and otherheat sources to produce electricity
Consists of HRSG (next slide) + steam turbine
State-of-the-art cycle for CC
3 pressure level steam generation with reheat Steam parameters
The three subcritical pressure levels
(optimized in each case?) Superheat: Typical 540 C (Maximum 565 C)
Reheat: Typical 540 C
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HRSG = A big heat exchanger
Heat recovery
steam generator Produces steam
from the hot gasturbine exhaust
Hot exhaust from
gas turbine, 600 C
Cold stack gas,90-130 C
Construction of 100 MW
CC plant by Kinder
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HRSG
Evaporators (boilers):production of steam
Economizers: Increasingthe temperature of liquidwater
Superheaters: Increasingthe temperature of steam(water vapor)
May be integrated withIGCC syngas coolers.
Steam is superheated inHRSG.
Suppliers: Vogt-NEM,Nooter-Eriksen, FosterWheeler, AalborgIndustries, and Deltak
CC plant by Kinder
Morgan, Midland, Texas,
2004 (My photo).
Left: HRSG
Right: Inlet air filter above
GE LM6000 gas turbine
Source: GE
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Air separation units (ASUs)
Cryogenic air separation: A process inwhich air is separated into componentgases by distillation at lowtemperatures
Lowest cost alternative for large scaleapplications
Single train production capacity (O2):3200 t/d
Recognized for high reliability
For IGCC, probably O2 storage only fora few hours operation
Major suppliers
Air Products
Air Liquide
BOC Gases
Praxair
Linde
Source: Air Products. 2800 t/d
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IGCC efficiency
While natural gas based CCs have efficiencies (LHV)
close to 60 %, coal based IGCCs have lower efficiencies
(below 45 % for the same technology level) Main reason is the gasification step where part of the
chemical energy in the coal (about 20-30%) is converted
to heat This heat is less efficiently converted to electricity than the
chemical energy in the produced syngas
Another factor is the work required for air separation IGCCs have no clear efficiency benefit compared to
supercritical pulverized coal plants
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IGCC improvement potential
Advances in several areas can potentially improve the
performance of future IGCC plants
Gasifiers
Dry feed gasifier with two stages
Refractory and feed injector lifetime
Coal feed and slag removal systems
Air separation Oxygen separating membranes (ionic transport membranes)
Gas turbines
Higher firing temperatures
Novel cycles including high temperature fuel cells
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According to a study*, a year 2020 IGCC plant could
be 49 % (LHV) efficient without capture and 43 %
efficient with capture
Without CO2capture With CO2capture
GE Shell 2020 plant GE Shell 2020 plant
Efficiency (%,LHV) 38.0 43.1 48.9 31.5 34.5 43.2
Capital cost ($/kW) 1187 1371 1129 1495 1860 1248
For the year 2020 plant, the study* assumed
Bituminous coal
A two-stage dry feed gasifier
A gas turbine more advanced than H-class
Supercritical steam cycle
Membrane air separation
* IEA GHG repor t PH4/19, 2003 (by Foster Wheeler)
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IGCC issues
Effect of coal quality
Most studies on bituminous coal (high rank)
Degree of integration (% of ASU air from GT) US demos: 0 %
European demos 100 %
Future plants: 25-50 % (probably) Gas clean up (sulfur and CO2)
2-stage Selexol, physical absorption seems to be
preferred Co-capture of sulfur and CO2 acceptable?
Gas turbines on hydrogen rich fuels
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IGCC Concluding remarks
Several IGCC plants have been demonstrated, all withgovernment support, private companies are now working
to commercialize the technology IGCC challenges
Demonstrate competitive capital cost and availability
IGCC benefits (over pulverized coal plants) Lower environmental impact, probably easier permitting
Lower cost option if CO2 capture (greenfield & retrofit)
Capture of CO2 introduces some minor technicalchallenges related to gas turbines on hydrogen rich fuels
For low rank coals such as lignite, less information onIGCC performance is available
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Thank you!