IGCC - Integrated Gasification Combined Cycle

8/10/2019 IGCC - Integrated Gasification Combined Cycle

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2Gas Technology Center NTNU - SINTEF

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


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!

Documents

IGCC - Integrated Gasification Combined Cycle