H2 Combustion in Power Production with CO2 captureus-norwaybilateral.com/content/2005-10-06_1_Oyvind-Langorgen.pdf2 Combustion in Power Production with CO 2 capture Øyvind Langørgen

1SINTEF Energy Research

H2 Combustion inPower Production with CO2 capture

Øyvind LangørgenSINTEF Energy Research

October 2005-”US Norwegian Late Summer school”

Contents

Pre-combustion CO2 captureTBO hydrogen test turbine

Tjeldbergodden methanol plantNatural gas power plantThe hydrogen test turbine

H2 CombustionKey challenges related to GTHydrogen propertiesCombustion fundamentalsStatus on GT hydrogen combustionResearch & Development

Summary

Courtesy of Alstom



Pre-combustion CO2 capture

ATR CO-shift CO2

removal

ASU

Steamturbine

HRSG

~Gas turbine

H2

CO2

Air Fluegas

Naturalgas

N2

O2

Air

Steam

Gasification CO-shift CO2removal

ASU

Steamturbine

HRSG

~Gas turbine

H2

CO2

Air Fluegas

Coal

N2

O2

Air

Steam

SO2removal

IRCC

IGCC

The primary fuel (coal, natural gas) is converted to a raw gas or synthesis gas consisting of CO, H2, CO2, CH4 and H2O

CO is shifted to CO2 and next CO2is separated at the elevated pressure prevailing in the reforming/gasification process (~30 bar)

The remaining hydrogen-rich gas is used as fuel in the power block (gas turbine, heat recovery steam generator and steam turbine)

Hydrogen content ~85% vol for the coal case and more than 90% vol for the natural gas case


Hydrogen test turbine at Tjeldbergodden

MotivationStatoil has proposed and made an application to build a 860 MW gas-firedpower plant at their Tjeldbergodden methanol plant (TBO)

A planned 30% extension of the existing methanol plant together withlimited power availability in the area initiated the idea

A ”purge gas” rich in hydrogen (> 85%) is available from the expandedmethanol plant

As part of the plans, Statoil was offering the opportunity for a gas turbinesupplier to install a hydrogen ”test turbine” of up to 25 – 30 MWe

Statoil goal: Show the state-of-art and further develop technology relatedto use of hydrogen-rich fuel gases in gas turbines


860MWMetanolEksp.




The methanol plant including extension:Production today 2550 MTPD, with extension 3300 MTPD

Steamreformer

Secondaryreformer

MeOH synthesis Distillation

Steam

Syngas compr.

Heat recovery/ Cooldown

Oxygen from Air Separation Unit

HP steamFeed water

MeOH

Natural Gas

Steamreformer


Syngas compr.

MeOH synthesis

Steam

Natural Gas

Existing Units/Sections

New Units/Sections

Recycle and fuel gases to exist. reformer sectionPurgegas

Fuel gas to new reformer section

Fuel gas

Steamreformer

Secondaryreformer

MeOH synthesis Distillation

Steam

Syngas compr.


Oxygen from Air Separation Unit

HP steamFeed water

MeOH

Natural Gas

Steamreformer


Syngas compr.

MeOH synthesis

Steam

Natural Gas


New Units/Sections


New Units/Sections

Recycle and fuel gases to exist. reformer sectionPurgegas

Fuel gas to new reformer section

Fuel gas



Proposed power plant consisting of:Two natural gas fired GT of 262MW and two HRSGOne steam turbine of 322MWOne hydrogen test turbine

Feed water to Methanol Plant

Purge gas

2 x HRSG triple

pressure

HRSG single

pressure

Steam TurbineGas Turbines

Natural gasAir

Air

Steam

Exhaust

N2 from ASU

HP IP LP

Condenser

HP Steam from Methanol Plant

Sea water


Purge gas

2 x HRSG triple

pressure

HRSG single

pressure


Natural gasAir

Air

Steam

Exhaust

N2 from ASU

HP IP LP

Condenser


Sea water



Power plant emissions

Natural gas power plant ~860MW 2.44 million tons of CO2About 5.5% of the total Norwegian CO2 emissions

Emissions to air

CO2 emissions

[tons/year]

NOx emissions

[tons/year]

NH3 emissions

[tons/year]

Methanol Capacity Expansion (excl. test turbine)

157 000 94 4.6 – 9.2

Power Plant (excl. test turbine) 2 440 000 1075 -

Capacity Expansion + Power Plant 2 597 000 1169 4.6 – 9.2

Existing Methanol Plant 353 000 400

Total emissions TBO 2 950 000 1569 4.6 – 9.2

(NOx emissions from power plant refer to 15 ppm in exhaust)



Norways CO2 emissions 2004: ~44 million tons (~10 tons per capita)




Purge gas

2 x HRSG triple

pressure

HRSG single

pressure


Natural gasAir

Air

Steam

Exhaust

N2 from ASU

HP IP LP

Condenser


Sea water


Purge gas

2 x HRSG triple

pressure

HRSG single

pressure


Natural gasAir

Air

Steam

Exhaust

N2 from ASU

HP IP LP

Condenser


Sea water


Hydrogen test turbine at TjeldbergoddenThe hydrogen-rich fuel gas at Tjeldbergodden (”purge-gas”)

Case 1: Non-purified purge gasCase 2: Purified purge gas using membranes

Case 1 Case 2

Composition Mole weight Mole % Weight % Mole % Weight %

Hydrogen (H2) 2.02 85.0 33.2 98.5 80.5

Carbon Monoxide (CO) 28 0.6 3.3 0.07 0.8

Carbon Dioxide (CO2) 44 1.1 9.4 0.71 12.6

Methane (CH4) 16.04 10.8 33.5 0.44 2.9

Water (H2O) 18.02 1.6 5.6 0.03 0.2

Methanol (CH3OH) 32.04 0.4 2.5 0.03 0.4

Nitrogen (N2) 28 1.6 8.7 0.16 1.8

Argon (Ar) 39.94 0.5 3.9 0.05 0.8

LHV [MJ/Sm3] 12.53 10.24

Fuel Heat [MW] 106. 77.

Pressure [bara] 35. 35.

Temperature [oC] 35. 90.


Hydrogen test turbine at TjeldbergoddenThe hydrogen-rich fuel gas at Tjeldbergodden (”purge-gas”)

The purge gas composition is highly relevant to IRCC or IGCC plants

Component TBO Case 1

TBO Case 2

ENCAP IRCC Natural Gas

ENCAP IGCC Hard Coal

ENCAP IGCC Lignite

H2 85.0 98.5 93.2 85.25 83.56

CO 0.6 0.07 0.66 4.84 0.61

CO2 1.1 0.71 0.5 0.5 0.10

CH4 10.8 0.44 3.74 0.01 7.16

H2O 1.6 0.03 0.51

CH3OH 0.4 0.03

N2 1.6 0.16 0.69 8.42 7.81

Ar 0.5 0.05 0.70 0.99 0.77

Temperature (°C) 35 90 50 25 25

Pressure (bar) 35 35 25.5 25.5 25.5



Three large gas turbine suppliers were involved

All of which have experience with IGCC plants without CO2 capture

They all pointed out the same goalTo burn high-hydrogen fuels in a clean, safe and reliable manner, withminimal or no diluent requirements



To make it short:

The hydrogen test turbine is not a part of the final power plant application

Available gas amount did not match GT suppliers strategies(they focus on large GT’s for hydrogen applications)

Uncertainties in scaling of results between small and large scale

Statoil has decided to focus on H2 production

(But, they may still discuss the possibilities for a hydrogen GT at TBO ifnew interest can be seen from the GT supplier side)


H2 combustionKey challenges related to GT

Pre-combustion CO2 capture requires that GT’s can cope withhydrogen-rich fuel in a safe and efficient way

Main challenges compared to natural gas combustion:Significantly higher flame temperature

higher NOx production

Large increase in volumetric fuel flow rates

Drastically reduced auto-ignition delay times

Ensure that flashback does not occur

A lot can be seen from the properties of hydrogen ( )


H2 combustionHydrogen properties vs. methane

Fuel properties Hydrogen MethaneDensity (kg/m3 at NTP) 0.09 0.71

Lower heating value on mass (MJ/kg) 119.91 50.03

Lower heating value on volume (MJ/Nm3) 10.23 33.95

Adiabatic flame temperature (K) 2380 2222

Flame speed in air at φ=1 (cm/s) 170 40.5Maximum flame speed (cm/s) 325 (φ=1.8) 42.0 (φ=1.1)

Flammability limits (vol-%) 4 - 75 5 – 15Flammability limits (equivalence ratio φ) 0.10 – 7.14 0.50 – 1.70Minimum spark ignition energy (mJ) 0.018 (φ=0.8) 0.28 (φ=0.9)

Autoignition temperature (°C) 400 – 572 537 – 632Autoignition delay time at 1000K and 17atm (msec.)

6.2 45.6


H2 combustionHydrogen properties vs. methane

0

50

100

150

200

250

300

350

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0Equivalence Ratio

Lam

inar

Fla

me

Spee

d (c

m/s

) Hydrogen

Methane

Flammability limits, flame speeds andignition energy


(H2) combustionFundamentals

Basic flame types(ordered with respect to premixedness and flow type)

Source: Warnatz et al. (1999)



Basic flame typesDiffusion burner (non-premixed, “conventional”)

Premixed burner



Combustion stoichiometry

Stoichiometric hydrogen-air reaction:H2 + 0.5(O2 + 3.76 N2) H2O + 1.88N2

Fuel rich - excess of fuel (example)2H2 + 0.5(O2 + 3.76 N2) H2O + H2 + 1.88N2

Fuel lean - excess of oxygen (example)0.5H2 + 0.5(O2 + 3.76 N2) 0.5H2O + 0.25O2 + 1.88N2

Lean premixed combustion do have oxygen excessNote! Overall stoichiometry may not be the same as the local flame stoichiometry



NOx emissions propensityTemperature and time

Stoichiometry of fuel-air mixture

Degree of premixedness


Lean premixed combustion isfavourable with respect to NOx(ref. DLN/DLE GT burners)

DrawbacksPre-ignition of the flammable mixture

Flashback

Flame stability and combustion dynamics (“noise”)

Lean premixed hydrogen combustion is a huge challenge related topre-ignition and flashback

No DLN/DLE burners exist today for hydrogen-rich fuels


(MJ/Sm3)(MJ/Sm3)

(MJ/Sm3)

0.5


H2 combustionStatus

Gas turbines with diffusion combustion commercially available

Many references in IGCC, refineries etc.

SG=syngas; WG=Waste Gas; RFG=Refinery Gas; Steel=COG+BFG; TG=Tail gas; PG=Process gas

Site Model No. Gas FeaturesZarqa Refinery PGT10 1 RFG 82% H 2

Georgia Gulf MS7001EA 3 Blend Methane+ 50% H 2

BASF/ Geismer MS600B 1 PG Up to 80% H 2

Koch Refinery MS6001B 1 RFG 12% to 50% H 2

Daeson II Korea MS6001B 1 PG up to 95% H2

Tenerife MS6001B 1 RFG ~70% H 2

Cartagena MS6000B 1 RFG 66% H 2

BASF/ Ludwigshafen LM5000 1 RFG 62.5% H 2 30.5% CO

DOW/ Stade LM5000 3 PG 50% CH 4/H2 blend

San Roque MS6000B 2 RFG 70% H 2

Schwarze Pumpe MS6001B 1 SG 65% H 2

Site Model No. Gas FeaturesZarqa Refinery PGT10 1 RFG 82% H 2

Georgia Gulf MS7001EA 3 Blend Methane+ 50% H 2

BASF/ Geismer MS600B 1 PG Up to 80% H 2

Koch Refinery MS6001B 1 RFG 12% to 50% H 2

Daeson II Korea MS6001B 1 PG up to 95% H2

Tenerife MS6001B 1 RFG ~70% H 2

Cartagena MS6000B 1 RFG 66% H 2

BASF/ Ludwigshafen LM5000 1 RFG 62.5% H 2 30.5% CO

DOW/ Stade LM5000 3 PG 50% CH 4/H2 blend

San Roque MS6000B 2 RFG 70% H 2

Schwarze Pumpe MS6001B 1 SG 65% H 2

Site Model No. Gas FeaturesAntwerpen MS6000B 1 RFG 78% H 2

Puertollano MS6000B 2 RFG Up to 60% H2

La Coruna MS6000B 1 RFG Up to 52% H2

Rotterdam MS6000B 1 RFG 59% H 2

AGIP/ Milazzo MS5001P 1 RFG 30% to 50% H 2

Cochin Refineries MS5001P 1 RFG 50% H 2

Mobil/ Paulsboro MS5001P 2 RFG 20% to 60% H 2

Shell Int'l MS5001P 1 RFG 60% H 2, propane

Reutgerswerke MS3002J 1 PG 60% H 2

Uhde NUP MS3002J 1 TG ~60% H 2

Donges GE10 1 RFG 76% H 2

Site Model No. Gas FeaturesAntwerpen MS6000B 1 RFG 78% H 2

Puertollano MS6000B 2 RFG Up to 60% H2

La Coruna MS6000B 1 RFG Up to 52% H2

Rotterdam MS6000B 1 RFG 59% H 2

AGIP/ Milazzo MS5001P 1 RFG 30% to 50% H 2

Cochin Refineries MS5001P 1 RFG 50% H 2

Mobil/ Paulsboro MS5001P 2 RFG 20% to 60% H 2

Shell Int'l MS5001P 1 RFG 60% H 2, propane

Reutgerswerke MS3002J 1 PG 60% H 2

Uhde NUP MS3002J 1 TG ~60% H 2

Donges GE10 1 RFG 76% H 2

H2 combustionStatus

Kilde: www.powergeneration.

siemens.com



H2 combustionStatus

When operating with diffusion combustion, NOx can be controlled by steam and/or nitrogen dilution


H2 combustionStatus

Drawbacks with dilutionHigher complexity

Increased volumetric flows

Diluents availability

Nitrogen compression

Steam losses

Water treatment

Hot section material integrity

GT suppliers define lean premix hydrogen combustion (DLN/DLE) with a minimum of dilution as the goal (for example as in the EU ENCAP project with both Alstom and Siemens participating)


H2 combustionResearch and developmentSequence of different approaches:

System analysisTheoretical combustion analysisReactor modeling of the combustion1-D flame calculationsComputational Fluid Dynamics (CFD)(DNS – ”Numerical experiments”)

Laboratory scale atmospheric combustorsFull-scale atmospheric combustor testsFull-scale pressurised combustor testsFull-scale engine test


H2 combustionResearch and development

System analysis: GT PRO 13.0 Petter E. Røkke

383 06-07-2004 12:47:24 file=C:\Tflow13\MYFILES\h2_tbo_2004-06-07.gtp

Net Power 33446 kWLHV Heat Rate 7773 kJ/kWh

p[bar], T[K], M[kg/s], Steam Properties: Thermoflow - STQUIK

1X SIE GT 10B

24787 kW

1.01 p 288 T 60 %RH 76.78 m 0 m elev.

1 p 288 T 76.78 m

Case 1 1.242 m

351 T 298 TLHV= 72214 kWth

14.18 p 657 T

13.61 p 1455 T

78.02 m

1.04 p 819 T 78.02 M

73.51 %N2 14.04 %O2 1.147 %CO2+SO2 10.42 %H2O 0.8853 %Ar

817 T 78.02 M

817 777 777 538 496 496 496 454

421 T 78.02 M

9908 kW

0.0058 M

FW

0.0689 p 312 T 11.69 M

312 T

1.185 p 366 T 11.82 M

LTE

312 T 11.82 M

366 T 1.185 p 378 T

12.05 M

36.97 p 448 T 12.05 M

HPE1

36.42 p 513 T 12.05 M

HPE3

36.42 p 518 T 11.93 M

HPB1

35.19 p 625 T 11.7 M

HPS3

34 p 623 T 11.7 M

35.19 p 625 T

0.234 M



System analysis:TBO case 1 and 2 with Siemens GT10B

GT10B GT10B

Fuel Diluent

Natural gas None

C1 N2

C1 N2+H2O

C2 N2

C2 N2+H2O

GT Power kW 24630 26634 27294 26090 27270 ST Power kW --- 9099 10182 8361 10140 Total kW --- 35733 37476 34451 37410 GT Efficiency %

34.2 36.22 35.65 36.57 35.81

CC Efficiency %

--- 48.59 48.95 48.29 49.13

PR - 14.0 15.2 14.9 15.2 14.8 TIT K 1455 1395 1435 1364 1445 TET K 815 777 808 757 810 M_ex kg/s 80 85 82 86 81



1000/T [K-1]

τ ign

[µs]

0.8 0.9 1 1.1101

102

103

104

105

BhashkaranGRI-MechWarnatzO ConaireLeedsLi

Reactor modeling:

Reactor modelingof ignition delay

H2/airΦ = 12.5 atm



No Reaction A n E 1 H+O2=O+OH 3.55E+15 -0.4 16599 2 O+H2=H+OH 5.08E+04 2.7 6290 3 H2+OH=H2O+H 2.16E+08 1.5 3430 4 O+H2O=OH+OH 2.97E+06 2.0 13400 5 H2+M=H+H+M 4.58E+19 -1.4 104380 6 O+O+M=O2+M 6.16E+15 -0.5. 0 7 O+H+M=OH+M 4.71E+18 -1.0. 0 8 H+OH+M=H2O+M 3.80E+22 -2.0. 0 9 H+O2(+M)=HO2(+M) k∞ 1.48E+12 0.6. 0 k0 6.366E+20 -1.72 524.8 10 HO2+H=H2+O2 1.66E+13 0 823 11 HO2+H=OH+OH 7.08E+13 0 295 12 HO2+O=O2+OH 3.25E+13 0 0 13 HO2+OH=H2O+O2 2.89E+13 0 -497 14 HO2+HO2=H2O2+O2 4.20E+14 0 11982 HO2+HO2=H2O2+O2 1.30E+11 0 1629.3 15 H2O2(+M)=OH+OH(+M) k∞ 2.95E+14 0 48430 k0 1.202E+17 0 45500 16 H2O2+H=H2O+OH 2.41E+13. 0 3970 17 H2O2+H=HO2+H2 4.82E+13. 0 7950 18 H2O2+O=OH+HO2 9.55E+06 2.0 3970 19 H2O2+OH=HO2+H2O 1.00E+12 0 0 H2O2+OH=HO2+H2O 5.80E+14 0 9557

Reactor modeling:

A chemical kineticmechanism is needed

Example: Li et. al 2004



1-D flame calculations:

Flame SpeedPREMIXH2/air1 atm

Φ

SL

[cm

/s]

0 1 2 3 4 50

50

100

150

200

250

300

LiO ConaireGRI-Mech

KwonTse

Computationalgrid

Computationalgrid

Combustor schematic(GE CFM56)

Simulation results, temperature and NOx:


Computational fluid dynamics:

Numerical grid

Temperature (K)24002200200018001600140012001000800

NO4.00x10-04

3.50x10-04

3.00x10-04

2.50x10-04

2.00x10-04

1.50x10-04

1.00x10-04

5.00x10-05

0.00x10+00

Natural gas

fuel

air

Temperature (K)24002200200018001600140012001000800

NO4.00x10-04

3.50x10-04

3.00x10-04

2.50x10-04

2.00x10-04

1.50x10-04

1.00x10-04

5.00x10-05

0.00x10+00

Hydrogen








Models are needed in order to solve the equationsTurbulence model (e.g. k-ε model)

Combustion model (e.g. Eddy Dissipation Concept - EDC)

Radiation model

Model for reaction kineticsDetailed mechanismsReduced mechanismsOne-step chemistryEquilibriumInfinitely fast reactions



Experimental methods:

KK


Experimental methods:

-0.025 0 0.0250

0.05

0.1

0.15

0.2

0.25

0.3a b

-0.025 0 0.0250

0.05

0.1

0.15

0.2

0.25

0.3

-0.025 0 0.0250

0.05

0.1

0.15

0.2

0.25

0.3c

Φ=0.3 0.5 0.9


Documents

H2 Combustion in Power Production with CO2 captureus-norwaybilateral.com/content/2005-10-06_1_Oyvind-Langorgen.pdf2 Combustion in Power Production with CO 2 capture Øyvind Langørgen