biomass gasification systems for electric power ... · biomass gasification systems for electric...

1

Biomass Gasification Systems for Electric Power, Cogeneration,

Liquid Fuels, and Hydrogen

Eric D. LarsonResearch Engineer, Ph.D.

Princeton Environmental InstitutePrinceton University

GCEP Biomass Energy WorkshopStanford University

27 April 2004

2

Main Points• Gasification-based conversion enables biomass to meet a wide

range of needs, including transport fuels.• If carbon-neutral biomass is to play a major role in future energy

systems, dedicated energy crops will be needed.• Conversion facilities with larger scales than traditionally considered

for biomass are needed for possibility of cost-competitiveness. • Large-scale biomass conversion facilities are feasible.• Co-production of two or more products (electricity, fuels, heat,

and/or chemicals) will generally provide best economics.• Producing clean synthesis gas from biomass accounts for typically

two-thirds of cost of final product(s) – cost reductions most important in these areas.

• Most components for processing of clean syngas are commercial or nearly so.

• Continuing systems analysis effort needed to understand potential benefits of any R&D efforts.

3

Transportation Services Per Hectare with Different Biomass Fuels

Hydrogenfromwood

Methanolfromwood

HydrogenfromwoodMethanol

fromwood

RapeMethylEster

Ethanolfrom corn

Ethanolfromwood

(advanced)

Ethanolfromwood

(advanced)

Ethanolfrom cane

0

25

50

75

100

125

150

175

200

225

250

1000

veh

icle

-km

/ha/

year

Internal Combustion Engine Vehicle

Fuel Cell VehicleNote: “wood” is short-rotation intensive culture plantation wood

4

Is Large-Impact, Large-Scale Biomass Conversion Feasible?

• Yes, but energy plantations with high yields are needed for logistics and costs.

• Efficient conversion and end-use are also essential.

0

10

20

30

40

50

60

70

80

90

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Percent of circular area planted

Radi

us o

f circ

ular

are

a, k

m

10152025

Yield on planted area

(dt/ha/yr)

Radius for 5000 dry t/day biomass supply (~1000 MWb)

Typical Iowa corn density

5

Thermochemical Conversion Routes

Electricity or Heat & Electricity

Synthesis

Conversion

Fuel Cell

Pressurized O2Gasification + Gas

Cleanup co-production

Chemicals,H2

Transport Fuels

Air Separation

Unit

Gas Turbine CC

• Gasifier designs best suited for downstream syngas conversion are pressurized, with partial oxidation (O2) or indirect heating.

• Energy efficiencies and economics typically will be favored with multiple products from same facility and at larger scales.

6

Key Technical Features Assumed for “Mature” Conversion Facilities

• Reliable biomass feeding to large-scale pressurized gasifier.

• High reliability commercial gasifier operation.• Gas cleanup to specifications for downstream

processing (tar, particulates, alkali, sulfur and other trace contaminants).

• Good gas turbine performance on low heating value gases.

• Good process heat integration and control.• No major cost reductions other than currently

foreseeable ones and due to scale effects.

7

Feeder

Ceramic Filter

Biomass

1

BiomassBiomass

1

Steam

Water

Steam

Water

Syngas Cooler

Feed Preparation

Feed Preparation

Gasifier Island

18

Gasifier 29.86 bar

Tar cracking

Gasifier 29.86 bar

Tar cracking

Nitr

ogen

C

ompr

esso

r

N2 Boost Compressor

Nitrogen

Oxygen

Oxygen Compressor

Air

Integrated ASU

Integrated ASU

Gas Cleanup

Raw syngas

Air Separation

10

15

Ash

Particulates

Steam

92

3

11

~~ Steam Turbine

Deaerator1.5 bar

Condenser0.5 bar

Power Island

19

HPLP IP

HRSGSteam reheat

HRSGSteam reheat

4

8

14

5 16

12

T (°C) P (bar) m (kg/s)1 25 1.013 65.62 234 31.65 13.83 1008 28.82 99.74 350 28.24 99.75 350 26.83 99.76 25 1.013 571.77 495 19.76 541.68 366 19.36 76.79 8 16.83 18.0

10 86 31.36 17.511 86 31.360 0.512 8 3.20 39.113 182 20.41 39.114 40 20.00 5.315 101 31.40 5.316 475 20.00 33.817 1370 19.17 598.418 650 1.07 628.419 90 1.013 628.4

~~6

Air

7

Leakage

17 267.5 MW

Gas Turbine

Cooling

188.9 MW

to Stack

H2CO CO2H2O CH4N2Ar others

20.3%15.0%23.1%28.2%

8.1% 4.7% 0.4% 0.2%

H2CO CO2H2O CH4N2Ar others

20.3%15.0%23.1%28.2%

8.1% 4.7% 0.4% 0.2%

13

O2N2Ar

95.0%2.0% 3.0%

O2N2Ar

95.0%2.0% 3.0%

O2N2Ar

1.1% 98.5%

0.4%

O2N2Ar

1.1% 98.5%

0.4%

Purge

SyngasLHV HHV

13.3 MJ/kg14.2 MJ/kg

LHV HHV

13.3 MJ/kg14.2 MJ/kg

Large Biomass IGCC Performance

Higher heating value (HHV) 983.2 Switchgrass input, MWth Lower heating value (LHV) 886.8

ASU powera -5.8 O2 compressor power 1.3 N2 compressor power 10.8 N2 boost compressor power 0.3 Steam cycle pumps, total 3.5 Fuel handling 0.7 Lock hopper/Feeder 4.2

Internal power use, MWe

Total on-site use 14.9 Gas turbine output 267.5 Steam turbine gross output 188.9 Gross power

output, MWe Total gross output 456.4 Net Power, MWe 441.5

Higher heating value (HHV) 44.9% Electricity efficiency, % Lower heating value (LHV) 49.8%

Switchgrassinput = 983 MWhhv

Net electric output =442 MWe

Efficiency (HHV) =45%

8

Performance Summary(for 5000 dry st/d biomass)

Note: BIGSOFC is ~2 points more efficient than BIGCC, but capital cost for sulfur removal + SOFC combined must be ~ $350/kW to compete with BIGCC.

B-IGSOFC Steam cycle

Gasifier design Indirectly heated

Pressurized, O2 blown

Pressurized, O2 blown

Boiler (no gasifier)

Gross electricity outputGas turbine, MW 264 267 -- -- Free turbine, MW -- -- 102 --

Steam turbine, MW 201 190 150 306Fuel cell, MW -- -- 330 --TOTAL, MW 465 458 582 306

On-site consumption MW 35 15 119 11Net electricity, MW 431 442 463 295

Net electric efficiency, % HHV 43.8% 45.0% 47.1% 30.0%% LHV 48.6% 49.9% 52.3% 33.2%

B-IGCC

5,670 raw metric tonnes/day (20% moisture content)Biomass input (983 MWHHV, 887 MWLHV)

9

Future Nth B-IGCC Power Costs

• Pressurized oxygen-blown gasifier with gas turbine combined cycle• Biomass-to-power efficiency: 45% HHV (49/9% LHV)• 15% capital charge rate; 85% capacity factor

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

0.10

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 Biomass Feed, dry tonne/day

Cos

t of E

lect

ricity

, 200

3 $/

kWh

500

700

900

1100

1300

1500

1700

1900

2100

2300

25000 200 400 600 800 1000 1200 1400 1600 1800

Biomass Feed, MW HHV

Ove

rnig

ht C

ost,

2003

$/k

W

$2.1/GJ

$3.4/GJ

$3.0/GJ

Plant-gate biomass price

5000 short tons per day

10

Cogeneration Economics

Gasifier Gas Cooling& Cleaning

H2S Capture& S recovery

Gas Turbine

HRSG(w/duct burner)

SteamTurbine

blackliquor

clean syngas

condensed phaseto causticizing sulfur to

pulping liquorpreparation

electricity electricity

processsteam

natural gas (if needed)

steam from hog fuel boiler

rawsyngas

BLGCC



Gas Turbine

HRSG(w/duct burner)

SteamTurbine

blackliquor

clean syngas




processsteam



rawsyngas

BLGCC



Gas Turbine

HRSG(w/duct burner)

SteamTurbine

blackliquor

clean syngas




processsteam



rawsyngasGasifier Gas Cooling

& CleaningH2S Capture& S recovery

Gas Turbine

HRSG(w/duct burner)

SteamTurbine

blackliquor

clean syngas




processsteam



rawsyngas

BLGCC

QuenchWater

950 °CPressurizedEntrainedFlow Reactor

Syngas

Black Liquor

GreenLiquor

Oxygen

QuenchWater

950 °CPressurizedEntrainedFlow Reactor

Syngas

Black Liquor

GreenLiquor

Oxygen

High-Temperature Gasifier

• Pressurized, O2-blown, smelt-phase solids removal, ~ 50% of sulfur leaves in gas phase, lower-energy product gas (~ 9 MJ/kg).

• Chemrec leading developer

Low-Temperature Gasifier

• Steam reforming, atmospheric pressure, dry solids removal, ~ 90% of sulfur leaves in gas phase, higher-energy product gas (~ 21 MJ/gk).

• MTCI is leading developer

11

BLGCC Energy Balances Tomlinson BLGCC BASE HERB Low-Temp Gasifier High-Temp GasifierFUEL INPUTS, MW (HHV) Mill by-product fuels 508.8 508.8 457.7 457.7 Black liquor to gasifier 437.6 437.6 391.1 391.1 Woody mill residues 71.2 71.2 66.6 66.6 Purchased fuels 33.1 33.1 148.7 85.9 Off-site wood wastes (MW, HHV) 0 0 33.4 33.4 Natural gas (MW, HHV) -- -- 67.6 14.3 Lime kiln #6 fuel oil (MW, HHV) 33.1 33.1 47.7 38.2 TOTAL FUEL INPUTS, MW (HHV) 541.9 541.9 606.4 543.6 STEAM TO PROCESS, MW 212.1 213.3 200.2 200.2 NET ELECTRICITY PRODUCED, MW 64.3 88.6 122.1 114.7 Power-to-Heat Ratio 0.30 0.42 0.61 0.57 Excess power available for export - 35.8 - 11.5 22.0 14.6 EFFICIENCIES (HHV basis) (Steam + Electricity)/(Total fuel input) 0.510 0.557 0.531 0.579 (Net Electricity Output)/(Total fuel input) 0.119 0.163 0.201 0.211 Efficiency of purchased fuel usea (%) -- -- 0.500 0.955 (a) Defined for the BLGCC cases as the net electricity produced in excess of Tomlinson BASE electricity output divided by the

difference in total purchased fuel between the BLGCC case and the Tomlinson BASE.

12

0% 5% 10% 15% 20% 25% 30% 35%

$50/metric tonne carbon premium + $2000/ton NOx allowance credit

$2000/ton NOx allowance credit

$50/metric tonne carbon premium

$10/metric tonne carbon premium

$25/MWh green premium + $18/MWh PTC

$15/MWh green premium + $18/MWh PTC

$18/MWh, 10-year production tax credit on incremental renew able energy

$25/MWh "Green" premium on incremental renew able energy

$15/MWh "Green" premium on incremental renew able energy

No environmental credits

IRR of incremental capital investment Relative to Tomlinson BASE (%)

Prospective BLGCC Economics(high-temp gasifier)

13

Syngas-to-Liquids Processes

SyngasCO + H2

Methanol

H2OWGSPurify

H2N2 over Fe/FeO

(K2O, Al2O3, CaO)NH3

Cu/ZnOIsosynthesis

ThO2 or ZrO2

i-C4

Alkali-doped

ZnO/Cr2 O

3

Cu/ZnO; Cu/ZnO/Al2 O3

CuO/CoO/Al2 O3

MoS2

MixedAlcohols

Oxosynthesis

HCo(CO)4

HCo(CO)3 P(Bu3 )

Rh(CO)(PPh3 )3

AldehydesAlcohols

Fischer-Tropsch

Fe, C

o, R

u

WaxesDiesel

OlefinsGasoline

Ethanol

Co, Rh

FormaldehydeAg

DME

Al 2O

3

zeolites

MTOMTG

OlefinsGasoline

MTBEAcetic Acid

carb

onyla

tion

CH3O

H +

COCo

, Rh,

Ni

M100M85DMFC

Direct Use

hom

olog

atio

nCo

isob

utyl

ene

acid

ic io

n ex

chan

ge

Graphics courtesy of Richard Bain, NREL

14

Thermochemical Fuels (TCF)Fischer-Tropsch Liquids

(straight-chain CnH2n , CnH2n+2)

• F-T fuels are commercially made from natural gas and (in S. Africa) from coal.

• F-T process dates to 1930s• Improved yields and

selectivity desirable.• Commercial fuel interest

today is primarily in the middle distillate fraction, a high-cetane, no-sulfur diesel fuel substitute.

• The process also gives a naphtha fraction (chemical feedstock) and heavy waxes (high-value, small market).

Dimethyl Ether(CH3OCH3)

• Ozone-safe aerosol propellant, chemical feedstock.

• Current global production < 150,000 tons/year by drying methanol (CH3OH).

• Similar to LPG – mild pressurization needed to keep as liquid.

• Good diesel-engine fuel: high cetane #, no sulfur, lower NOx, no C-C bonds

no soot.• Growing interest

(especially in Japan & China) for using DME for cooking & heating.

Hydrogen(H2)

• Intense H2 interest today.• Preferred fuel for a fuel

cell vehicle.• Low or no tailpipe

emissions of criteria pollutants or CO2.

• Low volumetric energy density presents challenge for on-board storage.

Methanol(CH3OH)

• Fuel cell vehicle fuel via onboard reforming.

• Health concerns as fuel.• Chemical feedstock.

15

Synthesis of Liquids from CO+H2

• Three reactor designs:– Fixed-bed (gas phase): low one-

pass conversion, difficult heat removal

– Fluidized-bed (gas phase): better conversion, but more complex operation

– Slurry-bed (liquid phase): much higher one-pass conversion due to easy thermal control

• Basic overall reactions:

TYPICAL CONDITIONS:P = 50-100 atm.T = 200-300oC

Methanol

Dimethyl ether

Fischer-Tropsch liquids

322 OHCHHCO ⇔+

233233 COOCHCHHCO +⇔+

222 H O- C2HCO +⇔+ H -

Synthesis gas(CO + H2)

Cooling water

SteamCatalystpowderslurriedin oil

Disengagementzone

Fuel product (vapor)+ unreacted syngas

Synthesis gas(CO + H2)

Cooling water

SteamCatalystpowderslurriedin oil

Disengagementzone

Fuel product (vapor)+ unreacted syngas

catalystCO

H2

CH3OCH3CH3OHCnH2n+2(depending on catalyst)

catalystCO

H2

CH3OCH3CH3OHCnH2n+2(depending on catalyst)

16

Cross hatched area indicates a range of numbers; Dots are the specific values from different studiesLight green indicates higher level of uncertainty

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

nat gas coal biomass nat gas coal biomass nat gas biomass nat gas biomass nat gas biomass biomass(via

syngas)

GJ

of p

rodu

ct/G

J of

feed

(LH

V ba

sis)

Corn

Hydrogen MeOH FTL-diesel

Olefins EtOHMixed Alcohols

(30%MeOH)

Yields for Single-Product Facilities

Courtesy of Richard Bain, NREL

• Relatively large-scale required, with good heat integration, for reasonable efficiencies.

Waxes

DieselNaphtha

ParaffinsOlefins

Sample F-T synthesis fractions

17

Foss

il en

ergy

ratio

(Epr

oduc

t/Efo

ssil)

biomass(via

syngas)

0.1

1

10

100

nat gas coal biomass nat gas coal biomass nat gas biomass nat gas biomass nat gas biomass corn

Hydrogen MeOH FTL Olefins EtOHMixed Alcohols

• Life Cycle = cradle-to-grave including feedstock production• Energy Ratio = Fuel energy out/Fossil energy in (LHV basis)

Note: Log scale

Life Cycle Fossil Energy RatioCross hatched area indicates a range of numbers; Dots are the specific values from different studiesLight green indicates higher level of uncertainty


18

Co-Production of ThermochemicalFuel (TCF) and Electricity

Gasification “Once-Thru”Synthesis

Power IslandExportElectricity

TCF Water Gas Shift

ASU airoxygen

SeparationGas Cooling& Cleanup

unconvertedsynthesis gas

biomass

processelectricity

H2S, CO2Removal

• Fuel-plus-electricity efficiency is comparable to efficiency of single-product plants, but value of outputs can vary.

-0.10

-0.05

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

0.02 0.025 0.03 0.035 0.04 0.045

$/lit

er g

asol

ine-

equi

vale

nt (i

n ye

ar-2

002

US$

)

Wholesale price of regular grade gasoline (90 octane) in Beijingon 9 February 2003, when world crude price was about $30/bbl.

With co-product electricity

Stand-alone methanol

Breakeven electricity sale price between co-production and stand-alone

Electricity Sale Price, $/kWh

Met

hano

l Cos

t$

per l

iter o

f gas

olin

e eq

uiva

lent

(200

2$)

-0.10

-0.05

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

0.02 0.025 0.03 0.035 0.04 0.045

$/lit

er g

asol

ine-

equi

vale

nt (i

n ye

ar-2

002

US$

)

Wholesale price of regular grade gasoline (90 octane) in Beijingon 9 February 2003, when world crude price was about $30/bbl.





Met

hano

l Cos

t$

per l

iter o

f gas

olin

e eq

uiva

lent

(200

2$) Wholesale price of regular grade gasoline (90 octane) in Beijing

on 9 February 2003, when world crude price was about $30/bbl.





Met

hano

l Cos

t$

per l

iter o

f gas

olin

e eq

uiva

lent

(200

2$) Estimated plant-gate cost of

methanol from coal in China: Texaco gasifier, with Yanzhoubituminous coal. APCI liquid phase synthesis. 60% China location factor on total installed capital cost (except for gas turbine in co-product case). Coal @ $24/t ($1.1/GJ). $20/t sulfur credit. 11% capital charge rate. 85% capacity factor. Annual O&M cost of 4% of initial capital. Cost of MeOH per liter gasoline equivalent assumes 10% higher efficiency for a neat-MeOH engine compared to a gasoline engine.

19

Feeder

Ceramic Filter

Biomass

Steam

WaterSyngas Cooler

Feed Preparation

Gasifier Island

Gasifier 29.86 bar

Internal Tar cracking

Nitrogen Compressor

Oxygen Compressor

Air

Integrated ASU

Gas Cleanup

Air Separation

Ash

Particulates

Steam

~Steam

Turbine

Deaerator1.0 bar

Condenser0.05 bar

Power Island

HPLP IP

HRSGSteam reheat

~AirLeakage

156.5 MW

Gas Turbine

Cooling

150.9 MW

to Stack

Purge

External Tar Cracker

Rectisol unit

CO2Compressor

Water

Steam

Syng

as

Com

pres

sor

To acid gas

treatment

Nitrogen

Oxygen

Product Separation Liquid-phase DME

Synthesis Reactor

Dehydration Reactor

DME to storage

Raw syngasClean syngas

Recycled methanol

Methanol

Wastewater to treatment

Synthesis IslandUnc

onve

rted

syng

as

Once-Through DME Production with Electricity Co-Product

20

0

5

10

15

20

25

0 0.01 0.02 0.03 0.04 0.05 0.06

Electricity price ($/kWh)

Cos

t of D

ME

(200

3$)

($/G

J, H

HV)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

Cos

t of D

ME

(200

3$)

($/g

allo

n di

esel

equ

ival

ent)

$2.1/GJ

$3.4/GJ

$3.0/GJ

Plant-gate biomass price

Input: 5000 dry st/d biomass (983 MW, hhv)Output: 244 MWDME,hhv + 278 MWe

Once-Through DME from Biomass with Electricity Co-Product

(draft Princeton results)

21

Syngas generation accounts for 50-75% of cost (all cases).

(excl. dist., marketing, & taxes)

(excl. excise tax credit)

Literature Cost Estimates


0

5

10

15

20

25

30

35

40

frombiomass

H2 frombiomass

MeOH frombiomass

diesel/ gasoline

frombiomass

(30% MeOH)

frombiomass

propylene frombiomass

(viasyngas)

corn

Prod

uct

Cos

t ($/

GJ,

LH

V)

biomass derived product pricecommercial product price

Dots are values from different studies

Hydrogen MeOH FTL

Olefins EtOH

Mixed Alcohols Higher level of

uncertainty

Biomass price = $1.5/GJ; 2000 dt/d biomass feed rate

22

Main Points• Gasification-based conversion enables biomass to meet a wide

range of needs, including transport fuels. • If carbon-neutral biomass is to play a major role in future energy

systems, dedicated energy crops will be needed.• Conversion facilities with larger scales than traditionally considered

for biomass are needed for possibility of cost-competitiveness. • Large-scale biomass conversion facilities are feasible.• Co-production of two or more products (electricity, fuels, heat,

and/or chemicals) will generally provide best economics.• Producing clean synthesis gas from biomass accounts for typically

two-thirds of cost of final product(s) – cost reductions most important in these areas.

• Most components for processing of clean syngas are commercial or nearly so.

• Continuing systems analysis effort needed to understand potential benefits of any R&D efforts.

biomass gasification systems for electric power ... · biomass gasification systems for electric...

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