Commercializing New Biomass Energy Technologies

1

Commercializing New Biomass Energy Technologies

Eric D. LarsonPrinceton Environmental Institute

Princeton UniversityUSA

International Society of Sugar Cane TechnologistsInternational Sugarcane Biomass Utilization Consortium

Third Meeting, 28 June – 1 July, 2009Shandrani Resort, Mauritius

2

My goals in this talk

• Discuss context for a new sugarcane-biomass energy technology initiative.

• Overview of thermochemical and biochemical biomass conversion technologies.

• Discuss gasification-based technologies and economics, including co-gasification of biomass with coal and CO2 capture and storage.

• Provide some technology cost and performance estimates that might be useful for “back-of-envelope” project calculations.

• Wrap-up thoughts/questions for further ISBUC discussions.

3

What Future Oil Prices ?

Low Price, Reference Case, and High Price projections are from the U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook 2009 (March 2009). Subsequently (April 2009) EIA revised Reference Case projection to reflect expectation that world recession would last longer than expected in AEO 2009.

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Historical Data

High Price Case

Reference Case

Revised Rerference Case

Low Price Case

> $100/bbl by 2012-2015

4

Climate Change Issues/Opportunities

• To avoid dangerous climate change (ΔT > 2oC), global GHG emissions by 2050 must be:– ½ current emissions level, or– Less than ¼ of projected 2050

“business-as-usual” emissions.• IEA projects GHG emissions

price in 2030 in OECD:– $90/t for 550 ppmv stabilization– $180/t for 450 ppmv stabilization

• Biomass will become much more valuable (including possibility for negative GHG emissions when biomass is used with CO2 capture and storage (CCS).

Source: International Energy Agency, Energy Technology Perspectives, 2008

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Power sector

Industry

Buildings

Transportation

Business-as-usual emissions 62 GtCO2eq

Targeted emissions 14 GtCO2eq

GHG Emissions, Gt CO2 equivalent per year

2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

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Intergovernmental Panel on Climate Change on CCS

• Based on observations and analysis of current CO2 storage projects (several storing ~106 tCO2/yr), natural systems, engineering systems, and models:

– CO2 injected underground is very likely to stay there for > 100 yrs. – CO2 injected underground is likely to stay there > 1000 yrs.

• Large potential for CO2 storage in deep sedimentary basins

Prospects for Holding CO2

Highly ProspectiveLow to High Prospective

Non Prospective

Source: B. Metz, O.Davidson, H. de Coninck, M. Loos, and L. Meyer (eds.), Figure SPM.6b in “Summary for Policymakers,” IPCC Special Report on Carbon Dioxide Capture and Storage,Cambridge University Press, Cambridge, 2005.

6

Parallels Between Coal IGCC and BIG/GT Development?

• Coal gasification proponents say coal-IGCC is superior to conventional technology options:

– higher efficiency than conventional coal power plants.– Inherently much lower air emissions than conventional power plants.– electricity generating cost in U.S. not higher than new conventional coal plant.

• But IGCC is not a routine commercial option for new coal power (despite first major demonstration in 1970s) because:

– Conventional plants can meet emissions regulations with add-on investments.– Many existing coal plants are already paid off (esp in U.S.), so existing

generating costs are much lower than for a new conventional coal plant.– IGCC experience is not yet sufficient to ensure low level of risk that goes with

new conventional coal plant.• Lesson: new technology must offer significantly better economics or

opportunity to justify taking risks needed to establish it in market.– Coal gasification is widely practiced in China, but for chemicals.– Analogy: the PC did not replace the typewriter because it significantly

improves typing – it provides many other benefits.

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New context for thinking about sugarcane biomass energy

• High oil (and natural gas) prices likely to be sustained– energy insecurity in U.S. and China are driving big

investments in new technologies for transport fuels from biomass and coal.

– Some major private sector players are getting involved, e.g. Shell, BP, GE, Sasol, others.

• Awareness of need for urgent action on climate change is growing rapidly (COP 15 - Copenhagen will continue to build this awareness).

• Gasification power from biomass that has only marginal economic benefits may not be compelling enough reason for commercializing biomass gasification – liquid fuels or co-production appear more promsing.

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Basic Biomass Conversion Options

Biochemical

BCombustion

Gasification

D

Ethanol

Electricity

Electricity

Alt. Liquid fuels

Bagasse, Trash

advanced technology options

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Biochemical conversion of biomass

• Current technology– Separate pretreatment hydrolysis using purchased enzymes (cellulases) to liberate

C5 and C6 sugars C6 fermentation.– C5 fermentation has been demonstrated at pilot scale.

• Near future technology– Pretreatment + combined enzyme hydrolysis and fermentation

• More future technology– Consolidated bioprocessing: one reactor for enzyme production, hydrolysis,

fermentation.

Pretreatment

FermentationRecovery &Distillation

Enzymeproduction

Solidsseparation

Steam & powergeneration

Ethanol

Process steam & electricity

Raw Biomass

Hydrolysis

Combining of two steps proposed: simultaneous saccharification and fermentation – SSF

Combining of three steps proposed: consolidated bioprocessing – CBP

• May 2009 study from U.S. National Academy of Sciences:– Ethanol yield with current known technology: ~260 liters/dry t biomass– Future-technology yield: ~330 liters/dry t biomass

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Gasification-based conversion of biomass

Air, O2, and/or steamBagasse, Trash

Gasification(1 to 30 bar)

Drying Sizing

Gas cleaning

Gas Turbine Heat Recovery Steam Turbine

Electricity

Process steamBGCC

Water Gas Shift(CO+H2O H2+CO2)

CatalyticSynthesis

Distillation or Refining

CO2 Removal

Steam & PowerGeneration

Process steam/elec.

LiquidFuel

CO, H2, CH4, CO2

Biomass to Liquids

FermentationDistillation or Refining

Steam & PowerGeneration

Process steam/elec.

Alcohols

Hybrid thermochem/biochem fuels production (one example)

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Methanol / MTG

Fischer Tropsch

Dimethyl ether

Mixed alcohols

Biocrude

Ethanol

Diesel

Paraffin

LPG

Kerosene

Gasoline

Biofuel substitutes for Conventional Fuel

Crude oil

GASIFICATION

HYDROLYSIS

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Fuels that can be made via gasification

• Fischer-Tropsch Liquids (FTL)– Diesel substitute + naphtha/gasoline co-product– Technology from 1930s, large interest in coal-to-FT today

• Dimethyl ether (DME)– Similar to LPG (25% blend with LPG acceptable)– Excellent diesel fuel, but needs pressurized fuel systems– Large production from coal in China, Iran

• Substitute natural gas (SNG)– Syngas methanation technology is commercial – Low temperature of biomass gasification favors CH4

• Hydrogen (H2)– Technology for H2 from syngas is commercial– Can provide the H2 needed for NH3 production

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Thermochem Biochem

Process sensitive to feedstock type/quality? No Yes

Fuel/power/chemicals flexibility? High Low

“Drop-in” fuels to replace petroleum fuels? Yes Maybe

Potential for co-processing with coal? High Low

CCS potential with liquid fuels production Higher Lower

Commercial or near-commercial components?

Yes No

R&D advances needed to achieve potential? No Yes

Significant R&D efforts ongoing (in U.S.)? No Yes

Ready for commercial-scale demonstration? Yes No

Familiar to sugarcane biomass industry? No Yes

Projected specific investment costs for fuels? Higher Lower

Comparing thermochemical and biochemical systems

Black – technology featuresRed – development statusBlue – key hurdles

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Gasification-based fuels from biomass and/or coal

Feed Preparationand Gasification

GasConditioning

Acid GasRemoval

Liquid FuelSynthesis

Refining

PowerGeneration

feedstock

OxygenProduction

airOnsiteElectricity

FinishedFuels

CO2 H2S,COSVent to atmosphere

or compress for transport/injection.

• All conversion component technologies are commercial (or near-commercial in the case of biomass gasification).

• CO2 removal is intrinsic part of the process.• Projects to demonstrate CO2 capture from coal and storage at

mega-scale (> 106 tCO2/yr injection) are in active development in USA, Europe, Australia, and China – will require ~10 years to gain confidence needed for widespread implementation.

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CCS for biomass

• Coal is target for most CCS developments, but if CCS works for coal, it can also be considered for biomass

• With CCS, biomass goes from “carbon neutral” to “carbon-negative” as a result of geological storage of photosynthetic CO2.

• Attractive approach: co-process biomass with coal:– Economies of scale of coal conversion.– Low cost of coal as feedstock.– Negative CO2 emissions of biomass offsets unavoidable coal-

derived CO2 net-zero GHG emission fuel can be produced.– One commercial operation already co-gasifying coal and

biomass (Buggenum IGCC, Netherlands) for power generation; several U.S. projects in development for fuels.

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Three designs for coal/biomass co-processing with CCS.

H2S, CO2removal

PressurizedGasification

Gas cooling& cleaning

Air separation unit

oxygen

airUnderground

Storage

WaterGas Shift

CO2

Coal

Biomass

SyngasConversion



H2S, CO2removal



Air separation unit

oxygen

airUnderground

Storage

WaterGas Shift

CO2

CoalBiomass

SyngasConversion

H2S, CO2

removalPressurizedGasification


Air separation unit

oxygen

airUnderground

Storage

WaterGas Shift

CO2

CoalBiomass

SyngasConversion

SYNFUELS and/or

ELECTRICITY

PressurizedCFBG

oxygen

SYNFUELS and/or

ELECTRICITY

SYNFUELS and/or

ELECTRICITY

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Coal/Biomass co-processing for Fischer-Tropsch diesel and gasoline, with CO2 capture for storage

FB Gasifier& Cyclone

Chopping & Lock hopper

oxygen

biomassTar

Cracking

steam

CO2

Gasification& Quench

Grinding & Slurry Prep

water

coal

SyngasScrubber

Acid GasRemoval

F-TRefining

F-TSynthesis

CO2

FlashRefrigeration

Plant

slag

Flash

methanol

CO2

syngas

Water GasShift

150 bar CO2

to pipeline

Re

ge

ne

rato

rH2S + CO2

To Claus/SCOT

HC

Re

cove

ry

RecycleCompr.

finished gasoline & diesel blendstocks

unconverted syngas+ C1 - C4 FT gases

raw FT product

Refinery H2 Prod

syncrudelight ends

purge gas PowerIsland

net exportelectricity

gascooling

expander

ATRoxygen steam

dry ash

gascooling

Filter

flue gas

oxygen

OxygenPlant

air

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Carbon/GHG flows for coal/biomass system with CCS.~40% of input energy from biomass gives ~0 GHG emissions

elec

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tai

lpip

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storage

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biomassConversion

Fu

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ATMOSPHERE

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Net lifecycle GHG emissions with alternative fuels from coal and/or biomass relative to petroleum-derived fuels

Coal-FTLCoal-gasoline (MTG)

Coal-FTL w/CCSCoal-MTG w/CCSCurrent Ethanol

EthanolCoal/bio-MTG w/CCS

Coal/bio-FTL w/CCSBio-FTL

Bio-MTGEthanol w/CCSBio-FTL w/CCS

Bio-MTG w/CCS

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Amount of biomass needed with different technologies to make fuels having ~zero net lifecycle GHG emissions

• One liter of fuel from biomass via thermochemical or biochemical processing requires about same amount of biomass feedstock.

• Co-processing biomass with coal to make a liter of zero-GHG liquid fuels requires half or less as much biomass as a “pure” biofuel.

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Co-processing for FTL, MTG

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Yields of low/zero net GHG liquid fuels per t biomass

* Pure biomass cases with CCS (BTL-RC-CCS and BTG-RC-CCS) have strong negative GHG emissions, so some petroleum-derived fuel can be used and still have overall GHG emissions = 0.

* *

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0 20 40 60 80 100GHG Emission Price, $ per tCO2 equiv.

Petrol ($100/bbl)

Petrol ($50/bbl)

Production costs (“Nth” plant) for alternative biomass-based liquid fuels.*

Assumptions: Biomass input rate ~1500 dry t/day; biomass price, $1.5/GJHHV; coal price, $1.7/GJHHV; capital charge rate = 0.15/yr.

Petroleum gasoline

$100/bbl crude oil

$50/bbl crude oil

$ p

er l

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of

gas

oli

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(200

7$)

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Ethanol

Ethanol-CCS

Petrol ($100/bbl)

Petrol ($50/bbl)



*Ethanol from U.S. National Academy of Sciences study (May 2009), which projects achievable future yield of 334 lit/dry tonne switchgrass with capex as indicated above. FTL estimates are based on analysis by Princeton Univ. researchers (e.g., see paper from Pittsburgh Coal Conference 2008, www.princeton.edu/pei/energy/publications)

Petroleum gasoline

$100/bbl crude oil

$50/bbl crude oil

$ p

er l

iter

of

gas

oli

ne

equ

ival

ent

(200

7$) Capex

(106 2007$)Gasoline eq

(bbl/d)Power(MWe)

GHG(vs. oil)

B-FTL 363 2178 15.7 -0.14B-FTL-CCS 370 2178 11.1 -1.35C/B-FTL-CCS 718 4936 34.1 -0.02C/B-FTL-El-CCS 740 4002 126 -0.01Ethanol* 156 1941 2.0 0.17Ethanol-CCS 158 1941 0.6 -0.22

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0.00

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B-FTL

B-FTL-CCS

Ethanol

Ethanol-CCS

Petrol ($100/bbl)

Petrol ($50/bbl)




Petroleum gasoline

$100/bbl crude oil

$50/bbl crude oil

$ p

er l

iter

of

gas

oli

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equ

ival

ent

(200

7$) Capex


(bbl/d)Power(MWe)

GHG(vs. oil)


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B-FTLB-FTL-CCSC/B-FTL-CCSC/B-FTL-El-CCSEthanolEthanol-CCSPetrol ($100/bbl)Petrol ($50/bbl)




Petroleum gasoline

$100/bbl crude oil

$50/bbl crude oil

$ p

er l

iter

of

gas

oli

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equ

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(200

7$) Capex


(bbl/d)Power(MWe)

GHG(vs. oil)


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Investment estimate for gasifier-GTCC power (Nth plant, U.S. site, 2007 prices)

Average Maximum Average MaximumInput biomass

Megawatts, LHV 255 766 255 766Megawatts, HHV 280 841 280 841Millions of dry tonnes per year (85% capacity factor) 0.401 1.202 0.401 1.202

Electricity, MWGross production 127 381 117 351Onsite consumption 7.5 22.6 16 46.8Net electricity sales 119 358 101 304

Plant capital costs, million 2007$Air separation unit (ASU), and O2 and N2 compression 53 92 52 90 Biomass handling, gasification, and gas cleanup 128 314 145 350 All water gas shift, acid gas removal, Claus/SCOT - - 30 57 CO2 compression - - 10 20 Gas turbine topping cycle 36 82 33 76 Heat recovery and steam cycle 45 111 53 135

Total plant cost (TPC), million 2007$ 262 598 322 727 Specific TPC, $ per kW 2,192 1,670 3,179 2,389

BIG-GTCC-V BIG-GTCC-CCS

Bagasse plus 50% of trash from 2 million tcane/yr 6 million tcane/yr

MW Electric Export to Grid

Investment cost

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Electricity selling price for stand-alone gasifier-GTCC power plant (“Nth plant” U.S. price estimate)

Financial assumptions (U.S. conditions)

Average Maximum Average Maximum

Levelized cost of electricity production, $ per MWhCapital charges 45.4 34.6 65.8 49.4 O&M charges 11.8 9.0 17.1 12.8 Biomass (@ $1.43/GJ HHV average cost) 12.0 12.0 14.1 14.1 CO2 emissions charge - - - - CO2 disposal charges - - 9.5 6.5 Total electricity cost, $/MWh 69.1 55.5 106.5 82.9

BIG-GTCC-V BIG-GTCC-CCS

CARBON EMISSION PRICE = ZERO

Weighted cost of bagasse ($15/dry t) + trash ($40/dry t).

US $ per MWh

(including 10% return on investment)Electricity Selling Price, US$ per MWh (2007 levels)

price

Debt fraction of capital investment 55% Equity fraction of capital investment 45% Real cost of debt 4.4% Real cost of equity 10.2% Corporate income tax rate 39.2% Non-fuel O&M (% of capital cost per yr) 4%

Is this a compelling case for BIG-GT commercialization ?

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Some numbers: potential yields from sugarcane biomass

Liquid Fuels Production From 50% of bagasse + trash (0.14 tonnes dry biomass total per tc)

Electricity Generation kWh per tonne cane* Steam cycle, 67 bar, 490oC 108 Steam cycle, 100 bar, 520oC 118 Gasification-GTCC 210 Liquid Fuels Production Liters per tonne cane* Ethanol Current technology [1] 38.7 Future (2015?) technology [2] 50.1 FT Diesel + FT Gasoline** [3] Diesel-equivalent liters 29.5 Ethanol-equivalent liters 50.1 Dimethyl ether DME liters 63.2 LPG-equivalent liters 47.4 Diesel-equivalent liters 33.6 Ethanol-equivalent liters 56.7 Nitrogen Fertilizer Production Kg of contained N per tonne cane*** Ammonia 365 1. Andrew McAloon, Frank Taylor, Winnie Yee (U.S. Department of Agriculture, Eastern Regional

Research Center, Agricultural Research Service) and Kelly Ibsen, Robert Wooley (NREL), “Determining the Cost of Producing Ethanol from Corn Starch and Lignocellulosic Feedstocks, A Joint Study Sponsored by: U.S. Department of Agriculture and U.S. Department of Energy,” NREL/TP-580-28893, October 2000.

2. Aden, A., Ruth, M. Ibsen, K., Jechura, J., Neeves, K., Sheehan, J., Wallace, B., Montague, L., Slayton, A., and Lukas, J., Lignocellulosic Biomass to Ethanol Process Design and Economics Utilizing Co-Current Dilute Acid Prehydrolysis and Enzymatic Hydrolysis for Corn Stover, National Renewable Energy Laboratory Report # NREL/TP-510-32438, Golden, CO, June 2002.

3. Kreutz, T.G., Larson, E.D., Liu, G. and Williams, R.H. “Fischer-Tropsch Fuels from Coal and Biomass,” 25th Annual International Pittsburgh Coal Conference, 9/29 – 10/2/2008, Pittsburgh, PA, USA

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Ethanolfromsugar

Ethanolcurrent

Ethanolfuture

B-FTL B-DME C/B-FTL-CCS

Lit

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pe

r to

nn

e c

an

e liters gasoline equiv/tc

liters ethanol equiv/tc

Electricity Generation kWh per tonne cane* Steam cycle, 67 bar, 490oC 108 Steam cycle, 100 bar, 520oC 118 Gasification-GTCC 210 Liquid Fuels Production Liters per tonne cane* Ethanol Current technology [1] 38.7 Future (2015?) technology [2] 50.1 FT Diesel + FT Gasoline** [3] Diesel-equivalent liters 29.5 Ethanol-equivalent liters 50.1 Dimethyl ether DME liters 63.2 LPG-equivalent liters 47.4 Diesel-equivalent liters 33.6 Ethanol-equivalent liters 56.7 Nitrogen Fertilizer Production Kg of contained N per tonne cane*** Ammonia 365 1. Andrew McAloon, Frank Taylor, Winnie Yee (U.S. Department of Agriculture, Eastern Regional

Research Center, Agricultural Research Service) and Kelly Ibsen, Robert Wooley (NREL), “Determining the Cost of Producing Ethanol from Corn Starch and Lignocellulosic Feedstocks, A Joint Study Sponsored by: U.S. Department of Agriculture and U.S. Department of Energy,” NREL/TP-580-28893, October 2000.

2. Aden, A., Ruth, M. Ibsen, K., Jechura, J., Neeves, K., Sheehan, J., Wallace, B., Montague, L., Slayton, A., and Lukas, J., Lignocellulosic Biomass to Ethanol Process Design and Economics Utilizing Co-Current Dilute Acid Prehydrolysis and Enzymatic Hydrolysis for Corn Stover, National Renewable Energy Laboratory Report # NREL/TP-510-32438, Golden, CO, June 2002.

3. Kreutz, T.G., Larson, E.D., Liu, G. and Williams, R.H. “Fischer-Tropsch Fuels from Coal and Biomass,” 25th Annual International Pittsburgh Coal Conference, 9/29 – 10/2/2008, Pittsburgh, PA, USA

Surplus Electricity (100% bag + 50% trash + meeting mill process steam and electricity needs)

Nitrogen Fertilizer Prod (50% bag + 50% trash)

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Mauritius potential electricity, fuels, fertilizer from sugarcane

Potential (% of current) Current Actual ?

Electricity Generation (GWh/year)

~ 2300100 bar steam cycle 590 (26%)

BIG-GT power 1050 (46%)

Transport Fuel (106 liters/yr gasoline equivalent)

~ 1300Sugar ethanol 315 (24%)

Biomass ethanol 165 (13%)

Biomass FTL 194 (15%)

Coal/Biomass FTL 440 (34%)

Ammonia Fertilizer (tonnes of contained N)

Biomass ammonia 1,825,000 (~200x) ~ 8800

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Summary thoughts

• Gasification is technologically close to being commercial. • Economics of gasification for power have not been sufficient to get over the “hump”

since idea first recognized ~25 years ago.• Coal gasification (and past biomass IGCC) experience suggest gasification must

provide “disruptive” benefits to succeed. – Electricity production may not be disruptive enough.– Liquid fuel production may be disruptive enough.– Gasification is well suited to make fuels/chemicals in addition to power.

• Co-production of fuel and power may be most disruptive of all.– World oil price volatile; co-production is a hedging strategy.– Strong GHG mitigation policy needed to avoid planetary overheating – such policies will also

help protect co-producer against oil price collapse.• Carbon-based fuels/power with low lifecycle GHG emissions will grow in value, and

negative GHG emissions potential of biomass is likely to be high value in long term. • Gasification strategy that foresees it as technology platform for fuels/chemicals/

power co-production may provide a compelling motivation for commercialization.• Sugarcane industry is unique in having experience with large-scale biomass handling,

with liquid fuels production, with power generation, and (in Mauritius) with coal use.• But commercializing gasification will require a big effort.

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Past BIG-GT commercialization efforts

Varnamo (Sweden) operation 1993-1999 • 20 MWbiomass GTCC + district heating.

• > 8,500 hours pressurized gasification • > 3,600 hours integrated operation. • Technical success, but larger scale needed for

successful economics.

ARBRE (UK) low-P gasifier, 8 MWe GTCC • Successful partial commissioning (2000/01)• Institutional problems end project in 2002.

SIGAME (Bahia), 32 MW, 1991-2003

BAGAÇO (Teste)

FLORESTA SECAGEM NO CAMPO MADEIRA

ESTOCADA NA PLANTA

ESTOQUE DE CAVACOS

GASEIFICAÇÃO

G

TG - 24 MW CALDEIRA DE RECUPERAÇÃO

G

TV-16 MW

SECAGEM

DO GÁS LIMPEZA

5110 ha *

240.250 m 3 /a

* Prodtiv : 47

m 3 /ha.a

CINZAS 0,80 t/h CARVÂO 0,01 t/h

(NH 4 ) 2 SO 4 0,4 m 3 /h a ~33% ÁGUA < 43 m 3 /h

210.000 m 3 / h MP < 35mg/MJ NOx < 40 mgNO 2 /MJ S << 20 mgSO 2 /MJ T < 100

o C

LIMITES: PH 5 - 9 T < 40 O C ÓL&G (M) < 20 mg/l ÓL&G (A) < 50 mg/l NH 3 < 5 mg/l Fenóis < 0,5 mg/l Fe (Sol.) < 15 mg/l Zi < 5 mg/l BOD < 60 mg/l Remoção > 80 %

Projeto - SIGAME

32 MW liq .. 240 GWh /a Ef .>40 % 85% FC

• Low-P gasifier

• Detailed engineering completed, GE turbine modified

• Plantations established

• Institutional problems end project.

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Challenges to commercializing biomass gasification

Engineering

• Efficient biomass drying, e.g. using low-temperature waste heat• Gasifier feeding of bagasse/trash (more for pressurized gasification)• Tar cracking/gas cleaning• Operational reliability and availability

Financial

• Finding the money• Demonstrating the competitiveness

• Investment cost• O&M cost• Fuel cost• Energy or product price

Institutional

• Getting support from the right partners (engineering, finance, institutional)

• Getting the right institutional and organizational arrangement to carry forward the demonstration and continue on to commercial deployment.

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Some considerations for ISBUC

• Past work (e.g., Arbre, Varnamo, and other projects) provides information needed to design a commercial-scale gasification installation.

• A minimum scale is needed to be convincing as a commercial demonstration and to achieve acceptable economics. What should be the scale?

• What should be produced? Power? Fuel? Power and Fuel?

• How about co-processing biomass and coal in an already-commercial coal gasifier?

• What are ISBUC’s long-term objectives – beyond a demonstration project?

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Thank you!

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Scale of Sugarcane Processing Plants in Southeast Brazil

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1000000

2000000

3000000

4000000

5000000

6000000

7000000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161 171 181 191

Number of Mills

To

nn

es o

f ca

ne

pro

cess

ed a

nn

ual

ly

Source: UNICA, Ranking de Produção,www.unica.com.br/referencia/estatisticas.jsp

4000

2000

1000

3000

0

Approximate dry t/day recoverable biom

ass

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Grinding & Slurry Prep.

Gasification & Quench

Syngas Scrubber

Water Gas Shift

Acid Gas Removal

Methanol Synthesis

Methanol Recovery

MTG reactor

Refining

Refrigeration plant

Flash

Flash

Regeneration

Power Island

Coal

Water Slag

Oxygen plant

Air

Gas cooling

Methanol

CO2

CO2

H2S + CO2 To Claus/SCOT

150 bar CO2 To pipeline

Air

Water

Flue gas

Purge gas

CrudeMethanol

Net export electricity

Gasoline

LPG

Fuel gas

Recycle Compr.

Recycled Syngas

Compression needed only if CCS is utilized.

Fischer-Tropsch liquids (FTL) from coal w/ or w/o CCS.

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Fischer-Tropsch liquids (FTL) from biomass w/ or w/o CCS

B-FTL, B-FTL-CCS

FB Gasifier& Cyclone

Chopping & Lock hopper

biomassTar

Cracking

steam

CO2

Acid GasRemoval

F-TRefining

F-TSynthesis

CO2

FlashRefrigeration

Plant

Flash

methanol

CO2

syngas

150 bar CO2

to pipeline

Re

ge

ne

rato

r

H2S + CO2

To Claus/SCOT

HC

Re

cove

ry

RecycleCompr.

finished gasoline & diesel blendstocks

unconverted syngas+ C1 - C4 FT gases

raw FT product

Refinery H2 Prod

syncrudelight ends

purge gas PowerIsland

net exportelectricity

ATRoxygen steam

dry ash

gascooling

Filter

flue gas

oxygen

OxygenPlant

air

Compression needed only if CCS is utilized.

38

GHG Emissions of Alternative Biomass-Based Liquid Fuels

-2.0 -1.5 -1.0 -0.5 0.0 0.5

BTG-RC-CCS

BTL-RC-CCS

EthOH-CCS

BTG-RC-V

BTL-RC-V

CBTL-RC-CCS

CBTG-RC-CCS

EthOH-V

Current EthOH

Relative to crude oil products displaced

39

Trajectory of GHG emissions price (in 2007 $/tCO2eq) that translates to a levelized GHG emissions price of $50/tCO2eq

0

20

40

60

80

100

120

140

160

180

2015 2020 2025 2030 2035

Year

GH

G E

mis

sio

ns

Pri

ce,

$/t

CO

2eq

Levelized GHG Emissions Price, 2016-2035

Commercializing New Biomass Energy Technologies

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