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NREL is a national laboratory of the U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.
Introduction to Biopower
Hawaii PUC
Richard L. Bain
April 11-12, 2012
Presentation Outline
• Background • Industry Status • Resources • Other Factors • Biomass Properties
• Direct Combustion • Cofiring • Gasification • Project Technical Evaluation
Photo Credit: Chariton Valley RC&D
Background
6
Biopower Status
2010 Capacity – 10.7 GW 5.8 GW Electric Power Sector 4.9 GW End Use Generators 2010 Generation – 56TWh Cost – 0.08 – 0.12 USD/kWh
Sources: DOE EIA Annual Energy Outlook, Table A16 (year-by-year) , NREL Renewable Electricity Futures Study (2010) – Preliminary Data EIA Form 860 (Capacity), EIA Form 923 (Generation)
Potential – Electric Sector
2022 - 22 GW 2035 - 48 GW 2050 - 91 GW
2010 U.S. Renewable Electricity Generation, TWh
DOE EIA Annual Energy Outlook, Table A16, Individual Yearly Issues
United States Biopower 1981 - 2009
2003-2010 U.S. Biopower Capacity and Generation Net Summer Capacity, GW 2003 2004 2005 2006 2007 2008 2009 2010
Electric Power SectorMunicipal Waste 3.19 3.19 3.21 3.39 3.42 3.43 3.20 3.30Wood and Other Biomass 2.00 2.04 1.96 2.01 2.09 2.17 2.43 2.45Total 5.19 5.23 5.17 5.40 5.51 5.60 5.63 5.75
End-Use GeneratorsMunicipal Waste 0.27 0.33 0.34 0.33 0.33 0.33 0.36 0.35Biomass 4.32 4.66 4.72 4.64 4.88 4.86 4.56 4.56Total 4.59 4.99 5.06 4.97 5.21 5.19 4.92 4.91
Total, All SectorsMunicipal Wastes 3.46 3.52 3.55 3.72 3.75 3.76 3.56 3.65Biomass 6.32 6.70 6.68 6.65 6.97 7.03 6.99 7.01Total 9.78 10.22 10.23 10.37 10.72 10.79 10.55 10.66
Generation, TWhElectric Power Sector
Biogenic Municipal Wastes 20.84 19.86 12.70 13.71 13.88 14.49 16.10 16.56Wood and Other Biomass Dedicated Plants 9.53 8.54 8.60 8.42 8.65 9.00 9.68 10.15 Cofiring 0.00 1.19 1.97 1.91 1.94 1.90 1.06 1.36Total 30.37 29.59 23.27 24.04 24.47 25.39 26.84 28.07
End-Use GeneratorsMunicipal Wastes 2.22 2.64 1.95 1.98 2.01 2.02 2.07 2.02Biomass 28.00 28.90 28.33 28.32 28.43 27.89 25.31 26.10Total 30.22 31.54 30.28 30.30 30.44 29.91 27.38 28.12
Total, All SectorsMunicipal Wastes 23.06 22.50 14.65 15.69 15.89 16.51 18.17 18.58Biomass 37.53 38.63 38.90 38.65 39.02 38.79 36.05 37.61Total 60.59 61.13 53.55 54.34 54.91 55.30 54.22 56.19
EIA Form 923 Actual Generation 55.40 55.06 54.34Note: In 2003, cofiring plants classified as coal
U.S. Existing Biopower Plants
Biomass Resource
0
5
10
15
20
25
0
200
400
600
800
1000
1200
1400
2005Milbrandt
2005
2015Walsh2008
2020Walsh2008
2020NAS2009
2025Haq &
Easterly2006
2025Walsh2008
BillionTon Study
Perlack 2005
2030DOE 2011
Base
2030DOE2011High (2%)
2030DOE 2011High (4%)
Urban Primary Mill Residue Forest Residue Agricultural Residues Dedicated Crops
Mill
ion
Dry
To
nn
es
Exaj
ou
les
USA Biomass Potential
0
20
40
60
80
100
120
140
160
0 5 10 15 20 25
Del
iver
ed C
ost
(200
9$/d
ry t
onne
)
Biomass Potential (EJ)
2010 2015 2020 2025
RE FuturesMilbrandt 2005
2030Khanna 2011
Base CaseHigh Growth
2%/yearHigh Growth
4%/year
Walsh 2008
2030 DOE 2011
Supply cost curves for potential delivered biomass, 2005–2030
Biopower Technology Costs
Efficiency = 341.4/Heat Rate, e.g., Advanced Gasification = 341.4/8 = 42.7%
Technology Year Heat Rate Ref(2009$) Overnight w AFUDC Fixed Variable
Combustion, Stoker 2009 3,685 3,823 100 4 16 0.78 75 59 12.50 McGowin (2007)
Combustion, CFB 2009 3,800 3,941 103 5 16 0.78 75 59 12.50 McGowin (2007)
CHP 2009 3,888 4,033 101 4 16 0.89 75 67 14.25 McGowin (2007)
Gasification, Base 2009 4,194 4,417 94 7 16 0.59 75 44 9.49 DeMeo (1997)
Gasification, Advanced 2009 3,607 3,795 60 7 16 0.50 75 38 8.00 McGowin (2007)
Cofiring, PC Co-feed3 2009 559 559 13 2 16 0.63 75 47 Coal Heat Rate +1.5%
McGowin (2007)
Cofiring, Cyclone Co-feed3 2009 355 355 13 1 16 0.63 75 47 Coal Heat Rate +1.5%
McGowin (2007)
Cofiring, Separate Feed3 2010 1,000 20 0 16.0 0.63 75 47 Coal Heat Rate +1.5%
Black & Veatch (2010)
Municipal Solid Waste 2009 7,306 7,660 267 29.1 -- -- -- -- 16.46 EPRI (2003)
1 Using a illustrative biomass cost of $75/ton ($82.60/tonne)
3 Biomass cost based on heat rate of 10.00 MMBtu/MWh
MMBtuMWh
Capital Cost Operating CostsFeed1
$/kW-yr $/MWh tonMWh
$*ton $/MWh1000$/MW MMBtu
dry ton
Source: McGowin 2007
Direct Combustion Capital and Operating Costs for Biopower
Units Stoker CFBa CHPb
Capacity MWe 50 50 50 Cogenerated steam output 1,000 lb/h 100 Cogenerated steam conditions psig, sat 100 Year $ 2009 2009 2009 Physical Plant Unit Life years 30 30 30 Construction Schedule
Preconstruction, license and design times years 1.5 1.5 1.5 Idealized plant construction time years 2 2 2
Capital Costs $/kW Fuel handling, preparation 120 120 130 Boiler and air quality control 789 882 857 Steam turbine and auxiliaries 625 625 709 Balance of plant 248 248 248 General facilities and engineering fee 1,157 1,157 1,157 Project and process contingency 109 113 115 Total plant cost (TPC) 3,048 3,144 3,216 AFUDCc 138 141 144 Escalation during construction total plant investment (TPI) 3,186 3,285 3,361
Owner Costs $/kW
Due diligence, permitting, legal, development 637 656 672 Taxes and fees 0 0 0
Total Capital Requirements (TCR) $/kW 3,823 3,941 4,033 O&M Costs
Fixed $/kW-yr 99.7 102.6 101.5 Variable $/MWh 4.1 4.6 4.2 Feed @ $75/ton $/MWh 58.59 58.59 66.80
Performance/Unit Availability Net heat rate Btu/kWh 12,500 12,500 14,250 MMBtu/MWh 12.50 12.50 14.25 % 27.31 27.31 23.96 Equivalent planned outage rate % 4 4 4 Equivalent unplanned outage rate % 6 6 6 Equivalent availability % 90 90 90
Emission Rates CO2 lb/MMBtu 220 220 220 NOx lb/MMBtu 0.15 0.08 0.15 SOx lb/MMBtu 0.10 0.04 0.10
2009 2022 2035 2050
Cofiring Dedicated Cofiring Dedicated Cofiring Dedicated Cofiring Dedicated
Total Capacity (GW) 0.5 0.2 15.3 15.3 28.2 28.2 18.4 69.4
Investment (billion $) 0.5 0.8 15.3 57.4 28.2 105.8 18.4 260.3
Direct Jobs 250 200 7,650 15,300 14,100 28,200 9,200 69,400
Total Jobs 1,250 1,000 38,250 76,500 70,500 141,000 46,000 347,000
Potential Investments and Cumulative New Jobs for Dedicated Biopower
and Cofiring in the Electric Power Sector
Cofiring capital expenditure = $1,000/kW, Average dedicated capital expenditure = $3,750/kW Cofiring direct jobs = 0.5/MW, Dedicated direct jobs = 1/MW Total jobs multiplier = 5 (Perez Verdin et.al 2008)
Consumptive Water Use
• Consumptive water use comparable to coal combustion
• Majority of consumptive water use is for evaporative cooling
tower and is independent of feed
• Valid for direct combustion and cofiring
• Average use 1.741 m3/MWh (0.46 gal/kWh)
Consumptive water use is the amount of water withdrawn from the source and not returned to the source
Davis, R.; Tan, E. (2010). Comparison of Biomass Pathways for Vehicle Use. NREL Milestone Report (unpublished).
National Energy Technology Laboratory (NETL). (2006, August). “Estimating Freshwater Needs to Meet Future Thermoelectric Generation Requirements.” DOE/NETL-2006/1235. Prepared by Stiegel, G. J. Jr.; McNemar, A.; Nemeth, M.; Schimmoller, B.; Murphy, J.; Manfredo, L.
Biomass Properties
The basic properties for the comparison of thermal behavior are proximate and ultimate analyses
Poplar Corn Stover
Chicken Litter
Black Liquor
IL No. 4HvBb
RosebudsubB
AthabascaBitumen
Proximate, wt% as received Ash 1.16 4.75 18.65 52.01 12.88 7.82 Volatile Matter 81.99 75.96 58.21 32.56 37.54 33.32 Fixed Carbon 13.05 13.23 11.53 6.11 42.04 41.91 Moisture 4.80 6.06 11.61 9.61 7.54 16.94
HHV, Dry (Btu/lb) 8,382 7,782 6,310 4,971 12,400 11,684 17,900
Ultimate, wt% as received Carbon 47.05 43.98 32.00 32.12 63.43 62.59 83.6 Hydrogen 5.71 5.39 5.48 2.85 5.10 6.27 10.3 Nitrogen 0.22 0.62 6.64 0.24 1.09 1.08 0.4 Sulfur 0.05 0.10 0.96 4.79 4.40 4.36 5.5 Oxygen 41.01 39.1 34.45 0.71 12.98 12.85 0.2 Chlorine <0.01 0.25 1.14 0.07 0.11 0.11 Ash 1.16 4.75 19.33 51.91 12.88 12.75H/C Atomic Ration 1.45 1.46 2.04 1.06 0.96 1.19 1.47
Elemental Ash, wt% of fuel as received Si 0.05 1.20 0.82 <0.01 Fe -- -- 0.25 0.05 Al 0.02 0.05 0.14 <0.01 Na 0.02 0.01 0.77 8.65 K 0.04 1.08 2.72 0.82 Ca 0.39 0.29 2.79 0.05 Mg 0.08 0.18 0.87 <0.01 P 0.08 0.18 1.59 <0.01 As (ppm) 14
The heating value is important in estimating process efficiency
Biomass Higher Heating Value
Correlation HHV, MJ/kg
10 15 20 25 30
Expe
rimen
tal H
HV,
MJ/
kg
10
15
20
25
30
Regression, r2=0.834, n = 17999% CIAquatic Herbaceous RDF WoodyLigninAnimal Waste
High Ash
Low Ash
HHV = 0.349C + 1.178H + 0.1005S - 0.1034O - 0.015N - 0.211A
Channiwala, S.A. and P.P. Parikh (2002), Fuel, 81, 1051-1063
Potassium Content of Biomass
0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5
Mixed waste paperFir mill waste
RFD - TacomaRed oak sawdust
Sugar Cane BagasseUrban wood waste
Willow - SV1-3 yrFurniture wasteWillow - SV1-1 yrAlder/fir sawdustSwitchgrass, MN
Hybrid poplarSwitchgrass, D Leaf, MN
Demolition woodForest residualsPoplar - coarse
Miscanthus, SilberfederWood - land clearing
Almond woodWood - yard waste
Danish wheat strawRice husks
Switchgrass, OHOregon wheat straw
Alfalfa stemsCalifornia wheat straw
Imperial wheat strawRice straw
Potassium Content (lb/MBtu)
Bain, R. L.; Amos, W. P.; Downing, M.; Perlack, R. L. (2003). Biopower Technical Assessment: State of the Industry and the Technology. 277 pp.; NREL Report No. TP-510-33123
Potassium content influences slagging and fouling properties
Biomass Slagging Guidelines in Combustion Boilers
• <0.4 lb alkali (K2O + Na2O)/MMBtu, low slagging and fouling
• 0.4 – 0.8 lb alkali/MMBtu, probable slagging and fouling
• >0.8 lb alkali/MMBtu, certain slagging and fouling
Miles, T. R.; Miles, T. R. Jr.; Baxter, L. L.; Bryers, R. W.; Jenkins, B. M.; Oden, L. L.; Dayton, D. C.; Milne, T. A. (1996). Alkali Deposits Found in Biomass Power Plants. A Preliminary Investigation of Their Extent and Nature (Vol. I); The Behavior of Inorganic Material in Biomass-Fired Power Boilers -- Field and Laboratory Experiences (Vol. II). Vol. I: 133 pp.; Vol II: 496 pp.; NREL Report No. TP-433-8142; Sand96-822
Nitrogen Content of Biomass
0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5
Red oak sawdustFir mill waste
Mixed waste paperSugar Cane Bagasse
Urban wood wasteFurniture waste
Miscanthus, SilberfederWillow - SV1-3 yr
Wood - land clearingDanish wheat straw
Alder/fir sawdustOregon wheat straw
California wheat strawDemolition wood
Poplar - coarseImperial wheat straw
Hybrid poplarWillow - SV1-1 yr
Rice husksSwitchgrass, MN
Almond woodSwitchgrass, D Leaf, MN
Switchgrass, OHBana Grass, HI
Forest residualsRFD - Tacoma
Wood - yard wasteRice straw
Alfalfa stems
Nitrogen (lb/MBtu)
Bain, R. L.; Amos, W. P.; Downing, M.; Perlack, R. L. (2003). Biopower Technical Assessment: State of the Industry and the Technology. 277 pp.; NREL Report No. TP-510-33123
Nitrogen is important in determining the need for NOx emission mitigation strategies
ASTM Fuel Specifications ASTM Test ASTM D 396 ASTM D 396 ASTM D6751 Typical Biodiesel
Test Description Method No. 2 - 4 light No. 6 Biodiesel Ranges measured
Flash Point oC, min D 93 38 60 100 122 - 185Water & Sed., % vol, max D 1796 0.05 2.00 0.05 0 - 0.025Kinematic Viscosity@40oC, mm2/s D 445 Min 1.8 >92 (@50) 1.9 3.97 Max 3.4-5.5 638(@50) 6 5.00Ramsbottom carbon residue, % mass, max D 524 0.35 0.1 0.01 - 0.08Ash, % mass, max D 482 0.05 0.02 0.01-0.03Sulfur, % mass, max D 129 0.5 0.0015 0.0006Copper strip corrosion, max, 3hr @50oC D 130 No. 3 No. 3 1A - 1BDensity @ 15oC, kg/m3 D 1298 0.85 n/a 0.87 - 0.89Pour point, oC, max D 97 -6.0 +15 (low S) report -4.0 to 0Cetane number, min D 613 45 47 - 70Acid Number, mg KOH/gm, max D 664 0.8 0.08 - 0.39Free Glycerin, % mass, max D 6584 0.02 0.0 - 0.007
Advanced Fuel Solutions, Inc.
Conversion Technologies
Technology Advantages Disadvantages
Cofiring Commercial technology Does not add to existing capacity
Lowest cost option Comingling of coal/biomass ash doesn't permit ash sales in cement market (ASTM C618)
Retains efficiency (-1.5% delta) of existing generator
Direct combustion Commercial technology Lowest efficiency option
Gasification Highest efficiency potential IGCC systems not commercial for biomass
Small CHP systems using IC engines commercial
Large scale required to capture cost benefits
Potential for carbon capture and storage
Biopower Technologies
Direct Combustion
Combustion
DeMeo, E. and J. Galdo (1997) Renewable Energy Technology Characterizations, EPRI, TR-109496.
Rankine Cycle
Plant Location MWe CF, % KTons/yr*Williams Lake Canada 60 106 768Shasta California 74 70 694Colmac California 49.9 96 846Stratton Maine 49 90 573Kettle Falls Washington 46 82 542Snomomish Washington 39 60 410Ridge Florida 40 57 376Grayling Michigan 36 63 320Bay Front Wisconsin 30 62 251McNeil Vermont 50 35 255Multtrade Virginia 79.5 19 214Madera California 25 60 308Tracy California 18.5 80 214Camas Washington 17 65 194Tacoma Washington 40 27 221Greenidge New York 10.8 80 98 * Wet tons/yr, assuming 4250 Btu/lb
Historic Biopower Plants, Circa 2000
Wiltsee, G. (2000). Lessons Learned from Existing Biomass Power Plants. 149 pp.; NREL Report No. SR-570-26946.
-1500
-1300
-1100
-900
-700
-500
-300
-100
100
300
All values Co-Firing w/o Avoided Emission Credit*
Co-Firing w/ Avoided
Emission Credit
Direct Combustion w/o Avoided
Emission Credit
Direct Combustion w/
Avoided Emission Credit
Gasification w/o Avoided
Emission Credit
Gasification w/ Avoided
Emission Credit
Pyrolysis
Life
Cyc
le G
HG
Em
issi
ons
(g C
O2e
/ k
Wh)
Life Cycle GHG Emissions of Biopower Technologies
KEY TO BOX PLOT
MAX
75th
MEDIAN
25th
MIN
= Use of CO2 Mitigation Technology
# of Estimates: 154 43 4 70 4 30 1 3 # of References: 35 12 3 20 4 12 1 1
Life Cycle Greenhouse Gas Emissions - Biopower
PM PM-10 PM-2.5 PM PM-10 PM-2.5
Filterable Particulate Matter lb/MMBtu lb/MWha
Dry wood No control 0.40 0.36 0.31 6.14 5.53 4.76
Mechanical collector 0.30 0.27 0.16 4.61 4.14 2.46
Wet wood No control 0.33 0.29 0.25 5.07 4.45 3.84
Mechanical collector 0.22 0.20 0.12 3.38 3.07 1.84
All fuels Electrolyzed gravel bed 0.1 0.074 0.065 1.54 1.14 1.00
Wet scrubber 0.066 0.065 0.065 1.01 1.00 1.00
Fabric filters 0.1 0.074 0.065 1.54 1.14 1.00
Electrostatic precipitator 0.054 0.04 0.035 0.83 0.61 0.54
NOx, SO2, CO NOx SO2 CO NOx SO2 CO
Wet wood 0.22 0.025 0.60 3.38 0.38 9.21
Dry wood 0.49 0.025 0.60 7.52 0.38 9.21
TOC,b VOC, CO2 TOC VOC CO2 TOC VOC CO2
All fuels 0.039 0.017 195 0.60 0.26 2993
a Estimated using wood EPA NEEDS (EPA 2006b) national average heat rate = 15,351 Btu/kWh b Total organic carbon
Average Existing Biopower Emissions (Environmental Protection Agency)
SOH DOH (“Hawaii Administrative Rules, Chapter 11-60.1”) PM < 0.40 lb/100lb for biomass fuel burning boiler, http://hawaii.gov/health/environmental/air/cab/CABrules/11-60-1.pdf; At 8,000 Btu/lb this equals 0.5 lb/MMBtu
Stoker Boilers Fluid Bed Boilers
Existing New Existing New
(lb/MMBtu)
Particulate Matter (PM) 0.02 0.008 0.02 0.008
Hydrogen Chloride (HCl) 0.006 0.004 0.006 0.004
Mercury (Hg) 0.0000009 0.0000002 0.0000009 0.0000002
Carbon Monoxide (CO)4 (ppm) 560 560 250 40
Dioxins/Furans (ng/dscm) 0.004 0.00005 0.02 0.007
1 MACT = Maximum Achievable Control Technology
2 http://www.epa.gov/ttn/atw/boiler/boilerpg.html
3 Pollutants: mercury, lead, cadmium, hydrogen chloride, particulate matter, carbon monoxide,
dioxins/furans, nitrogen oxides, sulfur dioxide
4 @ 3% oxygen
2010 EPA Proposed Air Toxics MACT Standards1,2,3
Cofiring
WoodPile
Truck Tipper
Feedstock
Dump Conveyor #1
RadialStacker
Radial Screw ActiveReclaim Feeder
Rotary AirlockFeeder
Sepa
rato
r
BinVent
Wood Silo
Valve
Valve
Air Intake
MechanicalExhauster
MetalDetector MagneticSeparator
Scale
Scale
Scale
Conveyor #2Disc Feeder
PrimaryHogger
SecondaryHogger
CollectingConveyors
Pressure Blowers
Biomass Co-Firing SystemRetrofit for 100 MW PulverizedCoal Boiler
ExistingBoiler System
BiomassFeedstock
HandlingEquipment
ExistingBoiler
System Boundary forBiomass FeedstockHandling System
Cofiring
DeMeo, E. and J. Galdo (1997) Renewable Energy Technology Characterizations, EPRI, TR-109496.
State Plant Name Biomass/ Coal
Cofiring Capacity
Total Plant
Capacity
AL Mobile Energy Services LLC 91 91AL Georgia Pacific Naheola Mill 31 78AL International Paper Prattville Mill 49 90AR Ashdown 47 156AZ H Wilson Sundt Generating Station 173 558CT Covanta Mid-Connecticut Energy 90 90DE Edge Moor 252 710FL International Paper Pensacola 83 83FL Jefferson Smurfit Fernandina Beach 74 128FL Stone Container Panama City Mill 20 34GA Georgia Pacific Cedar Springs 101 101GA International Paper Augusta Mill 85 85GA SP Newsprint 45 82HI Hawaiian Comm & Sugar Puunene Mill 46 62IA AG Processing Inc 8 8IA University of Iowa Main Power Plant 21 23KY H L Spurlock 329 1,279LA International Paper Louisiana Mill 59 59MD Luke Mill 65 65ME Rumford Cogeneration 103 103ME S D Warren Westbrook 62 81MI Decorative Panels Intl 8 8MI Escanaba Paper Company 81 103MI TES Filer City Station 70 70MN M L Hibbard 73 123
State Plant Name Biomass/ Coal
Cofiring Capacity
Total Plant
Capacity
MN Rapids Energy Center 26 28MS Weyerhaeuser Columbus MS 123 123NC Corn Products Winston Salem 8 8NC Primary Energy Roxboro 68 68NC Weyerhaeuser Plymouth NC 162 162NY AES Greenidge LLC 112 162NY AES Hickling LLC 70 70NY AES Jennison LLC 60 60NY Black River Generation 56 56SC International Paper Eastover Facility 48 110SC Stone Container Florence Mill 79 108SC Cogen South 99 99UT Desert Power LP 43 135VA Bassett Table 2 2VA Georgia Pacific Big Island 8 8VA International Paper Franklin Mill 96 155VA Covington Facility 105 105WA Steam plant 50 50WI Blount Street 100 188WI Manitowoc 10 90WI Fox Valley Energy Center 6 6WI Mosinee Paper 20 23WI Bay Front 40 68WI Biron Mill 22 62WI Whiting Mill 4 4WI Wisconsin Rapids Pulp Mill 72 72WI Niagara Mill 12 24
Total 3,569 6,317
Net Summer Capacity of Plants Cofiring Biomass and Coal, 2006
(Megawatts)
http://www.eia.doe.gov/cneaf/solar.renewables/page/trends/table9.html 3/11/2009
Gasification
Gasification
Acid Gas Removal
Feed Preparation & Handling
Synthesis
Product CO2
Catalytic Conditioning & Reforming
Compression LP Indirect Gasification
Biomass Shift Conversion Compression Low Pressure
Gasification
LP Indirect Gasification
Compression & Reforming
Cold Gas Cleanup
Representative Gasification Pathways
Hot Gas Cleanup
High Pressure Gasification
Oxygen
Compression Reforming
Efficient biomass gasifiers exploit the unique characteristics of biomass
Characteristic
Fibrous material
High reactivity High volatiles content High char reactivity Raw syngas composition Tars Sulfur Alkali, ammonia, others
Scale of Operation
Implications
Feeding systems:
Particle size limitations, pressurized operation more difficult
Gasifier design
Allows gasification alternatives without pure oxygen
Gas cleanup
More tar, water soluble (dry ash gasifiers) Low sulfur (except BL) Must be considered
Limits economies of scale
Secondary
Circulating Fluid-Bed Gasifier
Fly Ash
Bottom Ash
Biomass
Air/Steam
GasifierPrimaryCyclone
CycloneSecondary
Circulating Fluid-Bed Gasifier
Fly Ash
Bottom Ash
Biomass
Air/Steam
GasifierPrimaryCyclone
Cyclone
Fly Ash
Bottom Ash
Biomass
Air/Steam
GasifierPrimaryCyclone
Cyclone
Biomass
Pyrolysis
Reduction
Combustion
Gas, Tar, Water
AshAir
C + CO2 = 2COC + H2O = CO + H2
C + O2 = CO24H + O2 = 2H2O
Downdraft Gasifier
Biomass
Pyrolysis
Reduction
Combustion
Gas, Tar, Water
AshAir
C + CO2 = 2COC + H2O = CO + H2
C + O2 = CO24H + O2 = 2H2O
Downdraft Gasifier
Biomass
N2 or Steam
Furnace
Char
Recycle Gas
ProductGas
Flue Gas
Entrained Flow Gasifier
Air
Biomass
N2 or Steam
Furnace
Char
Recycle Gas
ProductGas
Flue Gas
Entrained Flow Gasifier
Air
Pyrolysis
Reduction
Combustion
Gas, Tar, Water
Ash
Biomass
Air
C + CO2 = 2COC + H2O = CO + H2
C + O2 = CO24H + O2 = 2H2O
Updraft Gasifier
Pyrolysis
Reduction
Combustion
Gas, Tar, Water
Ash
Biomass
Air
C + CO2 = 2COC + H2O = CO + H2
C + O2 = CO24H + O2 = 2H2O
Updraft Gasifier
QUENCHWATER
OXYGENFEED SLURRY
NATURALGAS
SYNGAS
SLAG
WATER
Entrained-Flow Slagging Gasifier
There are a number of types of biomass gasifiers – e.g., fixed bed, fluid bed, and entrained flow
72
Small and medium size combined heat and power is a good opportunity for biomass
Credit: Community Power Corp
Credit: Carbona Corp
15-100 kWe
5 MWe + District Heat Skive, Denmark
DOE and the USDA Forest Service have supported development Community Power Corporation’s BioMax Modular Biopower System
15, 50, 75 kW systems
Credit: Community Power Corp
The ClearFuels biomass gasification technology produces syngas from cellulosic feedstocks through the use of a High Efficiency Hydrothermal Reformer (HEHTR). The syngas can be used to produce power or liquid fuels. A simplified depiction of the HEHTR process and potential downstream syngas conversion processes is shown below.
ClearFuels HEHTR Process Integrated with Downstream Syngas Processing
Unlike other gasifiers or pyrolysis processes, ClearFuels HEHTR is a one-step rapid steam reforming process that converts biomass to syngas with minimal char, ash and tar yields. The technology has operational controls for tuning the hydrogen to carbon monoxide ratio in the syngas product from 1.0 up to 3.5 as shown in the plot to the right, which presents syngas composition as a function of residence time in the ClearFuels gasifier. The tuning of syngas composition provides flexibility for various downstream processing and conversion options. The HEHTR process allows for the production of several high-value energy products such as renewable diesel, power, ethanol and hydrogen from a variety of cellulosic feedstocks. Wood waste from wood product facilities like sawdust or wood scrap and sugar mill waste like bagasse and cane trash are two examples of many inexpensive and readily available feedstocks. ClearFuels has stated that commercial HEHTR and downstream processing facilities are likely to be co-located with existing sugar mills and wood product facilities, which will reduce operating costs and increase operating efficiencies.
A summary of the ClearFuels HEHTR process design features and anticipated benefits are summarized in the table below.
Design Feature
Result Benefit
Indirect firing
Combustion separate from
Cleaner syngas with low tar
HEHTR
Gasifier Residence Time (seconds)
Syn
gas
Com
posi
tion
(m
ole%
)
Photo credit: http://www.rentech.com/clearfuels.php
Clear Fuels (Rentech)
SKIVE PROCESS DIAGRAM
DISTRICT HEATING 11.5 MWth
POWER 3x2 MWe
GAS FILTER
3 GAS ENGINES
BIOMASS, 28 MWth
FLY ASH
2 BOILERS
TO STACK
WATER
GAS SCRUBBER
GAS BUFFER TANK
2x10 MWth
BOTTOM ASH
AIR/STEAM
TAR REFORMER GASIFIER
GAS COOLERS
WOOD PELLETS
GASIFIER BODY
Carbona: SKIVE GASIFICATION CHP-PLANT, DENMARK 6 MWe and 12 MWth
February 2009
2 GAS BOILERS
3 JENBACHER GAS ENGINES
FLARE
Source: Carbona Status: >1000 hours with engines April 2009
Questions
