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8/12/2019 Biomass Co-Firing - Canadian Clean Power Coalition
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Appendix
CBiomass Co-firingA Final Phase III Report
Prepared by CCPC Technical Committee, November 2011
C a n a d i a n C l e a n P o w e r C o a l i t i o n : A p p e n d i x CC01
Table of Contents
1. Introduction ___________________________ C02
Part A Co-firing Results from Kema Study _____ C02
1. Introduction ___________________________ C02
2. Generic Biomass Co-firing Configurations ___ C02
3. Biomass Feedstocks ___________________ C03
3.1. Raw Biomass __________________________ C03
3.1.1. Wood Chips ___________________________ C04
3.1.2. Willow ________________________________ C04
3.1.3. Flax Straw ____________________________ C05
3.2. Modified Biomass ______________________ C05
3.2.1. Pelletized Biomass _____________________ C053.2.2. Torrefaction ___________________________ C08
4. Six Co-firing Configurations Studied ______ C10
5. Conclusions From KEMA Report _________ C21
5.1. Evaluation of Co-firing Options ___________ C22
5.2. Technical Ranking ______________________ C22
5.3. Financial and Risk Analysis of Biomass
Co-Firing Conversion ___________________ C23
5.4. Fuel Availability and Suitability ___________ C24
5.5. Optimum Co-firing Regimes and
Implications of Co-firing Retrofits
on Heat Rates _________________________ C25
Part B Co-firing Results from NS Power Study ___ C26
1. Introduction ___________________________ C26
2. Natural Gas Test Firing with Biomass _____ C263. Coal/Biomass Co-firing Tests ____________ C27
4. Coal/Biomass Co-firing Test Conclusions ___ C27
5. CFBC Testing __________________________ C27
Part C Co-firing Conclusions _________________ C28
1. Conditions for Employing Co-firing _______ C28
1.1. Preferences of Power Producers _________ C28
1.2. Conditions Which Must be Met Before
Co-firing Will be Adopted ________________ C28
2. Conclusions ___________________________ C30
Figure and Tables
Figure 1: Typical Biomass Co-firing Routes ________________________ C02
Table 1: Major solid biomass materials of industrial interest
on a worldwide basis ______________________________________ C03
Table 2: Relevant chemical properties of raw biomass feedstocks ______ C04
Table 3: Relevant physical properties of raw biomass feedstocks _______ C04
Figure 2: Typical pellet manufacturing and processing chain _________ C05
Table 4: Advantages and disadvantages for pelletization of
biomass fuel for co-firing ___________________________________ C06
Table 5: Typical specifications of wood and flax in original
and pelletized _____________________________________________ C07
Table 6: Properties of torrefied pellets compared to non-torrefied
fuel types (indicative) ______________________________________ C08
Table 7: Advantages and disadvantages for torrefaction of
biomass fuel for co-firing ___________________________________ C09
Table 8: Properties of some wood and willow biomass
types (indicative) __________________________________________ C09
Table 9: Physical Characteristics of Co-firing Plants _________________ C10
Table 10: Fuel Characteristics ____________________________________ C11
Table 11: Capital Costs for Co-firing Cases ________________________ C11
Table 12: Avoided CO2Emissions for Biomass _____________________ C12
Table 13: Rough Ranges of Biomass Feedstock Costs ______________ C12Table 14: Cost of Operating a Co-firing Plant in Millions
of Dollars per Year _________________________________________ C13
Table 15: Avoided Costs of CO2Reductions/Incremental
Cost of Power ____________________________________________ C13
Figure 3: Avoided Costs for Various Biomass Prices ________________ C14
Figure 4: Incremental Cost of Biomass Power for Various
Biomass Prices ___________________________________________ C15
Figure 5: Incremental Cost of Biomass Power _____________________ C16
Figure 6: Increase in Power Cost for Each Case ____________________ C17
Figure 7: Avoided CO2Cost Components _________________________ C18
Figure 8: Impact of Amortization Period on Avoided CO2Cost _______ C19
Table 16: Comparison of Costs to Comply with GHG Requirements _____ C19
Figure 9: Avoided CO2Cost of Natural Gas in a Coal Plant ___________ C20
Figure 10: Avoided CO2Cost for Wind at Three Power Prices ________ C20
Table 17: Technical ranking ______________________________________ C22
Table 18: Financial and risk ranking _______________________________ C23
Table 19: Fuel availability and suitability ___________________________ C24
Table 20: Likely feasible co-firing ranges and likelihood of
a resulting plant derate _____________________________________ C25
This report was prepared for the Canadian Clean
Power Coalition and its participants and associates
(collectively the CCPC). The information containedin this report maybe referenced by any other party for
general information purposes only. No other party is
entitled to rely on this report, in any manner whatsoever,
without the prior written consent of the CCPC. Under no
circumstances, including, but not limited to, negligence,
shall the CCPC be liable for any direct, indirect, special,
punitive, incidental or consequential damages arising out
of the use of this report or the information contained
herein by any other party.
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Coal Mills Burners Boiler
Pre-
treatment
Steam
Turbine
Biomass Mills
Flue Gas
Treatment
Gasifier Stack
1 2 3
4
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Introduction
The CCPC considers biomass co-firing as potential way to
reduce the CO2emissions from coal plants since biomass
is generally considered a carbon neutral fuel. During the
course of the CCPCs phase III work, it commissioned two
studies related to biomass co-firing. The first was preparedby Doug Campbell of Nova Scotia Power. The objective of
this study was to determine the maximum size of biomass
particle that could be successfully combusted in a coal
plant and to identify how co-firing with biomass will affect
the operation of the plant including thermal efficiency,
carbon burnout, slagging and fouling. The second study
was completed by KEMA Consulting. The objective of this
study was to characterize several fuels and determine the
operating consequences and capital cost of firing these
fuels in six co-firing configurations.
This report has three parts. Part A summarizes the work
completed by KEMA Consulting. Part B summarizes thework completed by Nova Scotia Power. Part C describes
some of the conclusions reached by the CCPC about what
would be required before a commercial scale biomass
co-firing project would be considered feasible. It also
includes conclusions reached from these studies and
the analysis completed.
Part A Co-firing Results from Kema Study
1. Introduction
As electric utilities search for ways to reduce carbon
dioxide (CO2) emissions from fossil-fuel fired power plants,
one of the most attractive and easily implemented options
is co-firing of biomass in existing coal-fired boilers. Co-firing
projects replace a portion of the nonrenewable fuel coal
with a renewable fuel biomass. In biomass co-firing, up
to 20%-30% of the coal is typically displaced by biomass.
The biomass and coal are combusted simultaneously.
When used as a supplemental fuel in an existing coal-firedboiler, biomass can provide the following benefits: lower
fuel costs, more fuel flexibility, reduced waste to landfills,
and reductions in sulfur oxide, nitrogen oxide, and CO2
emissions. Other benefits, such as decreases in flue gas
opacity, have also been documented.
2. Generic Biomass Co-firing Configurations
Biomass co-firing is currently a commercial technology for
coal-fired utility-scale power plants that has been tested in
a wide range of boiler types including cyclone, stoker,
pulverized coal, and fluidized bed boilers. Biomass co-firing
technology can be configured in several ways, dependingon the percentage of biomass to be co-fired and the design
of the specific boiler system. In general, there are four main
routes to accomplish co-firing, as shown in Figure 1.
1. Co-milling biomass with coal.
2. Separate milling, injection in pulverized-fuel (pf)
lines, combustion in coal burners.
3. Separate milling, combustion in dedicated
biomass burners.
4. Biomass gasification, syngas combusted infurnace boiler.
Figure 1: Typical Biomass Co-firing Routes
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C a n a d i a n C l e a n P o w e r C o a l i t i o n : A p p e n d i x C C03
Co-milling biomass with coal and separate milling and
injection/combustion of biomass in the coal burners are
the most common applications of biomass co-firing when
the overall percentage of biomass to coal is relatively
small (
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For the KEMA study, a set of raw biomass feedstock types
were selected to be representative of a broad spectrum of
possibly available feedstocks. In addition, a premise of the
study was that the selected feedstocks should avoid potential
for competition with food production and should be capable
of being grown and harvested in a sustainable manner.
General properties of the selected raw biomass
feedstocks wood chips, willow, and flax straw
are summarized in Table 2 and Table 3.
Table 2: Relevant chemical properties of raw biomass feedstocks
Wood chips Willow Flax Relation to
Moisture Humid Humid-Wet Dry Drying
Ash Low Low-Moderate Low Ash retention
Calorific value (dry) High Moderate High Capacity & efficiency
Sulphur Low Low Low Emissions
Chlorine Low Moderate-High High Corrosion
Table 3: Relevant physical properties of raw biomass feedstocks
Wood chips Willow Flax Relation to
Bulk density Moderate Moderate Low Sizing, transport
Fibrousness High High Moderate Milling
Homogeneity High Moderate High Operational window
The following subsections summarize the relevant
characteristics of the raw biomass feedstocks. Since
specifications of biomass can vary from sample to sample,
a range and typical value are presented for each feedstock.
3.1.1. Wood Chips
The properties of wood chips can vary significantly
depending on numerous factors, e.g., type of wood, location
of growth, and the harvesting method. See Table 5. The
moisture content of freshly harvested wood typically ranges
between 40-50 wt% as received (ar). Open storage can
reduce the moisture content to a level of 10 to 20 wt%.
The ash content increases when bark or impurities such as
sand are mixed with the fuel. Core wood without bark or
other impurities such as sand typically has an ash content
of about 0.5 wt% (dry base). A clean harvesting method
is important to keep the ash content as low as possible.
Sulphur levels in wood are significantly lower when
compared to typical coal values. On the other hand,
chlorine, calcium and (earth) alkali levels are somewhat
higher than in coal, thereby increasing the risks of slagging
and fouling in the boiler. It should be noted that Nova
Scotia Power did not find slagging or fouling issues with
high proportions of wood chip firing.
3.1.2. Willow
Short rotation coppice (SRC) consists of dense plantations
of high-yielding varieties of either poplar or willow. During
harvesting, which typically occurs on a 2-5 year cycle, only
the shoots are removed, leaving behind the roots to allow
for re-growth. SRC is harvested as rods, chips, or billets
with a moisture content of 50-60 percent. In the UK, yields
have been reported between 5-18 oven dry metric ton per
hectare per year. The major causes of this variation are the
species planted, the conditions of the site on which the
SRC is planted, and the efficiency of harvesting. 2
Willow feedstock is assumed to be fired as freshly harvested
wood. This type of biomass will be quite humid and will not
emit much dust. The physical properties can vary depending
on the biomass production. Compared to typical wood
chips, willow can have a somewhat higher moisture and ash
content. Table 8 summarizes the characteristics of willow.
2 Themba Technology Ltd, Evaluating the sustainability of co-firing in the UK, September 2006.
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3.1.3. Flax Straw
Flax is an important agricultural crop in Canada. For
example, Saskatchewan producers plant 1.4 million
acres of flax each year. 3Flax is considered as a favorable
addition to many farmers crop rotations. A constraint
to flax production however is dealing with the flaxstraw residue.
Because flax has a significant percentage of long tough
stem fibers that decay slowly, it is difficult to incorporate
flax straw into the soil after harvest. Flax straw used to
be burned directly on the land, but today this practice is
discouraged for a number of reasons. Currently, chopping
and spreading is the preferred alternative but co-firing flax
straw in a coal-fired power plant can be a good alternative
as well. Table 5 summarizes the characteristics of
flax straw.
The chlorine content of flax straw is considerably higherthan that of wood chips or willow. To keep chlorine
corrosion within reasonable levels, the waste incineration
business has established a rule of thumb to keep the
sulphur to chlorine ratio above 4 (S/Cl > 4) at all times.
This means that co-firing percentage of flax straw needs
to be limited because of this ratio.
3.2. Modified Biomass
A number of methods are available, or are being developed,
that can improve the quality of raw biomass, render a more
homogeneous product, reduce shipping costs, improve
handling characteristics, and make processing of the
biomass at the power plant site more effective. Severalof the more prominent methods are described below.
3.2.1. Pelletized Biomass
Pellets are attractive for co-firing applications because:
they have a high calorific density, which makes them
more economical when fuel must be transported over
a long distance
they can be used on-site with limited on-site
modifications and equipment investments
they can be used at high percentages, often with
limited boiler derate due to their cylindrical geometry pellets can be stored
in silos and can easily be transported by all feeding
equipment mechanical and pneumatic
A typical pellet manufacturing processing chain is
presented in Figure 2.
Figure 2: Typical pellet manufacturing and processing chain
Green
hammer mill Dryer
Dry
hammer mill
Pellet
press
Pellet
cooler
Peller
storage
Feedstock Off-site
Pre-processing
Pelletizing
facility Port Product
3 www.saskflax.com
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The quality of the milling and pelletization process is
essential for obtaining the desired particle size after
on-site milling and consequently good feeding behavior.
The quality of the pelletizing process itself is very much
dependent on the original biomass type. Generally it can
be said that the softer the wood (high content of lignin),
the easier the pelletizing.
Arguments for and against applying pelletization as a biomass
pre-treatment technology for co-firing are listed in Table 4.
Table 4: Advantages and disadvantages for pelletization of biomass fuel for co-firing
Advantages Disadvantages
High energy density pellets (transport) Some fuels difficult to pelletize
Known technology Dust (HSE)
Not a lot of heat is required for drying Wear of mills (soil)
Fully commercial Operations sensitive to input material
All over the world Odor can be an issue
Normally high availability Expensive to produce
Experience with pellet specifications Pellets sensitive to moisture
Pellets are applied at large scale
Various input products possible
Easier to process at power plant site
Important issues around wood pellets include:
sustainability of the raw material (certification)
product quality
setting up the right technical specifications for the
wood pellets
good quality assurance and quality control
management system
When the pellets are not of a consistent and continuous
quality, the effects on power plant operations may be
significant. These include (but are not limited to):
difficulty with unloading at receipt
limited storage capacity
on-site formation and emission of dust
problems with dust staining in the conveyors
risk of (self) ignition
wear of the mills
not achieving the appropriate mill throughput
ash quality deterioration
value of the pellets (energy density may decrease)
loss of boiler heat rate (due to high moisture or low
burn out)
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Table 5 presents ranges and typical values for raw and pelletized woody and flax-type of biomass.
Table 5: Typical specifications of wood and flax in original and pelletized
Wood Flax straw
Chips Pellets Chopped or baled Pellets
Proximate analysis range range typical range typical
Moisture (% wt ar) 10-50 4-7 6 6.5-8.5 6
Ash (% wt db) 0.3-3 0.3-3 1 2-6 4
Volatiles (% wt db) 70-85 70-85 80 80-81 81
Fixed carbon (% wt db) 15-25 15-25 19 13-18 15
HHV (MJ/kg dry) 19-21 19-21 20 19.5-20.5 20
Bulk density (kg/m3) 200-250 600-750 700 70-140 700
Ultimate analysis (% wt db)
C 48-52 48-52 50 49-51 50
H 5.5-6.5 5.5-6.5 6 5.2-6.3 5.8
N 0.1-1 0.1-1 0.3 0.6-1.3 0.8
S 0.04-0.2 0.04-0.2 0.08 0.07-0.17 0.13
O 38-46 38-46 42 42-45 43
Cl 0.01-0.05 0.01-0.05 0.02 0.04-0.4 0.2
K 0.02-0.4 0.02-0.4 0.1 0.3-0.5 0.4
Ca 0.1-1.5 0.1-1.5 0.7
A substantial amount of experience has been gained with
co-firing wood pellets, and when the quality and supply of
biomass pellets can be assured it is an attractive option
for co-firing significant amounts of biomass.
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3.2.2. Torrefaction
Torrefaction is a thermal pre-treatment technology that
produces a solid biofuel product with superior handling,
milling and co-firing characteristics as compared to
other biofuels.
KEMA foresees that torrefaction will play an important
role in co-firing biomass at coal-fired power plants in the
future. At present, torrefaction technology is making its
first careful steps towards commercialization, while the
technology and product quality are still surrounded by
uncertainties. Nevertheless, some European utilities have
taken the risk by signing long-term off-take contracts with
torrefaction suppliers, which indicates torrefaction is
gaining momentum.
Table 6 shows typical physical and chemical properties of
torrefied solid fuels, compared to non-torrefied fuels. Thetable shows that when biomass is torrefied and
subsequently pelletized, the product has similar handling,
milling, and transport requirements as coal. However,
more tests are required on torrefied materials to
substantiate these characteristics.
Table 6: Properties of torrefied pellets compared to non-torrefied fuel types (indicative)
Wood Wood pellets Torrefaction pellets Charcoal Coal
Moisture content (% wt) 30-45 7-10 1-5 1-5 10-15
Calorific value (MJ/kg) 9-12 15-16 20-24 30-32 23-28
Volatiles (% db) 70-75 70-75 55-65 10-12 15-30
Fixed carbon (% db) 20-25 20-25 28-35 85-87 50-55
Bulk density (kg/l) 0.2 -0,25 0.55-0.75 0.75-0.85 ~ 0.20 0.8-0.85
Volumetric energy density (GJ/m3) 2.0-3.0 7.5-10.4 15.0-18.7 6-6.4 18.4-23.8
Dust Average Limited Limited High Limited
Hydroscopic properties Hydrophilic Hydrophilic hydrophobic hydrophobic hydrophobic
Biological degradation Yes Yes No No No
Milling requirements Special Special Classic Classic Classic
Handling properties Special Easy Easy Easy Easy
Product Consistency Limited High High High High
Transport cost High Average Low Average Low
Many torrefaction reactor technologies exist, and more
are under development. Some reactor technologies are
being proven. These include:
Rotary drying drum
Multiple Hearth Furnace (MHF) or Herreshoff oven
TurboDryer
Torbed reactor
Screw conveyor reactor
Compact moving bed Belt dryer
Most of the torrefaction technology development takes
place in the Netherlands, Belgium, France, Canada, and
the United States. Torrefaction development is performed
by companies and research institutes such as CDS,
Torr-coal, BIO3D, EBES AG, CMI-NESA, Wyssmont/
Integro Earth Fuels, Topell, BTG, Biolake, FoxCoal, ETPC,
Agri-tech producers, ECN, Torspyd/Thermya, Buhler,
Stramproy, NewEarth Eco Technology, etc. Some of these
initiatives have not passed the exploration phase, while
others have proven pilots and are in the demonstrationphase. Which technology performs best depends on the
functional requirements, fuel specifications, heat source,
and development status.
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Table 7: Advantages and disadvantages for torrefaction of biomass fuel for co-firing
Advantages Disadvantages
Produces high energy density pellets (transport) Pelletization requires additives (chemicals)
Material is brittle(easy milling) Tar formation (operations)
Material is hydrophobic(storage) Odor (HSE)
Many proven initiatives exist (technology) Loss of some volatiles (energy, HSE)
Demonstrators being built (40-70 kt/a)(scale) Little experience heterogeneous input (flexibility)
Can use large amounts with little capex modifications to boiler Particle size and shape sensitive (operations)
Combustion not really known (operations)
Cooling for ignition prevention (HSE)
No full scale demonstrations operational
Apart from the reactor technology, the performance of
torrefaction is heavily dependent on the heat integration
design. Although heat can be integrated in various ways,
all torrefaction developers apply the same basic design in
which the volatiles are combusted in an afterburner and
the flue gas is used to heat the pre-drying process and the
torrefaction process.
Arguments for and against applying torrefaction as a biomass
pre-treatment technology for co-firing are listed in Table 7.
Torrefaction is becoming a viable technology that could be a
cost-effective method for utilities wanting to co-fire significant
amounts of biomass. The cost savings can be achieved in
long distance transport, biomass handling, and processing.
In addition it is believed coal boilers will require very little
modification to use substantial quantities. However, the
technology and product quality is still surrounded byuncertainties. The first generation torrefaction technology
is most likely to operate with wood chips, as this biomass
feedstock brings the lowest technical and financial risks.
Table 8: Properties of some wood and willow biomass types (indicative)
Wood Willow
Chips Torrefied pellets Chipped Torrefied pellets
Proximate analysis range range typical range typical
Moisture (% wt ar) 10-50 1-5 3 50-60 3
Ash (% wt db) 0.3-3 0.3-5 1 1-4 2
Volatiles (% wt db) 70-85 55-70 65 80-90 70
Fixed carbon (% wt db) 15-25 28-45 34 10-20 28
HHV (MJ/kg dry) 19-21 20-24 21 18-21 21
Bulk density (kg/m3) 200-250 750-850 800 750
Ultimate analysis (% wt db) range range typical range typical
C 48-52 50-65 60 46-51 55
H 5.5-6.5 5-6 5.5 5.5-6.5 5.5
N 0.1-1 0.1-1 0.3 0.2-1 0.3
S 0.04-0.2 0.04-0.2 0.08 0.02-0.1 0.08
O 38-46 30-40 33 40-46 37
Cl 0.01-0.05 0.01-0.05 0.02 0.01-0.05 0.02
K 0.02-0.4 0.02-0.4 0.1 0.2-0.5 0.1
Ca 0.1-1.5 0.1-1.5 0.7 0.2-0.7 0.7
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4. Six Co-firing Configurations Studied
The CCPC commissioned KEMA to evaluate several
co-firing configurations employing different proportions
of biomass firing and fuels. Those six configurations are
described below.
Case 1: 10% (by thermal input) flax pellets co-fired in
a 150-MWe lignite-fired boiler with an assumed heat
rate of 11,500 Btu/kWh
Case 2: 60% co-firing of torrefied willow pellets in
a 150-MWe lignite or bituminous-fired boiler, with
an assumed heat rate of 9,600 Btu/kWh for the
bituminous-fired boiler and an assumed heat rate
of 11,500 Btu/kWh for the lignite-fired boiler
Case 3: 60% wood pellet co-firing in a 400-MWe
sub-bituminous-fired boiler, with an assumed heat
rate of 10,000 Btu/kWh
Case 4: 60% co-firing of torrefied wood pellets in a
400-MWe sub-bituminous-fired boiler, with an
assumed heat rate of 10,000 Btu/kWh
Case 5: complete retrofit of a 150-MWe pulverized-
lignite-fired boiler, with an assumed heat rate of
11,500 Btu/kWh into a bubbling fluidized-bed boiler
firing 100% wood chips having a new capacity
of 100 MWe
Case 6: 20% wood chip co-firing in a 150 MWesub-bituminous-fired boiler, with an assumed heat
rate of 10,000 Btu/kWh
Unfortunately in the KEMA study the CO2intensity of
a sub-bit unit was used for Case 6. To best match the
numerical values for case 6 in the KEMA study, the heat
rate for a lignite unit was replaced in this report with that
for a sub-bit unit for Case 6.
The following table describes some of the key features of
the six co-firing plants evaluated by KEMA and assumed
in the economic modeling. Thermal input refers to the %
of the thermal input provided by biomass. Fuel displacedrefers to the amount of coal displaced by the biomass
on a GJ basis. The torrefied material for cases 2 and 4
were pelletized.
Table 9: Physical Characteristics of Co-firing Plants
Biomass Fuel case # Plant Type
Plant
Capacity
(MW) Thermal Input
Capacity
Factor
Base Heat
Rate (GJ/
MWh)
Fuel
Displaced
(GJ/hr)
Pelletized Flax 1 Lignite 150 10% 70% 11.5 173
Torrefied Willow 2 Bituminous 150 60% 70% 9.6 864
Pelletized Wood 3 Sub-Bit 400 60% 70% 10.0 2,400
Torrefied Wood 4 Sub-Bit 400 60% 70% 10.0 2,400
Wood Chips 5 Retrofit BFB 150 100% 70% 11.5 1,725
Wood Chips 6 Sub-Bit 150 20% 70% 10.0 300
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The following table describes the characteristics of the
biomass fuel. The values are based on the characteristics
of dried fuel. Nova Scotia Power did not find a derate firing
20% wood chips. Derates may be incurred if the biomass
reduces the efficiency of the boiler or if additional power
is required to process, grind or hammer mill the biomass.
Table 10: Fuel Characteristics
Biomass Fuel case #
Heat Content
Biomass (GJ/t)
Mass of
Biomass (t/hr)
Density
(kg/m3)
Volume of
Biomass (m3/hr)
Derate
(MW)
Pelletized Flax 1 20 8.6 700 12 0
Torrefied Willow 2 23 37.6 700 54 1
Pelletized Wood 3 20 120.0 700 171 3
Torrefied Wood 4 23 104.3 800 130 2
Wood Chips 5 20 86.3 250 345 50
Wood Chips 6 20 15.0 250 60 4
The table below shows the rough capital costs identified for each case.
Table 11: Capital Costs for Co-firing Cases
Biomass Fuel case # Capex ($m) Capex ($/kWth)
Pelletized Flax 1 6.7 447
Torrefied Willow 2 7.9 88
Pelletized Wood 3 49.4 206
Torrefied Wood 4 12.2 51
Wood Chips 5 43.3 289
Wood Chips 6 21.9 730
Capital costs include those costs directly related to the
on-site equipment to be installed and modified, includingengineering, procurement, and construction (EPC), civil
works, development, and owners costs (based on eastern/
Midwestern U.S. cost indices). Interest during construction,
tax, on-site operational costs during commercial operations,
loss-of-income due to derate, fuel purchase and
transportation costs for pellets, wood chips, etc., and
renewable energy or CO2emission certificates were
excluded. The capital costs are estimated with an accuracy
of +/- 50% given the high-level character of this study.
The following table shows the CO2intensity of the plant
operating on coal. This is followed by the amount of CO2
produced by the coal plant before co-firing. There are two
significant sources of CO2associated with biomass
co-firing. First there are the emissions associated with
processing the biomass. A significant amount of drying and
grinding may be involved to produce the fuel. Biomassco-firing may also derate the plant since biomass is often a
lower quality fuel with a lower heat content than the coal
being replaced. It is assumed that all of the emissions
associated with coal displaced are avoided. However, the
fossil fuel emissions related to offsite processing and for
replacing the lost power must be added back to determine
the amount of CO2avoided. The net CO2avoided is used
to calculate the revised CO2intensity.
In this report CO2Avoided is calculated based on the
values in Table 12. CO2Avoided is equal to CO2Before
Conv CO2Before Conv x % Co-fired CO2from Offsite
CO2from replaced power. The Revised CO2Intensity is
equal to (CO2Before Conv CO2Avoided) / MWh
produced in year.
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Cases 2, 3 and 4 were chosen to meet a CO2intensity
similar to that for a natural gas combined cycle unit. This
may be the intensity the Federal government may require
coal plants to meet in the future. Case 5 has a CO2
intensity close to zero because 100% of the fuel in this
case is biomass. Case 6 provides only 20% of the fuel
from biomass. Therefore the CO2intensity is reduced by
about 20% assuming biomass is a carbon neutral fuel.
Table 12: Avoided CO2Emissions for Biomass
Biomass Fuel case #
Base CO2
Intensity
(t/MWh)
CO2 Before
Conv
(kt/yr)
CO2from
Offsite Process
(kt/yr)
CO2from
replaced
power (Kt/yr)
CO2
Avoided
(kt/yr)
Revised CO2
Intensity
(t/MWh)
Pelletized Flax 1 1.18 1,085 3 0.0 106 1.07
Torrefied Willow 2 0.91 837 30 5.6 467 0.40
Pelletized Wood 3 1.00 2,453 53 18.4 1,400 0.43
Torrefied Wood 4 1.00 2,453 83 12.3 1,376 0.44
Wood Chips 5 1.18 1,085 0 361.8 724 0.00
Wood Chips 6 1.00 920 0 24.5 159 0.83
The next table provides assumed ranges for the cost of
obtaining biomass feedstocks. These values are based
on rough estimates from internal sources and some
published material. The CCPC did not study fuel costs in
phase III. However, biomass feedstock costs represent
the most significant cost associated with biomass
co-firing. Biomass feedstock costs are highly dependent
upon the type of biomass involved, the cost to process
the fuel, the location of the raw fuel, the volume available
and the distance it must travel to the power plant, etc.
For this reason a range of values were studied. A great
deal more work would be required to refine these cost
estimates for a given plant. The fuel costs on the right
hand side of the table below include both the biomass
cost and transportation costs to move the biomass to
the power plant site. The coal cost for Case 2 is high
because it represents the cost for expensive imported
coal in Nova Scotia.
Table 13: Rough Ranges of Biomass Feedstock Costs
Biomass Fuel case #
Coal Cost
($/GJ)
Biomass Cost
Low ($/t)
Biomass Cost
High ($/t)
Transport to
Site ($/t)
Fuel Cost
Low ($/GJ)
Fuel Cost
High ($/GJ)
Pelletized Flax 1 1.0 120 150 10 6.5 8.0
Torrefied Willow 2 4.0 160 200 10 7.4 9.1
Pelletized Wood 3 1.0 130 182 10 7.0 9.6
Torrefied Wood 4 1.0 160 220 10 7.4 10.0
Wood Chips 5 0.0 60 100 10 3.5 5.5
Wood Chips 6 1.0 60 100 10 3.5 5.5
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The following table shows the rough costs for burning
biomass in a coal plant for a year. The net fuel costs were
based on the costs per tonne identified above and the
heat content of the fuels less the cost of coal displaced.
The O&M charge was based on a study by Dr. Zhang 4.
The value of lost power is the opportunity cost associated
with not being able to sell the power, at $90/MWh,
associated with plant derates. The capex was taken from
above and multiplied by a capital recovery factor to define
a yearly value. This was divided by the operating hours
assumed. The two columns on the right show the range
of costs in millions of dollars per year for the low and high
fuel costs. These values were used in the derivation of the
avoided costs of CO2for the cases.
Table 14: Cost of Operating a Co-firing Plant in Millions of Dollars per Year
Biomass Fuel case #
Net Fuel
Cost Low
($/yr)
Net Fuel
Cost High
($/yr)
O&M
($/yr)
Value of
Lost Power
($/yr)
Capex
($/yr)
Total Cost
Low
($/yr)
Total Cost
High
($/yr)
Pelletized Flax 1 5.8 7.4 0.2 0.0 1.0 7.0 8.6
Torrefied Willow 2 18.0 27.2 0.7 0.6 1.2 20.4 29.6
Pelletized Wood 3 88.3 126.6 1.5 1.7 7.2 98.7 137.0
Torrefied Wood 4 94.1 132.5 0.8 1.1 1.8 97.7 136.1
Wood Chips 5 37.0 58.2 1.8 27.6 6.3 72.7 93.9
Wood Chips 6 4.6 8.3 0.6 2.2 3.2 10.6 14.3
The table below shows the estimates for cost of CO2
reduction and the incremental cost of power produced
from the biomass. The values in the right hand were
divided by the avoided CO2emissions for a year to
determine the avoided cost. The total cost per year
were also divided by the energy produced by biomass
for each case to determine the incremental cost
of power in $/MWh basis. However, the remaining
costs for operating the plant may change very little
except that less coal will be used. Therefore biomass
co-firing will generally increase the cost of operating
the plant.
Table 15: Avoided Costs of CO2Reductions / Incremental Cost of Power
Biomass Fuel case #
Avoided Cost Low
($/t)
Avoided Cost High
($/t)
Incr.Cost Low
($/MWh)
Incr.Cost High
($/MWh)
Pelletized Flax 1 66.5 81.6 76.3 93.6
Torrefied Willow 2 43.7 63.4 36.9 53.6
Pelletized Wood 3 70.5 97.8 67.1 93.1
Torrefied Wood 4 71.0 98.9 66.4 92.5
Wood Chips 5 100.5 129.7 79.0 102.0
Wood Chips 6 66.6 89.7 57.7 77.7
4 Life Cycle Emissions and Cost of Producing Electricity from Coal, Natural Gas, and Wood Pellets in Ontario, Canada,
Yimin Zhang, University of Toronto, 20 November, 2009.
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The figure below shows the avoided costs for the six co-firing configurations as the cost of biomass fuel varies.
Figure 3: Avoided Costs for Various Biomass Prices
40
60
80
100
120
140
0 50 100 150 200 250
AvoidedCO
2
Cost($/t)
Biomass Cost ($/t)
1 10% FP
2 60% TW
3 60% WP
4 60% TW
5 100% WC
6 20% WC
Cases 2 and 4 both employ torrefied wood. The reason
Case 2 has such a low avoided CO2cost is that it displaced
coal priced at $4.00/GJ compared to $1.00/GJ for the other
cases. Case 5 is expensive because it is based on a
complete retrofit of the plant to a bubbling fluidized bed.
The capital cost for this case and the significant derate
associated with this retrofit contribute most to the
additional costs. Cases 1 and 3 have a similar range of fuel
costs. Case 6 is based on firing 20% wood chips. The cost
for the fuel is expected to be relatively low. However,
the capital cost for this case is relatively high.
The avoided costs in this graph could be compared to
the costs to reduce CO2emissions by carbon capture
processes. However, the fuel costs would need to be
refined to make a more accurate comparison. One of the
advantages of biomass co-firing is that it is more mature 5
than carbon capture and therefore may have less risk.
5 The biomass co-firing experience is generally at lower percentages of co-firing.
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The following figure shows the cost of producing power
with biomass fuel. This incremental cost includes the cost
to co-fire the fuel less the cost of coal displaced. A
proportion of the cost for this power must be added to the
cost for the underlying plant and in all cases will have the
effect of increasing the overall cost of power from the plant.
30
40
50
60
70
80
90
100
110
0 50 100 150 200
CostofBiomassPower($/MWh)
Biomass Cost ($/t)
1 10% FP
2 60% TW
3 60% WP
4 60% TW
5 100% WC
6 20% WC
Case 2 suggest that torrefied wood may have the lowest
incremental cost even though the cost of the fuel is
expected to be relatively high. Recall the reason the Case
2 costs are lower than Case 4 costs is related to the
assumption that expensive bituminous coal imported by
sea is being displaced in Case 2 compared to mine mouth
coal in Case 4. Case 6 has a cost which is expected to be
slightly lower than all the other cases except for Case 2.
Figure 4: Incremental Cost of Biomass Power for Various Biomass Prices
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0
20
40
60
80
100
120
1
10%
FP
2
60%
TW
3
60%
WP
4
60%
TW
5
100%
WC
6
20%
WC
IncrementalPower($/M
Wh)
Net Fuel High
Net Fuel Low
Derate
O&M
Capex
The figure below shows the cost components for the incremental cost of producing power with biomass for each case.
Figure 5: Incremental Cost of Biomass Power
The purple bar shows the fuel costs assuming fuel has
a low cost. The orange bar is added to the purple bar to
show the total net fuel cost for the high case. Clearly fuel
costs account for most of the incremental costs in each
case. Case 5 has a substantial opportunity cost associated
with not being able to sell a significant amount of power
at $90/MWh because of the significant derate. Likewise
Case 6 also have a substantial opportunity cost associated
with a plant derate. As mentioned above Case 6 has a
relatively high capital cost compared to the other cases.
Cases 2, 3 and 4 have very low capital costs requirements
because the torrefied wood and wood pellets required
very little capital costs modification to use the fuel directly
in the coal boiler and because the fuel is delivered dry.
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The figure below shows the expected increase in
power costs associated with adding biomass co-firing
to an existing plant. Given that case 1 has such a small
proportion of co-firing it will have a smaller impact on the
overall cost of power production from a plant than the
other cases. Since case 5 essentially replaces 100% of
the output of the plant the average cost of power for this
case will increase by the full amount shown above.
Figure 6: Increase in Power Cost for Each Case
0
20
40
60
80
100
120
1
10%
FP
2
60%
TW
3
60%
WP
4
60%
TW
5
100%
WC
6
20%
WC
IncreaeinPowerCost($/MWh)
Net Fuel High
Net Fuel Low
Derate
O&M
Capex
As mentioned above Case 5 is based on a significant
retrofit of the plant and as such incurs significant capital
costs. As described above Case 2 has a modest fuel cost
increase because expensive bituminous coal is being
replaced and its cost is subtracted from the biomass fuel
cost. Cases 1 and 6 show modest increases in power
costs because the proportion of fuel displaced is
relatively small.
The fuel costs represent the majority of the marginal costs
associated with co-firing. It may be that the plants will be
incented to operate with co-firing as a strategy to reduce it
CO2emissions as part of a scheme to comply with GHG
or other emission regulations. If this is the case the plant
may not have the option to operate without co-firing. This
is an issue for plants in markets like Alberta, which
generally encourage supply offers for power based on
marginal cost. The fuel costs in the graph above show the
impact of co-firing on the average marginal cost of the
unit. That is the average marginal cost for the unit is
expected to increase by at least the costs associated with
the purple bars. These higher marginal costs will likely
have the effect of decreasing the amount of time the plant
is economically able to operate. These higher costs may
force the plant to dispatch at lower output or come off
line more often for economic reasons. The marginal
cost for most carbon capture technologies is likely to
be much lower than those in the graph above for similar
reductions in CO2emissions because most carbon
capture costs are fixed.
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The following figure shows the costs which make up the avoided CO2costs for each of the cases.
Figure 7: Avoided CO2Cost Components
0
20
40
60
80
100
120
140
1
10%
FP
2
60%
TW
3
60%
WP
4
60%
TW
5
100%
WC
6
20%
WC
AvoidedCO
2
Cost($/t)
Net Fuel High
Net Fuel Low
Derate
O&M
Capex
The most significant cost associated with carbon capture is
generally capital cost. It should be noted that capital costs
for most of the co-firing cases represents a relatively small
proportion of the overall costs. Unlike carbon capture,
biomass co-firing does not put nearly as much capital at risk
to reduce a tonne of CO2emissions. However, the cost of
biomass co-firing is clearly more dependent on fuel costs
than carbon capture. Except for Case 5, derates associated
with biomass co-firing are also expected to be significantly
lower than for many carbon capture technologies.
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The figure below shows the impact of amortizing a co-firing
and a post combustion capture project over 5 to 25 years. It
is assumed that the capital component of the avoided CO2
cost for a co-firing project constitutes 10% of $100/t. It is
assumed that the capital component of the avoided CO2
cost for a post combustion CO2capture project constitutes
50% of $100/t. Given that co-firing projects are expected tohave a relatively low capital cost component they are a more
attractive option when a plant is expected to operate for
less than 20 years. Even if the co-firing project is operated
for only 5 years the avoided CO2costs only increases by
10% compared to a 25 year project. Generally it is expected
that if post combustion capture is going to be added to an
old plant significant life extension costs will be incurred to
allow the plant to operate over a further 20 years. Therefore
co-firing may be a more attractive option for retrofitting coalplants with short economic lives than other more capital
intensive options like post combustion capture.
Figure 8: Impact of Amortization Period on Avoided CO2Cost
100
105
110
115
120
125
130
135
140
145
150
0 5 10 15 20 25 30
AvoidedCO
2
Cost($/t)
Project Term (years)
Post Combustion
Co-firing
If the Canadian Government requires old coal plants toadopt an NGCC CO2intensity, and the economic life of the
plant is short, it may not make sense to add a lot of capital
to the plant to capture CO2. It may however make sense
to employ large amounts of wood pellets or torrified
material even if the price of the fuel is expensive. Table 16
shows the cost to employ biomass to reduce the CO2
intensity of a coal plant by 0.6 t/MWh. The incremental
cost would increase by $40 to $60/MWh. If the plants
capital is written off, there may be $20/MWh of O&Mremaining. The average cost would be about $60 to $80/
MWh. However, if carbon capture is employed for a 5 year
period the incremental cost would be about $90/MWh and
the average cost would be $110/MWh. Employing
biomass rather than carbon capture for older plants with
short economic lives may make sense. However, the
marginal cost of the plant employing biomass will be high.
Table 16: Comparison of Costs to Comply with GHG Requirements
Bio Low Bio High CC Low CC High
Biomass Cost ($/t) 130.0 182.0
Net Fuel Cost ($/GJ) 6.0 8.6
Avoided Cost ($/t) 70.5 97.8 100.0 150.0
Incremental Cost ($/MWh) 42.3 58.7 60.0 90.0
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-20
-10
-
10
20
30
40
50
60
70
80 85 90 95 100 105 110
AvoidedC
O2
Cost($/t)
Market Power Price ($/MWh)
$120/MWh
$110/MWh
$100/MWh
Price of
Wind Power
20
40
60
80
100
120
140
160
4.0 5.0 6.0 7.0 8.0 9.0 10.0
AvoidedCO
2
Cost($/t)
Gas Price $/GJ
$1/GJ Coal Price
$2/GJ Coal Price
Coal plants can also be co-fired or repowered with natural
gas. However, natural gas delivers less radiant heat per
gigajoule than coal. This can seriously impact the
performance of the boiler particularly as it relates to energy
transfer in the waterwalls and may require significant boiler
modifications. The graph below shows the avoided cost
assuming natural gas is used to replace coal at two coal
prices. The natural gas is assumed to be burned with a heat
rate of 10 GJ/MWh. The avoided CO2costs appear low at
low gas prices, but increase significantly as gas prices
increase. This graph only includes fuel costs and does not
account for any other costs related to plant modifications,
such as burner and pressure part modifications, required to
combust natural gas in the boiler.
Figure 9: Avoided CO2Cost of Natural Gas in a Coal Plant
The combustion of biomass to make power is generally
considered to be a renewable process. Wind is also
considered a renewable process. The following graph is
based on the assumption that wind displaces 0.65 t CO2/
MWh. Wind may offer a low avoided cost and may be anattractive may to reduce GHG emissions. However,
credits from wind may not be allowed to be used to allow
coal plants to meet regulatory requirements to reduce
GHG emissions. The avoided CO2cost is calculated as the
difference between the cost of wind and the market
power price divided by 0.65t/MWh. The national average
emission intensity is closer to 0.2t/MWh. Using this figurewould cause the avoided costs of wind to increase by
more than threefold.
Figure 10: Avoided CO2Cost for Wind at Three Power Prices
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5. Conclusions From KEMA Report
The feasibility of biomass co-firing at a coal-fired power plant
is highly dependent on the availability of biomass fuels, the
processing required to modify the fuels for consumption in
the power plant, the on-site characteristics of the power
plant, and the degree of tolerance for modifications thatmight result in output derates of the power plant. While this
study looked only at capital costs associated with a co-firing
conversion, it is the balance between capital costs, fuel
costs, other operational costs, and regulatory requirements
compared to the cost of other options to meet these
requirements that will determine the economic feasibility
of specific biomass co-firing projects.
In general, a specific biomass supply and market
study is needed to determine the availability and cost
of fuels and cost of transporting fuel to the plant. This
can be completed on a fleet basis or individual plant
basis. International trading in wood pellets is wellestablished. Therefore, a fuel market and supply
study can be performed with reasonable accuracy
and reliability, and helps in creating a reliable biomass
co-firing business case.
The suitability of certain types of biomass is always
dependent on the percentage of co-firing, boiler type,
coal type, etc. Flax needs special attention because of
its potential to cause corrosion. Torrefied material is
attractive as it is thought that it can be milled directly
in a coal mill. However, to date no real large-scale
experience exists using torrefied
material in a coal plant.
Converting a boiler to high percentages of biomass
(or even complete retrofit) will likely lead to an output
derate and heat rate penalty. This will certainly require
a closer look at the individual feasibility of these
measures, and associated conceptual design. In
this context, large (lignite) fired boilers are generally
thought to be more attractive for complete retrofit, as
large boilers are likely to suffer less from a significant
output derate.
Drying of biomass may be an option in cases where
biomass can be collected from various suppliers in
locations near the power plant. Heat that is present
in the flue gas may be used for drying, and if not
available, steam at a low temperature could be a
candidate. This may induce some output derate,
depending on the amount and quality of steam
that is required.
For both wood pellets and torrefied material, it is
recommended that utilities secure fuel supply, and
leverage responsibilities to the suppliers where
possible. If supply and fuel quality cannot be
secured and power generation capability must be
maintained at all times, multifuel handling options
should be considered.
Regulatory aspects should not be forgotten in the
co-firing business case. However, it is recommended
to secure subsidy tariffs for an extended period oftime, if applicable.
The timeline for initiating, engineering, designing,
tendering, realizing, commissioning, and obtaining
stable commercial operation with a secure biomass
supply and minimal heat rate penalty and/or output
derate, is often in the order of 5 to10 years. This
timeline for low biomass percentages and wood
pellet co-firing may take around 5 to 7 years. Nova
Scotia Power prepared to fire 20% biomass over a
4 year period. Using torrefied materials may shorten
this timeline, however, it is dependent on how quickly
manufacturers can deliver torrefied pellets. Torrefiedpellets will most likely come at a significant cost,
even if they might become available without having
bilateral contracts in place with specific suppliers. The
timeline for complete retrofits (e.g., BFB installation)
or high percentages of co-firing utilizing different types
of wet biomass are likely to take close to 10 years.
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5.1. Evaluation of Co-firing Options
KEMA completed the following evaluations of the co-firing
configurations studied:
Technical ranking of options;
High level financial and risk analysis applied to the above; Fuel availability and suitability analysis; and
Optimum co-firing regimes and impact on heat rates
5.2. Technical Ranking
Table 17 provides a qualitative ranking of technical
feasibility for each of the configurations studied. The
technical maturity and challenges are based on all on-site
activities that have to be performed, and do not consider
the maturity and complexity of all off-site processes (astorrefaction and pelletization), i.e. quality of the delivered
fuel is assumed to be assured.
Table 17: Technical ranking
The main conclusion is that co-firing wood pellets is
technically proven and technically feasible. Firing torrefied
material is expected to be technically feasible; however,
there is currently a lack of experience with this material.
There is some experience with retrofitting a bubbling
fluidized bed into a coal-fired unit, but this option requires
significant modifications and therefore various operational
challenges are expected. Installing a dryer is technically
feasible, but special attention must be paid to the
integration aspects.
Case No
Unit size
(MWe)
Configuration
type Maturity
Operational
challenges
Extent of
modifications
required
Technical
ranking
1 150 10% flax pellets
co-firing
Moderate Several Limited Feasible with some
challenges
2 150 60% torrefied
willow pellets
Low Expected feasible
Limited experience
Limited Feasible in the
long run
3 400 60% wood pellets High Several but known Moderate Feasible
4 400 60% torrefied
wood pellets
Moderate-Low Expected feasible
Limited experience
Limited Feasible in the
long run
5 150 100% wood chip
BFB retrofit
High-Moderate Various challenges Significant Very plant specific with
major challenges
6 150 20% wood chips High-Moderate Some challenges Substantial Feasible with some
challenges
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5.3. Financial and Risk Analysis of Biomass Co-firing Conversion
Table 18 shows qualitative financial and risk rankings for
each configuration. The capital and operational costs are
associated with the avoided CO2emission, and only refer
to the on-site costs. Financial risks refer to risks that
increase capital and operational costs.
Table 18: Financial and risk ranking
Case No
Unit size
MWe) Configuration type CapEx OpEx (fuel) OpEx (non-fuel)
Sensitivity factors /
risks
1 150 10% flax pellets
co-firing
Moderate Moderate Moderate Fuel availability,
corrosion
2 150 60% torrefied willow
pellets
Low High Low Fuel quality, fuel cost/
availability, fans, mills,
heat release, HSE
3 400 60% wood pellets Moderate Moderate Moderate Equipment size/cost,
fuel cost, milling,
combustion
4 400 60% torrefied wood
pellets
Low High Low Fuel quality, fuel cost/
availability, fans, mills,
heat release, HSE
5 150 100% wood chip BFB
retrofit
Moderate-High Low Moderate Boiler type, fans,
storage size (delivery),
fuel price, derate
6 150 20% wood chips High Low High Heat source drying,
storage size (delivery),
fuel price
The financial and technical risk for torrefied wood may
be high since so few plants have been constructed.
The main conclusion is that, due to the expected minor
modifications, the investment in equipment is lowest for
the torrefied pellets. However, it is expected that the price
of good quality torrefied pellets will be high. Untorrefied
wood pellets will come at a lower price, but then more
investment will have to be completed on pre-treatment
facilities. When wet wood chips can be guaranteed
to be purchased for a long-term period, then capital-
intensive investments can still be feasible. Availability
of flax is dependent on local conditions, and it is likely
that arrangements will have to be made with farmers
for harvesting, baling, and intermediate storage. Whether
one of these options is economically feasible depends
on the exact business case.
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5.4. Fuel Availability and Suitability
Table 19 summarizes the factors that influence the
availability of the biomass supply and/or measures to secure
the biomass supply, and shows the suitability of each of the
biomass fuels types within the given configurations.
Table 19: Fuel availability and suitability
Case No
Unit size
(MWe) Configuration
Biomass type
(origin) Availability Suitability
1 150 10% flax pellets co-firing Flax Dependent on agriculture Moderate
2 150 60% torrefied willow pellets Willow To be outsourced to
pellet manufacturer
Moderate-High
3 400 60% wood pellets Wood To be outsourced to
pellet manufacturer
High
4 400 60% torrefied wood pellets Wood To be outsourced to
pellet manufacturer
Moderate-High
5 150 100% wood chip BFB retrofit Wood chips Likely various suppliers High
6 150 20% wood chips Wood chips Likely various suppliers Moderate
The main conclusion is that woody (both torrefied and
untorrefied) types of biomass are generally available or
can be made available. However, there are no commercial
scale torrefaction plants in Canada. Processing these
types of biomass in the form of pellets is performed
by pellet manufacturers. This will come at a cost, but
long-term contracts are likely to enhance security of
supply. Generally, wood pellets are suitable for co-firing.
Flax can also be suitable but has more operational risks,
as well as it needs more organization for harvesting and
processing, depending on the local agricultural situation.
Wood chips are cheaper (as is sawdust), but often have
to be collected from various suppliers and industries in
the direct vicinity of the power plant, presenting potential
logistical and security of supply problems.
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5.5. Optimum Co-firing Regimes and Implications of Co-firing Retrofits on Heat Rates
Table 20 shows the technically feasible biomass to total
fuel co-firing percentage ranges; these are site specific,
but generally:
Low: below 20% co-firing
Medium: 20-50% co-firing
High: above 50% co-firing
Table 20: Likely feasible co-firing ranges and likelihood of a resulting plant derate
A retrofit of a pulverized fuel boiler into a bubbling fluidized
bed is likely to result in a significant derate, which may be
up to 30-60% of its original capacity. In addition, the heat
rate will increase. Utilizing wet wood chips and drying the
wood chips by means of an integrated dryer (using steam
from the plant steam cycle) will result in a derate and heat
rate penalty, depending on the actual amount of water that
needs to be evaporated. Generally, firing biomass results in
an increased house-load for conveying, milling, and
(possibly) fans. Nova Scotia Power did not see any derate
related to firing 20% wood chips given they had excess
fan capacity. It should also be noted the fast growing
species such as willow may cause fouling issues which
may lead to derates or heat rate issues.
Future studies should be focused on specific plants to
determine the optimal fuel, co-firing percentage and co-firing
technology as well as the cost for co-firing at the site.
Case No
Unit size
(MWe) Configuration
Feasible co-firing
percentage Likely effect on heat rate Likely derate
1 150 10% flax pellets co-firing Low Minor Limited
2 150 60% torrefied willow pellets Low-High Minor Limited
3 400 60% wood pellets Low-High Some Limited
4 400 60% torrefied wood pellets Low-High Minor Limited
5 150 100% wood chip BFB retrofit High Substantial Significant
6 150 20% wood chips Low Substantial Substantial
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Part B Co-firing Results from NS Power Study
1. Introduction
Nova Scotia Power has been tasked with meeting a
Renewable Portfolio Standard as part of Nova Scotia
Government policy. In order to meet this requirementNova Scotia Power has initiated studies to determine the
feasibility of co-firing biomass in their pulverized coal units
as well as the circulating fluidized bed unit at Point Aconi.
The Canadian Clean Power Coalition has an interest in
following this work and has provided funding for research
carried out by CanmetENERGY. Two areas of research
were completed. The objective of the first study was to
determine the maximum size of biomass particle that can
be successfully fired and identify how co-firing with
biomass will affect the operational aspects of the boiler
including carbon burnout and slagging and fouling.
The second area of research funded by the CCPC was to
investigate the performance of biomass in a circulating
fluidized bed boiler co-fired with a petroleum coke and
coal fired mixture. Ratios of biomass to coal of 10, 20,
30 and 40% by mass were targeted.
While pulverized firing of coal has been long-established,
experience with the addition of biomass to a suspension
flame is limited, and doing so may present difficulties in
several areas. Problems may arise in material handling,
flame stability, burnout, and increased corrosion or fouling
of heat exchangers due to mineral matter within the
biomass, etc.
Full-scale experimentation on a subject such as this is very
expensive and therefore seldom undertaken. Instead,
laboratory analyses, bench-scale tests, and pilot-scale
experimentation are employed to clarify and quantify as
many parameters and variables as possible, thereby
building up a body of information that gives full-scale
implementation a high probability of immediate success.
CanmetENERGY in Ottawa, a branch of Natural
Resources Canada, has a wide array of facilities and
fifty years of experience in assisting Canadas energyindustry by performing research such as this. Nova
Scotia Power Inc. therefore contracted with Natural
Resources Canada for extensive testing to investigate
the impacts of biomass blends on fuel handling,
combustion, and overall performance.
The purpose of this investigation is to evaluate the suitability
of co-firing biomass with pulverized coal. Two fuels were
therefore considered, which included wood chips sourced
from the local forestry sector, and a low-sulphur Colombian
bituminous coal. The ultimate aim was to determine how
the biomass can be most effectively co-fired with the
baseline coal. Therefore, the study included:
Basic chemical and physical characterization
of the fuels;
Kinetic modeling of the fuels for carbon burnout
within existing boilers; and
An experimental investigation involving co-firing
wood chips with both natural gas and the baseline
coal in the laboratory-scale research furnace (LSRF).
This study was intended to address the performance
of the biomass including:
Determination of the maximum allowable size
of wood chips; The maximum fraction of overall heat input
from biomass attainable in the co-firing mix;
Carbon loss as affected by size, fired fraction,
and excess air;
Slagging and fouling as influenced by the fired
fraction and the amount and composition of ash
within the biomass; and
Flame stability.
2. Natural Gas Test Firing with Biomass
The objectives of co-firing wood chips with natural gas was
to better isolate the carbon burnout from the wood in a
situation where the other fuel would not contribute to the
carbon burnout data or the ash related data. In this manner
the effects of exposing wood particles to specific
temperature and oxygen profiles in the furnace could be
studied to determine an optimal biomass size for co-firing
with the coal in the next phase of the experimental program.
The furnace has four bottom ash sampling points and
three probes at various temperatures and locations in the
system. Results related to the fouling of the probes, the
carbon content in the bottom ash and fly ash samples, the
proportion of CO in flue gas were used to help determine
the size of biomass to be used in the coal co-firing tests.
The data appear to show that the smaller fuel size burns
more completely than the larger sizes, and that increasing
the biomass feed rate decreases burnout. After
presenting the interim results along with data for a smaller
size of wood chips (with a distribution which let 90 %
through 2.5 mm mesh), it became clear that flame stability
was a critical factor in the decision on which size to select
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for co-firing with coal tests. As observed in the carbon
monoxide run-time data, flame stability decreased with
increased particle size, and since the 2.5 mm material was
regarded as too fine, the decision was made to proceed
with the 3.4 mm material. This size was considered to
burn out fairly well within the flame, as minimal unburned
material was collected post-testing.
3. Coal/Biomass Co-firing Tests
Biomass heat inputs of 5, 10 and 15% co-fired with coal
were tested. Coupled with the quantitative data regarding
carbon concentration and ash origin, it is reasonable to
conclude that the larger wood chips (within the 3.4 mm
distribution tested) did not have sufficient time to burn out
within the flame.
Given the composition measurements for the back-end
ash samples, it appears that the vast majority of flyash will
originate from coal, which makes sense given the low ashcontent in the wood chips. However, consideration should
be given to potential challenges in full-scale conditions. If
partially burned biomass travels far downstream and
accumulates, it may be hazardous for the baghouse and
other back-end equipment. This is because biomass char
is quite volatile and reactive, and can ignite at conditions
where coal char is essentially inert.
Some biomass may fall to the bottom of the boiler. As
long as oxygen is available and the temperature within this
region is high, it is believed that overall the wood chips
should be able to smolder in situ at the bottom of the
boiler without a significant negative effect on the overallcombustion efficiency.
4. Coal/Biomass Co-firing Test Conclusions
a. Flame stability decreased with increased biomass input,
as observed with video footage of the burner. This is
expected to affect air staging at both the local level (i.e.,
burner design) and at the global level (i.e., wood chip
injection elevation within the burner zone).
b. The degree of burnout achieved in all tests was
acceptable for a combustor of this scale.
c. Chemical composition analyses found that the vast
majority of material collected in the back-end of the furnace
originated from coal. This means that the wood chips fell or
burned out earlier in the system and did not fully entrain in
the gas stream. Rather, the biomass appeared to settle at
the first restrictions and burn in situ. There appeared to be
no correlation between the wood chip fired fraction and
particulate loading in the baghouse. The risk of ignition
within the back-end increases with fuel volatility, and since
biomass char is more reactive than coal char, effort should
be made to ensure that the wood burns out early within the
full-scale furnace. This may be accomplished by injecting
wood chips at a lower level within the burner region.
Locating the suitable level must also consider the portion of
material falling downwards to the base of the furnace, andmay require further modeling effort.
d. The largest particles within the wood chip size
distribution were observed to land at the base of the
furnace within the combustor, and burn in situ within
approximately 2.5 seconds. Slightly smaller particles burned
in approximately 1 second. These observations were for a
high-temperature oxidizing environment in a full-scale
boiler conditions may not support this burning rate for
wood chips which fall to surfaces below the lowest burner
level, which are typically reducing atmospheres. Further
investigation of the ignition (gasification) behaviour of wood
chips under these conditions can be tested in order tominimize the risk of explosion should a pulse of high-
oxygen air enter this region.
e. Slagging of the LSRF interior walls was apparent for
coal-only and coal-wood chip tests, however, severe
slagging on the surfaces of cooled probes was not
observed. Co-firing with wood did not appear to enhance
or suppress slagging, likely due to the low ash content
within the wood.
f. The fouling deposition rate was seen to drop at the two
in-combustor probe locations with increased biomass
input. At full-scale, added biomass is not expected toincrease fouling in the superheater region.
g. Emissions of SO2decreased in proportion to the feed
rate of biomass, due to a much lower sulphur content
within the wood. The nitrogen content of each fuel was
similar; therefore nitrogen oxides were mostly thermal in
origin and could be reduced through excess air control.
Emissions of NOXmay present a challenge should the
biomass supply change to one rich in nitrogen.
5. CFBC Testing
Further tests were completed on a CFBC. A blend of coke/
coal with biomass providing 0, 10, 20, 30 and 40% by
mass were tested. Biomass has been successfully co-fired
in CanmetENERGYs pilot-scale CFBC at levels up to 40%.
The combustion was stable as long as a steady feed rate
could be maintained. NOXemissions decreased as the
amount of biomass increased in the fuel feed. The addition
of biomass had no effect on particulate matter emissions,
and no effect on the properties of the fly ash either.
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Part C Co-firing Conclusions
1. Conditions for Employing Co-firing
There are many factors which need to be considered
when making the decision of whether or not to adopt
biomass co-firing at a coal plant. What follows is adescription of those things which would be preferred or
helpful and this conditions which must be met before a
project is likely to be approved.
1.1 Preferences of Power Producers
The following describes the characteristics of biomass
co-firing systems which are generally preferred by owners
and operators of coal plants. However, individual companies
and plant operators may have other preferences and many
not value some of those listed here particularly highly.
Government subsidies to offset technology risk
and support technology development. Many of the
technologies are not well established and require
several more pilot and demonstration plants before
they will be considered commercial. Subsidies would
help speed up this process.
Prefer technologies which require less time to
implement. Some technologies required very long
development, design, regulatory and construction
timelines. They may not be implemented in time to
meet GHG reduction requirements.
May prefer low capital cost plant modifications. As
plants age there is less time available to amortize
capital additions. Therefore, projects with lower
capital costs may be considered more favourably
for older plants.
Proven biomass technologies reduce risks. Utilities
are risk adverse and prefer technologies which have
been proven already at the commercial scale.
Proven handling and firing technologies reduce
risks. Technologies which have been used to handle
material or fire material in other settings wouldgenerally be perceived as having less risk.
Few plant modifications are preferred. Coal plants are
sophisticated and the fewer modifications made to
them the better.
Biomass fuel standards. Standards for biomass fuelswould help make biomass a commodity that could be
traded. It would also reduce the uncertainty regarding
fuel quality.
Co-firing which reduces other emissions such as
sulphur. The utilization of some biomass fuels will
have the effect of reducing other plant emissions
which is considered beneficial.
Flexibility to use low cost opportunistic fuels. If the
system is designed to allow for the use of multiple
fuels and has spare capacity, it may be able to take
advantage of seasonal fuels or fuels with inconsistentsupply which may be available at low cost.
Co-feeding of biomass with coal. Systems which rely
on the use of the existing coal grinding and feeding
infrastructure rather than separate grinding and
feeding systems for the biomass are preferred to
reduce capital costs.
1.2 Conditions Which Must be Met Before
Co-firing Will be Adopted
What follows is a list of those conditions which may needto be met before co-firing is adopted by a power producer.
Individual power producers may have other conditions and
may not consider some of these items to be conditions at
all. However, it is generally expected that most of these
conditions will need to be met before co-firing is adopted.
Regulatory framework mandating GHG reductions.
Since most co-firing strategies are uneconomic, some
form of regulatory mandate may be required to
encourage co-firing.
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Regulatory approval to co-fire. Some jurisdictions have
forbidden coal fired plants from burning biomass. In
others, the regulator has not been very encouraging
and environmental groups have forcefully opposed
co-firing proposals scuttling projects.
GHG protocol. Biomass is not necessarily treated at acarbon neutral fuel everywhere. If biomass is treated
as a carbon neutral fuel protocols need to be in place
to allow project developers to determine how to
quantify the amounts of CO2avoided.
High and predictable GHG credit prices. If a market
does not exist for GHG reductions biomass co-firing
may be adopted to meet physical requirements to
reduce emissions. However, if one can meet their
GHG reduction requirement by purchasing credits or
offsets or by paying a carbon tax, then the price of
these alternatives needs to be higher than the avoided
cost of CO2from the co-firing options before onewould adopt co-firing. The market price may need to
be significantly higher than a physical solution given
the potential technology and operating risks inherent
in biomass co-firing. Before upfront capital is spent,
project developers will want to be satisfied that the
market price for the CO2reductions they create will
generate a fairly predictable return on investment.
The cost of biomass co-firing will be compared to the
value of CO2mitigation costs avoided or the value of
CO2credits sold. The cost of biomass co-firing is
roughly the capital recovery charge, incremental
O&M, cost of biomass fuel less the cost of thedisplaced coal. Western Canadian coals have a cost
of about $1.00 to 2.00/Gj. The cost of biomass fuels
alone is expected to be significantly greater than this.
Cost of GHG reductions from co-firing should be lower
than other physical options. Biomass co-firing would
be attractive if the cost and risk of doing so is
perceived to less costly than for other physical options.
Co-firing yields material decreases in GHG. Some
co-firing schemes may not supply sufficient GHG
reductions to warrant consideration. Co-firing
schemes may be unattractive because large
quantities of low cost fuel may not be available.
Minimal impact on heat rate, output, corrosion,
availability, O&M, downtime to install, etc. Many
biomass fuel and co-firing schemes may adversely
impact the operation of a power plant. These impacts
may increase costs or reduce the ability of the plant
to sell power. These impacts will normally be included
in the estimate of the cost of the co-firing scheme.Therefore, these costs must be considered reasonable.
Long term secure and consistent supply of low cost
high quality (dry) fuel must be available. In order to
justify capital expenditures, the supply of fuel may
need to be contracted for a significant period of time.
Currently the absence of robust biomass commodity
trading makes it difficult to hedge supply risk. For
many co-firing schemes fuel cost will be the greatest
cost incurred. Therefore, increases in fuel costs or
deterioration in either fuel quality or supply may
adversely impact the economics of a co-firing project.
Plant space availability. Many co-firing scheme
required significant space to receive, process, dry,
grind, store and move fuel around. Many coal plants
may not have sufficient space for these processes
and may not have space to interconnect the biomass
feeding systems into existing facilities.
Fuel characteristics and their impact on plant
operations must be well understood. Tests may need
to be conducted to determine the following:
Proximate, ultimate, elemental and trace analysis, ash
fusion temperature, TGAs, bulk density, dust issues,
particle size distributions and maximum allowablesize, odour issues, biomass degradation issues,
corrosion and fouling considerations, flame stability,
burnout, other operational impacts, etc. Biomass
co-firing can cause significant operational issues in a
coal plant. Therefore, one should have a very good
understanding of the impact of specific biomass fuels
at their expected flow rates on the performance of
the coal plant. Fuels with certain characteristics at
certain flow rates may not be suitable for used in
some coal plants. Understanding the likely impact of
the fuel on plant operations can help determine the
kinds of mitigation strategies to consider.
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2. Conclusions
Figure 3 suggests that for all the cases where flax pellets,
torrefied wood, wood pellets or wood chips are used to
replace sub-bituminous or lignite coals in existing boilers,
the avoided CO2cost ranges from about $70 to $100/
tonne. These values are even lower when torrefiedmaterial is used to replace bituminous coal. These avoided
CO2costs are competitive with expected carbon capture
technologies and may have lower technical risks.
Figure 8 shows that for plants with short economic lives
biomass co-firing may be a very attractive option to
comply with GHG emission reduction requirements
compared to other capital intensive carbon capture
options. Amortizing capital related to carbon capture over
a short number of years will significantly increase the cost
to reduce GHG emissions.
Figure 6 showed that power costs will increase withco-firing. Many carbon capture technologies are capital
intensive and may not impact marginal costs significantly.
Biomass co-firing will increase marginal costs. For cases 3
and 4 they may increase marginal cost by $40 to 60/MWh.
This cost increase may impact the dispatch order of the
plant reducing its capacity factor. However, unlike many
carbon capture options, the co-firing options studied are
not expected to materially decrease the output of a plant.
Table 16 suggests that for older plants with short
economics lives it may be more economical to use large
amounts of wood pellets or torrefied material to meet
GHG requirements than to implement carbon capture.
This table also suggests that for these older plants they
may have competitive average prices for power when
fired on large amounts wood pellets or torrefied material.
More work is required to show that torrefied materials can
be produced at high volumes with consistent quality and
be fired high percentages at coal plants.
Cases 1 and 6 rely on lower proportions of biomass firing.
Figure 6 suggests that increasing the proportion of these
materials to 60%, for these two cases, the amount of
co-firing required to meet NGCC GHG intensities, will
yield increases in power costs similar to the 60% cases.
However, it may not be possible to fire wood chips at
more than 20%. The Nova Scotia Power study showedthat large biomass chips with a distribution of within
3.4 mm wood chips co-fired well with coal up to 15%
co-firing. Co-firing of up to 40% in a CFBC was successful
as well. However, conversion of a coal plant to a bubbling
fluidized bed, as shown in case 5, does not look like an
attractive option.
The biomass studied is expected to have an ultimate
sulphur concentration of between .04 and .2 % by weight.
This is lower the sulphur content of most of the coals
studies. Co-firing could have the effect of also significantly
reducing sulph