biomass co-firing - canadian clean power coalition

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


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.



8/30

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


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


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



13/30

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.



14/30

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.



15/30

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



16/30

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.



17/30

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.



18/30

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.



19/30

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



20/30

-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



21/30

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.



22/30

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



23/30

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.



24/30

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.



25/30

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



26/30

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

biomass co-firing - canadian clean power coalition

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