appendix biomass co-firing c · figure 1: typical biomass co-firing routes ... increase in power...

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 C C01

Table of Contents

1. Introduction ___________________________ C02Part A – Co-firing Results from Kema Study _____ C021. Introduction ___________________________ C022. Generic Biomass Co-firing Configurations ___ C023. Biomass Feedstocks ___________________ C033.1. Raw Biomass __________________________ C033.1.1. Wood Chips ___________________________ C043.1.2. Willow ________________________________ C043.1.3. Flax Straw ____________________________ C053.2. Modified Biomass ______________________ C053.2.1. Pelletized Biomass _____________________ C053.2.2. Torrefaction ___________________________ C084. Six Co-firing Configurations Studied ______ C105. Conclusions From KEMA Report _________ C215.1. Evaluation of Co-firing Options ___________ C225.2. Technical Ranking ______________________ C225.3. Financial and Risk Analysis of Biomass

Co-Firing Conversion ___________________ C235.4. Fuel Availability and Suitability ___________ C245.5. Optimum Co-firing Regimes and

Implications of Co-firing Retrofits on Heat Rates _________________________ C25

Part B – Co-firing Results from NS Power Study ___ C261. Introduction ___________________________ C262. Natural Gas Test Firing with Biomass _____ C263. Coal/Biomass Co-firing Tests ____________ C274. Coal/Biomass Co-firing Test Conclusions ___ C275. CFBC Testing __________________________ C27Part C – Co-firing Conclusions _________________ C281. Conditions for Employing Co-firing _______ C281.1. Preferences of Power Producers _________ C281.2. Conditions Which Must be Met Before

Co-firing Will be Adopted ________________ C282. 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 CO2 Emissions for Biomass _____________________ C12

Table 13: Rough Ranges of Biomass Feedstock Costs ______________ C12

Table 14: Cost of Operating a Co-firing Plant in Millions of Dollars per Year _________________________________________ C13

Table 15: Avoided Costs of CO2 Reductions/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 CO2 Cost Components _________________________ C18

Figure 8: Impact of Amortization Period on Avoided CO2 Cost _______ C19

Table 16: Comparison of Costs to Comply with GHG Requirements _____ C19

Figure 9: Avoided CO2 Cost of Natural Gas in a Coal Plant ___________ C20

Figure 10: Avoided CO2 Cost 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 contained in 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.

Coal Mills Burners Boiler

Pre-treatment

SteamTurbine

Biomass Mills

Flue GasTreatment

Gasifier Stack

1 2 3

4

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 CC02

Introduction

The CCPC considers biomass co-firing as potential way to reduce the CO2 emissions from coal plants since biomass is generally considered a carbon neutral fuel. During the course of the CCPC’s phase III work, it commissioned two studies related to biomass co-firing. The first was prepared by 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 the work 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-fired boiler, 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, depending on 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 in furnace boiler.

Figure 1: Typical Biomass Co-firing Routes


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 (<10%, but from KEMA experience generally at a maximum of 3-5 wt-%). In these applications, the biomass blends will be predominantly coal and the biomass is combusted in the boiler with little operational impact.

For larger percentages of co-firing with biomass, typical applications will require the addition of separate feed streams of the biomass along with the addition of dedicated biomass burners. These boiler modifications are needed because of the differing characteristics and heating values of the fuel (biomass ~ 9,000 Btu/pound versus coal ~ 7,000 to 12,000 Btu/pound) and the varying feedstock quality that can often be found in biomass fuel supply.

A fourth route to co-firing biomass is to gasify biomass, usually in a fluidized-bed gasifier, and then combust the synthetic gas in the furnace with dedicated gas burners. This approach is increasingly gaining market acceptance,

particularly with the successful commercial operation of fluidized bed gasifiers, and is a driving technology behind the retrofit of older biomass stoker plants.

3. Biomass Feedstocks

Biomass feedstocks can be categorized as belonging to one of two classes: raw biomass or modified biomass. Raw biomass is harvested, transported, and used directly for co-firing applications. Modified biomass is harvested and then processed before delivery to the plant in order to improve the quality, costs, and/or logistics associated with fuel transport, handling, and processing at the power plant site.

3.1. Raw Biomass

Various biomass types with different origin, composition, physical properties, and price are available in the market. When contemplating a biomass co-firing scenario, it is appropriate to consider designing the on-site plant modifications to accommodate a variety of feedstocks.

Table 1: Major solid biomass materials of industrial interest on a worldwide basis 1

Agricultural products Forestry products Domestic and municipal wastes Energy crops

Harvesting Residues Harvesting residues Domestic/industrial Wood

Cereal strawsOil seed rape and linseed oil strawsFlax strawCorn stalks

Forestry residues Municipal solid waste (MSW)Refuse-derived fuelsConstruction and demolition

wood wastesScrap tiresWaste pallets

WillowPoplarCottonwood

Processing residues Primary processing wastes Urban green wastes Grasses and other crops

Rice husksSugarcane bagasseOlive residuesPalm oil residuesCitrus fruit residues

SawdustsBarkOffcuts

LeavesGrass and hedge cuttings

SwitchgrassReed canary grassMiscanthus

Animal wastes Secondary processing wastes

Poultry litterTallowMeat/bone meal

SawdustsOffcuts

1 IEA Bioenergy Task 32, Deliverable 4, Technical status of biomass co-firing, 50831165-Consulting 09-1654, 2009.

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.


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. 3 Flax is considered as a favorable addition to many farmers’ crop rotations. A constraint to flax production however is dealing with the flax straw 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 higher than 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. Several of 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

Greenhammer mill Dryer

Dryhammer mill

Pelletpress

Pelletcooler

Pellerstorage

Feedstock Off-sitePre-processing

Pelletizingfacility Port Product

3 www.saskflax.com


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)


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.


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. The table 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 demonstration phase. Which technology performs best depends on the functional requirements, fuel specifications, heat source, and development status.


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 by uncertainties. 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


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 MWe sub-bituminous-fired boiler, with an assumed heat rate of 10,000 Btu/kWh

Unfortunately in the KEMA study the CO2 intensity 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 displaced refers 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 InputCapacity 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


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, including engineering, 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 CO2 emission 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 CO2 intensity 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 CO2 associated 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. Biomass co-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 CO2 avoided. The net CO2 avoided is used to calculate the revised CO2 intensity.

In this report CO2 Avoided is calculated based on the values in Table 12. CO2 Avoided is equal to CO2 Before Conv – CO2 Before Conv x % Co-fired – CO2 from Offsite – CO2 from replaced power. The Revised CO2 Intensity is equal to (CO2 Before Conv – CO2 Avoided) / MWh produced in year.


Cases 2, 3 and 4 were chosen to meet a CO2 intensity 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 CO2 intensity is reduced by about 20% assuming biomass is a carbon neutral fuel.

Table 12: Avoided CO2 Emissions for Biomass

Biomass Fuel case #

Base CO2 Intensity (t/MWh)

CO2 Before Conv (kt/yr)

CO2 from Offsite Process

(kt/yr)

CO2 from 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


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 CO2 for 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 CO2 emissions 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 CO2 Reductions / 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.


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

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0 50 100 150 200 250

Avo

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CO

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($/

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 CO2 cost 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 CO2 emissions 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.


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.

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Po

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1 – 10% FP

2 – 60% TW

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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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Incr

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ow

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$/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.


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

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($/

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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 CO2 emissions 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 CO2 emissions because most carbon capture costs are fixed.


The following figure shows the costs which make up the avoided CO2 costs for each of the cases.

Figure 7: Avoided CO2 Cost Components

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140

1 – 10% FP

2 – 60% TW

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WC

6 – 20% WC

Avo

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($/

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 CO2 emissions. 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.


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 CO2 capture project constitutes 50% of $100/t. Given that co-firing projects are expected to have 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 CO2 costs 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 coal plants with short economic lives than other more capital intensive options like post combustion capture.

Figure 8: Impact of Amortization Period on Avoided CO2 Cost

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0 5 10 15 20 25 30

Avo

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t)

Project Term (years)

Post Combustion

Co-firing

If the Canadian Government requires old coal plants to adopt an NGCC CO2 intensity, 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 plant’s

capital is written off, there may be $20/MWh of O&M remaining. 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

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$120/MWh

$110/MWh

$100/MWh

Price of

Wind Power

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4.0 5.0 6.0 7.0 8.0 9.0 10.0

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$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 CO2 costs 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 CO2 Cost 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 an attractive 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 CO2 cost 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 figure would cause the avoided costs of wind to increase by more than threefold.

Figure 10: Avoided CO2 Cost for Wind at Three Power Prices


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 that might 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 well established. 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 of time, 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. Torrefied pellets 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.


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 (as torrefaction 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 NoUnit size (MWe)

Configuration type Maturity

Operational challenges

Extent of modifications

requiredTechnical 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


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 CO2 emission, 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 NoUnit 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.


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 NoUnit 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.


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 NoUnit 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


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 requirement Nova 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 Canada’s energy industry 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


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 ash content 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 overall combustion 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, and may 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 to minimize 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 to increase fouling in the superheater region.

g. Emissions of SO2 decreased 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 NOX may 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 CanmetENERGY’s pilot-scale CFBC at levels up to 40%. The combustion was stable as long as a steady feed rate could be maintained. NOX emissions 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.


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 a description 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 would generally 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 fuels would 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 inconsistent supply 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 need to 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.


• 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 a carbon 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 CO2 avoided.

• 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 CO2 from the co-firing options before one would 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 CO2 reductions they create will generate a fairly predictable return on investment.

The cost of biomass co-firing will be compared to the value of CO2 mitigation costs avoided or the value of CO2 credits sold. The cost of biomass co-firing is roughly the capital recovery charge, incremental O&M, cost of biomass fuel less the cost of the displaced 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, TGA’s, bulk density, dust issues, particle size distributions and maximum allowable size, 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.


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 CO2 cost ranges from about $70 to $100/tonne. These values are even lower when torrefied material is used to replace bituminous coal. These avoided CO2 costs 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 with co-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 showed that 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 sulphur emissions from coal plants. Therefore, co-firing should be compared to not only the cost of reducing GHG emissions but to the costs of reducing sulfure emissions as well.

Biomass co-firing may have lower avoided CO2 costs than current carbon capture technologies. If there are logistical or operational limits on the amount of co-firing possible at a plant it could be employed along with carbon capture to meet GHG reductions requirements.

Figures 5 and 6 suggest that given capital and O&M costs account for such a small proportion of the costs, that errors in these estimates will only have a minor impact on avoided CO2 costs. Since the cost of biomass fuel accounts for most of the cost of co-firing, more work is required to establish the cost and ability to supply a consistent quality biomass to specific plants before a decision is made to implement co-firing.


appendix biomass co-firing c · figure 1: typical biomass co-firing routes ... increase in power...

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