Lessons Learned

from Existing Biomass Power Plants
February 2000 ï NREL/SR-570-26946

Lessons Learned from Existing

Biomass Power Plants

G. Wiltsee

Appel Consultants, Inc.

Valencia, California

NREL Technical Monitor: Richard Bain

Prepared under Subcontract No. AXE-8-18008

National Renewable Energy Laboratory

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CONTENTS

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Section Page

Executive Summary ............................................................................................................1

Bay Front Station, Ashland, Wisconsin ............................................................................10

Kettle Falls Station, Kettle Falls, Washington ...................................................................16

McNeil Generating Station, Burlington, Vermont .............................................................23

Wheelabrator Shasta Plant, Anderson, California ..............................................................32

San Joaquin Valley Energy Partners, Chowchilla, El Nido, and Madera, California ........44

Boralex Stratton Energy, Stratton, Maine ..........................................................................56

Tracy Biomass Plant, Tracy, California .............................................................................61

Tacoma Steam Plant No. 2, Tacoma, Washington ............................................................66

Colmac Energy, Mecca, California ....................................................................................79

Grayling Generating Station, Grayling, Michigan .............................................................88

Williams Lake Generating Station, British Columbia, Canada ..........................................94

Multitrade Project, Hurt, Virginia ....................................................................................102

Ridge Generating Station, Auburndale, Florida ...............................................................107

Greenidge Station, Dresden, New York ..........................................................................113

Camas Cogeneration Plant, Camas, Washington ............................................................119

Snohomish County PUD/Kimberly-Clark Corp., Everett, Washington .........................125

Okeelanta Cogeneration Plant, South Bay, Florida ..........................................................130

Lahti Gasification Cofiring Project, Lahti, Finland ..........................................................137
1

EXECUTIVE SUMMARY

________________________________________________________________________

This report includes summary information on 20 biomass power plants—18 in the United

States, one in Canada, and one in Finland, which represent some of the leaders in the

industry. Table 1 lists the 20 plants in order of on-line date, the same order in which they

are presented in the report. In some cases, the on-line date means the date an older fossilfired plant started using biomass fuel commercially (not its original on-line date). Some of

the information in the table is abbreviated, but can be clarified by referring to the specific

plant sections.

Table 1

Summary of Biomass Power Plants in this Report

The on-line dates of the plants span about 18 years, from December 1979 to January 1998.

The types of biomass fuels used are abbreviated: “mill” refers to mill wastes, etc. Many

boiler types are represented: six traveling grate stoker boilers, four water-cooled vibrating

grate boilers, four bubbling fluidized bed combustors (FBCs), one circulating fluidized bed

(CFB) boiler, one fixed-grate boiler, one sloping grate boiler, and two pulverized coal (PC)

boilers retrofitted to cofire solid or gasified biomass. Steam temperatures for the biomassPlant Online Fuels Boiler(s) lb/hr Psig fiF MWe

Bay Front Dec-79 Mill, TDF, coal 2 modified coal stokers 280,000 30

Kettle Falls Dec-83 Mill 1 traveling grate stoker 415,000 1500 950 46

McNeil Jun-84 Forest, mill, urban 1 traveling grate stoker 480,000 1275 950 50

Shasta Dec-87 Mill, forest, ag, 3 traveling grate stokers 510,000 900 905 49.9

El Nido (closed) Oct-88 Ag, forest, mill, 1 bubbling FBC 130,000 650 750 10

Madera (closed) Jul-89 Ag, forest, mill, 1 bubbling FBC 260,000 850 850 25

Stratton Nov-89 Mill, forest 1 traveling grate stoker 400,000 1485 955 45

Chowchilla II (closed) Feb-90 Ag, forest, mill, 1 bubbling FBC 130,000 650 750 10

Tracy Dec-90 Ag, urban 1 water-cooled vib grate 18.5

Tacoma (cofiring) Aug-91 Wood, RDF, coal 2 bubbling FBCs 400 750 12

Colmac Feb-92 Urban, ag, coke 2 CFB boilers 464,000 1255 925 49

Grayling Aug-92 Mill, forest 1 traveling grate stoker 330,000 1280 950 36.17

Williams Lake Apr-93 Mill 1 water-cooled vib grate 561,750 1575 950 60

Multitrade Jun-94 Mill 3 fixed grate stokers 726,000 1500 950 79.5

Ridge Aug-94 Urban, tires, LFG 1 traveling grate stoker 345,000 1500 980 40

Greenidge (cofiring) Oct-94 Manufacturing 1 tangentially-fired PC 665,000 1465 1005 10.8*

Camas (cogen) Dec-95 Mill 1 water-cooled vib grate 220,000 600 750 38-48

Snohomish (cogen) Aug-96 Mill, urban 1 sloping grate 435,000 825 850 43

Okeelanta (cogen) Jan-97 Bagasse, urban, 3 water-cooled vib grate 1,320,000 1525 955 74

Lahti (cofiring, cogen) Jan-98 Urban, RDF 1 CFB gasifier + PC 992,000 2500 1004 25**

*108 total net MW, 10% from wood and 90% from coal.

**167 total net MW, 15% from biofuels and 85% from coal.
2

fired boilers are 750°-980°F; for the PC boilers, 1004°-1005°F. The nominal sizes of the

plants range from 10 MW to 79.5 MW.

Electricity Generation and Fuel Consumption

Table 2 lists the plants in order of electricity generation, in gigawatt-hours/yr (GWh/yr).

For some plants, the generation numbers are actual statistics from a recent year (1996,

1997, or 1998). For plants that did not provide these statistics, the generation rates were

estimated based on available information. The same is true for the annual CFs (CF, %) and

net plant heat rates (Btu/kWh). The biomass fuel consumptions were calculated by

multiplying GWh/yr times Btu/kWh, and dividing by 8.5 million Btu/t (4250 Btu/lb, or

8500 Btu/dry lb with 50% moisture content).

Table 2

Plant Electricity Generation and Biomass Fuel Consumption Estimates

Plant Location MWe GWh/yr CF, % Btu/kWh Tons/yr*

Williams Lake British Columbia 60.0 558 106 11,700 768,000

Okeelanta (cogen) Florida 74.0 454 70 13,000 694,000

Shasta California 49.9 418 96 17,200 846,000

Colmac California 49.0 393 90 12,400 573,000

Stratton Maine 45.0 353 90 13,500 561,000

Kettle Falls Washington 46.0 327 82 14,100 542,000

Snohomish (cogen) Washington 39.0 205 60 17,000 410,000

Ridge Florida 40.0 200 57 16,000 376,000

Grayling Michigan 36.0 200 63 13,600 320,000

Bay Front Wisconsin 30.0 164 62 13,000 251,000

McNeil Vermont 50.0 155 35 14,000 255,000

Lahti (cogen) Finland 25.0 153 70 14,000 252,000

Multitrade Virginia 79.5 133 19 14,000 219,000

Madera California 25.0 131 60 20,000 308,000

Tracy California 18.5 130 80 14,000 214,000

Camas (cogen) Washington 17.0 97 65 17,000 194,000

Tacoma Washington 40.0 94 27 20,000 221,000

Greenidge New York 10.8 76 80 11,000 98,000

Chowchilla II California 10.0 53 60 20,000 125,000

El Nido California 10.0 53 60 20,000 125,000

*Tons/year are calculated, assuming 4250 Btu/lb.
3

Capacity Factors

Annual CFs range from 19% to 106%. Some plants with low CFs (e.g., Multitrade and

McNeil) are peaking units. The plants with very high CFs have special circumstances.

Shasta and Colmac were still under the first 10 years of California Standard Offer contracts

when the data were obtained. Williams Lake can operate as high as 15% over its rated

capacity, and can frequently sell extra power.

Heat Rates

The Williams Lake plant also holds the distinction of having the largest single boiler

(60 MW) and the lowest heat rate (11,700 Btu/kWh) of any 100% biomass-fired power

plant. Biomass-cofired coal plants can achieve slightly lower heat rates, as exemplified by

Greenidge Station (11,000 Btu/kWh on the biomass portion of the fuel, compared to 9818

on coal alone). The least efficient plants in this report have heat rates of about 20,000

Btu/kWh. A “typical” value is about 14,000 Btu/kWh (24.4% thermal efficiency, HHV).

Cogeneration

The four cogeneration plants in the report—Okeelanta, Snohomish, Lahti, and Camas—are

recent plants, using the latest technology, in traditional niches for biomass power: two at

pulp and paper mills (Snohomish and Camas), one at a sugar mill (Okeelanta), and one at a

municipal district heating plant (Lahti). The estimates given in Table 2 for these plants

represent only the solid fuel biomass portion of the energy input. At the two pulp and paper

mills, recovery boilers produce large fractions of the total steam from waste liquor; the

wood waste boilers at these facilities constitute focus of this report. At Lahti, coal and

natural gas produce most of the energy; wood wastes and refuse derived fuel (RDF) are

fed to a gasifier that supplies low-Btu gas to the boiler. The Okeelanta cogeneration plant

burns bagasse for about 6 months of the year, and burns urban and other wood wastes at

other times.

Fuels

The cost of biomass fuel from mill wastes and urban wood wastes can range from about

$0/MBtu to about $1.40/MBtu, depending on the distance from the fuel source to the

power plant. Getting to zero fuel cost depends on locating a power plant in an urban area

next to a wood waste processor, or next to a large sawmill or group of sawmills.

Deregulation will make this zero fuel cost strategy more important in the future.

Agricultural residues (primarily orchard tree removals) can be processed into fuel and

delivered to nearby biomass power plants for about $1/MBtu. Only if open burning of

residues is prohibited will transferring some of this cost to the orchard owners be possible.

Forest residues are much more costly ($2.40-$3.50/MBtu), because of the high costs of

gathering the material in remote and difficult terrain, processing it to fuel, and transporting

it to power plants. There are strong arguments for government programs to bear the costs

of forest management and (in the West) fire prevention. Only if such programs are created

will forest residues be as cost-competitive fuel as in the future.

Plants that have come close to zero fuel cost are Williams Lake, which is located very close

to five large sawmills, and Ridge, which accepts raw urban wood wastes and whole tires,

and burns landfill gas. Other plants burning primarily mill wastes include Shasta, Kettle

Falls, Stratton, Snohomish, Grayling, Bay Front, Multitrade, and Camas. Other plants
4

burning primarily urban wood wastes (and in some cases RDF) are Okeelanta, Colmac,

Lahti, and Tacoma. Sawdust from furniture manufacturing is the main biomass fuel at the

Greenidge plant. Plants burning agricultural residues include Okeelanta, Tracy, Madera,

Chowchilla II, and El Nido. Plants burning significant amounts of forest residues include

McNeil, Shasta, Stratton, and Grayling.

Lessons Learned

The project experiences described in the following sections capture some important lessons

learned that lead in the direction of an improved biomass power industry. Undoubtedly,

many other problems and solutions did not surface in the interviews and in the documents

and articles that served as source materials. A summary of the lessons learned from these

20 biomass plants follows; in each category an effort is made to identify plants that

illustrate particular points, so the reader can go to those sections to learn more.

Fuel

The highest priority at most biomass power plants is to obtain the lowest-cost fuels

possible. This involves tradeoffs in fuel quality, affects the design and operation of the

system, and frequently is limited by permit requirements. Some fuel-related lessons

illustrated in this report are:

• At Bay Front, the conversion from coal and oil to biomass and other waste fuels

kept an old generating station operating and provided continued employment.

• At the McNeil Station, long-term fuel contracts insisted on by financing institutions

created some costly problems. As required, McNeil had 15 or 20 long- term fuel

contracts when it started up. The CF dropped because of dispatch requirements,

resulting in lawsuits and settlements with fuel suppliers and odors from the wood

piles. The plant now runs more economically by buying wood fuel under shortterm contracts.

• Maintaining adequate fuel supply in the midst of a declining regional timber

industry has been the single biggest challenge for the Shasta plant. Almost from

startup, Shasta has tried to diversify its fuel sources. From an initial list of

permitted fuels that included only mill waste, logging/thinning residue, and cull

logs, Shasta added agricultural residues, fiber farm residues, land and road clearing

wood wastes, tree trimmings and yard wastes, and natural gas.

• The San Joaquin Valley Energy Partners plants (Chowchilla II, El Nido, and

Madera) experimented in combusting low-cost, low-demand agricultural waste

materials such as grape pomace, green waste, onion and garlic skins, and bedding

materials not desired by competing facilities. However, the most difficult-to-burn

agricultural residues were assigned to the “tertiary” fuel category and mixed in

small percentages with better fuels, primarily wood.

• Experience at the Tracy plant shows that urban wood waste can be a comparatively

inexpensive fuel (~$0.35/MBtu) if the plant is located close to the urban area.

Compared to urban wood waste, orchard wood is relatively expensive

(~$1.00/MBtu) because growers are used to simply pushing and burning it, and are

generally not willing to pay a fee to have the wood removed.

• Tacoma found that focusing on fuel cost (¢/kWh) rather than fuels that provide

highest efficiency (Btu/kWh) saved the plant $600,000/yr. Opportunity fuels (with

tipping fees) can eliminate fuel costs and generate net revenues. Fuel procurement

should be one of the highest priorities and a full-time job.
5

• At the Williams Lake plant, with uncertainty in the forestry industry, unknown

impacts of Asian market upheaval, high provincial stumpage fees, and closure of

some coastal sawmills and pulp mills, the biggest threat to an enviable operating

record appears to be fuel availability.

• The Ridge Generating Station is an urban waste recycling facility, working within

the local waste management infrastructure to provide a low-cost recycling service to

waste generators, and to obtain a free or negative-cost fuel mix (urban wood

wastes, scrap tires, and landfill gas) for energy production.

• The Snohomish Cogeneration plant design anticipated the trend toward declining

quantities of sawmill residues, and the increasing use of urban wood wastes in the

region. Siting the plant at a paper mill provided an excellent fit for steam use, as

well as expertise in wood waste handling and combustion.

Fuel Yard and Fuel Feed System

The area of a biomass power plant that can almost be counted on to be mentioned in

response to the question “Have you had any significant problems or lessons learned?” is

the fuel yard and fuel feed system. Most plants in this report spent significant time and

money during the first year or two of operation, solving problems such as fuel pile odors

and heating, excessive equipment wear, fuel hangups and bottlenecks in the feed system,

tramp metal separation problems, wide fluctuations in fuel moisture to the boiler, etc., or

making changes in the fuel yard to respond to market opportunities. Examples noted in this

report include:

• At Bay Front Northern States Power (NSP) engineers installed and improved (over

time) a system that allows feeding of 100% biomass, 100% coal, or any

combination of the two. Because wood fuel quality varies more than coal quality,

proper tuning of the automatic combustion controls is more important when firing

wood. Operators must pay close attention and periodically adjust feeders.

• With the addition of a debarker, high-speed V-drum chipper, chip screen, and

overhead bins, the Shasta plant was able to offer to custom chip logs, keeping the

35% of the log not suitable for chips. In times of low chip prices, Shasta still

purchases the whole log. Shasta successfully marketed the program to some of the

largest landowners in California.

• At Shasta, the operators learned to blend all the fuels into a homogeneous mixture

that allowed the boilers to fire at a consistent rate and maintain maximum load

under all conditions, without violating environmental standards, excessively

corroding heat transfer surfaces, or slagging beyond the point where the boilers

required cleaning more than twice per year.

• At Stratton, the original owners spent about $1.8 million during the first year of

operation to improve the operation of the fuel yard.

• Tacoma personnel stress the need to take extra care at the beginning of the project

with design of the fuel feed system. Selecting a proven fuel feed system is

important.

• The only area of the Williams Lake plant that was modified after startup was the

fuel handling system. Minor modifications were made to improve performance,

such as adding the ability to reverse the dragchains on the dumper hoppers, to make

it easier to unplug fuel jams; and adding three more rolls to each disk screen (12

rolls were provided originally), to reduce the carryover of fine particles that tended

to plug up the hog.
6

• The Multitrade plant’s minor problems included fuel feeding problems in the early

days of operation (quickly corrected); erosion and corrosion in the fuel splitter

boxes and conveyor belt shrouds (corrected by relining with plastic); and occasional

heating and odor problems in the fuel pile until they learned not to let any part of the

pile age more than 1 year.

• The Greenidge Station found that the technology for preparing biomass fuel for

cofiring in a PC boiler needs further economic evaluation, research, and

development. Grinders do not normally produce a product that has good flow

characteristics. The wood fibers are sticky, stringy, and elongated when produced

from a grinding operation. The fuel product needs to processed by equipment that

produces a chip.

Design for Fuel Flexibility

Many biomass plants change fuels significantly over the years, as opportunities arise or old

fuel sources dry up. These changes are often not predictable. The best strategy to deal with

this problem is to have a plant design and permits that allow as much fuel flexibility as

possible. For example:

• Bay Front was a coal-fired stoker plant that converted to wood firing and cofiring

capability in 1979. Experience showed that ash fouling and slagging problems were

much more severe when cofiring wood and coal than when firing either fuel alone.

NSP now operates in either 100% coal or 100% wood firing mode.

• In 1989, the ability to burn natural gas was added to McNeil Station. Summer

pricing for Canadian gas was more attractive than wood prices at that time. Six

fossil fuel burners were installed, allowing full load capability (50 MW) on gas and

15 MW capability on No. 2 oil. Gas prices rose during the mid-1990s, and McNeil

burned almost no natural gas from 1997 to 1998.

• At the Shasta plant, a large hammermill was added to the fuel processing system to

allow the use of a broader range of fuels. This reduced fuel costs by allowing the

plant to process opportunity fuels such as railroad ties, brush, and prunings.

• The Tacoma plant was constrained by a limited fuel supply and permit, and worked

hard to develop more options to use opportunity fuels (tipping fee fuels, some of

which are not biomass)—waste oil, asphalt shingles, petroleum coke, etc.

• Colmac found that modifying its permit to allow the use of petroleum coke was

worthwhile. At times, waste fossil fuels can be more economical than biomass.

• The Ridge fuel yard can handle essentially any type or size of wood waste; its only

restriction is that it will not accept palm trees. The simple and reliable traveling grate

stoker boiler can burn these mixed wood wastes, including yard wastes, and can

burn crude tire-derived fuel (TDF) and landfill gas. The emission control system

with a lime spray dryer and baghouse can remove almost any significant pollutant

encountered in these wastes.

Location

As realtors say, “Location, location, location!” Biomass residues and wastes are local

fuels, with very low energy densities compared to fossil fuels. Transport costs become

very significant after about 20 mil, and usually prohibitive beyond 100 or 200 mil. The

ability to have the waste generators deliver the fuel to the plant site at their own expense

requires a location very close to the sources of waste. There are also other considerations,

such as the proximity to residential neighborhoods. For example:
7

• The primary lesson learned from the McNeil plant experience in Burlington,

Vermont, is careful attention to the siting of a biomass-fueled plant. Siting the plant

in a residential neighborhood of a small city has caused a number of problems and

extra expenses over the years: a permit requirement to use trains for fuel supply,

high taxes, high labor rates, local political involvement, and neighborhood

complaints about odors and noise.

• The Colmac plant shows that urban wood waste can be a comparatively expensive

fuel (~$1.50/MBtu) if the plant is located far outside the urban area. The

transportation cost is significant. An urban biomass plant can derive income from

its fuel with a location and tipping fees that attract wood waste generators with

loads to dump.

Reliability and Dependability

Several plant managers with the best long-term operating records stressed the necessity for

placing a high value on reliability and dependability. This is true during plant design and

equipment selection, and during operation. For example:

• Outside of planned outages, the Kettle Falls plant has an availability factor of about

98% over a continuous 16-year period. The superintendent has high praise for the

people on the staff. The plant is always exceptionally clean and neat.

• The Shasta general manager advises: “Always place a high value on reliability and

dependability, for these will allow you to be considered a ‘player’ and thus a

participant in the development of special programs with the utility.”

• At Williams Lake, which has an outstanding performance record, the chief engineer

stressed that staying on top of maintenance programs at all times is essential.

Partnerships

The most successful projects have developed formal or informal partnerships with their

key customers and suppliers. The relationship with the utility company that buys the power

is usually the most important. This may change as generators simply bid their power into a

power pool. Cogeneration plants by definition must have close relationships with their

steam users. Sometimes there are a few large fuel suppliers (such as sawmills) with whom

special relationships are crucial. Examples in this report that illustrate the importance of

strong partnerships include:

• In the words of the Shasta general manager: “But these new approaches must go

forward on a very different basis than our past biomass developments. They must

go forward in partnership with utilities. While the utility may want to participate in

such systems, they will not and cannot do so unless the cost to ratepayers is very

close to that of other generating options.”

• Like several other biomass power plants, the Grayling Station is operated as a

cycling plant. It has run at about a 70%-80% CF during peak demand periods, and

at about a 40%-50% CF during off-peak periods. The McNeil, Multitrade, and

Ridge plants are other examples of cycling plants.

• The arrangement between the Camas Mill and its electric utility (PacifiCorp) is

mutually beneficial. The utility-financed turbine/generator provides the mill with an

additional source of cash flow, without significantly changing the mill's steam

generation and delivery system. The utility has added about 50 MW of reliable

generating capacity to its system for a relatively small investment, and has

strengthened its relationship with a major customer.
8

• The Okeelanta Cogeneration Plant provides many environmental benefits, and

should serve as a reliable energy source for the sugar mill and the electric utility.

Unfortunately, the owners and the utility could not amicably resolve their

differences over a “standard offer” contract. The ensuing lawsuits, bankruptcy,

shutdown, and layoffs significantly affected the project.

Cofiring

Once the availability of low-cost biomass fuel is established, the primary issue addressed

in most retrofitted cofiring projects is how to feed the fuel (and in what form to feed it) to

the coal-fired boiler. There are of course many other issues, such as effects on boiler

operations, plant capacity, emissions, and ash quality. Some of these are highlighted by

lessons learned at four plants in this report:

• Bay Front could use standard wood sizing and feeding equipment because its coalfired boilers were stokers. Cofiring was possible at any ratio of wood to coal from

0% to 100%. However, slagging and fouling was very severe because of the

interaction between the alkali in the wood and the sulfur in the coal.

• The bubbling FBCs at Tacoma can fire 0%-100% wood, 0%-50% coal, and

0%-50% RDF (permit limitation). The actual fuel mix on a heat input basis from

1993 to 1997 was 54%-68% waste wood, 12%-32% coal, and 12%-20% RDF.

Opportunity fuels that command a tipping fee or can be obtained free became a

high priority in 1997.

• The cofiring experience at Greenidge Station demonstrates that a separate fuel feed

system can effectively feed wood wastes to a PC unit. The economics at this site

are favorable; the difference between coal and wood prices is $0.45-$0.79/MBtu.

The plant has continued to cofire wood and invest in system improvements since

the testing began more than 4 years ago.

• The Lahti cofiring project at a PC- and natural gas-fired district heating and electric

generation plant in Finland uses a CFB gasifier to convert wood wastes and RDF to

low-Btu gas that is burned in the boiler. The operation has been technically

successful for 1 year, and gives utilities in the United States another option to

consider when examining the feasibility of cofiring biomass and waste fuels in

coal-fired boilers.

Benefits

The 20 biomass projects in this report provide many concrete illustrations of environmental

and economic benefits. The Kettle Falls, Williams Lake, and Multitrade plants provide air

quality benefits in rural settings where sawmills used to pollute the air with teepee burners.

The Ridge, Tacoma, and Lahti plants serve urban areas by burning urban waste fuels

cleanly; Lahti provides district heat as well. The Okeelanta, Tracy, and San Joaquin plants

burn agricultural residues cleanly, which formerly were burned with no emission controls.

The Shasta, McNeil, and Grayling plants serve the forest management operations in their

areas by cleanly burning unmerchantable wood, brush, and limbs. For example:

• The Bay Front plant was being considered for phaseout as larger, more efficient

units came on line in the NSP system. Adding the ability to use biomass fuel kept

the plant operating, saved jobs, and improved waste management.

• Long-term residents in the Kettle Falls area reported major reductions in haze after

the plant went into operation. The plant improved air quality by eliminating

numerous wigwam burners formerly used to dispose of mill wastes.
9

• In the forests near the Shasta plant: “The result is a healthier, faster growing forest

that has a dramatically lowered potential to be destroyed by fire. There are now

adequate moisture, nutrients and sunlight for the remaining trees and net growth

often triples. The remaining trees regain their traditional resistance to insect and

disease attack.”

• The Grayling and Ridge projects were planned and the plants were designed with

waste management roles in mind—one in a rural setting and the other in an urban

setting. Efforts were made to fit constructively into the local economic and

environmental landscapes, with clearly positive results.

Subsidy Programs Do Not Last

As a final note, the Shasta general manager’s list of lessons learned includes this one:

“Beware of entering a regulatory system in which the utility commission or legislature has

determined that it is acceptable for ratepayers to pay the full cost of your technology. Such

things do not last.”
10

BAY FRONT STATION, ASHLAND, WISCONSIN

________________________________________________________________________

Northern States Power Company’s Bay Front Station, located in Ashland, Wisconsin, on

Lake Superior, can generate as much as 75 MW of electricity using coal, wood, shredded

rubber, and natural gas. Units 1 and 2 account for 40 MW of this nominal capacity. Units 1

and 2 have spreader stoker boilers that were converted from coal only to a multiple fuel

coal/wood/shredded rubber capability in 1979. Either boilers can be fired entirely on wood,

coal, or any blend of wood and coal. However, the preferred mode of operation is to fire

100% coal during periods of high load (44 MW total output), and 100% wood during other

times (30 MW total output). During 1998 Bay Front Units 1 and 2 consumed about

220,000 t of wood wastes from mills, about 30,000 t of shredded railroad ties, and about

2,000 t of shredded tires. Of the 292,200 MWh generated by Units 1 and 2 during the first

11 months of 1998, about 164,000 MWh (56%) were generated from wood.

Vital Statistics

Configuration 2 modified coal stoker boilers

Operating mode (fuel) Wood + TDF Coal

Plant output, MW 30 44

MWh/yr, 1998 164,000 128,000

Fuel consumed, tons/year:

 Wood wastes (from mills) 220,000

 Railroad ties (shredded) 30,000 Scrap tires (shredded) 2,000

History and Outlook

Units 1 and 2 at Bay Front were originally designed to fire 100% coal. These B&W stoker

grate boilers (rated approximately 200,000 lb/h) were converted to crude oil firing without

coal capability during the early 1970s. During late 1970s the oil burners were removed, and

stokers were reinstalled for burning various grades of coal. At this time provisions were

added to allow waste wood products to be blended with the coal. Subsequent modifications

enabled either boiler to be fired entirely on wood, coal, or blends of wood, coal, and

shredded rubber.

During 1991 the Bay Front Station used 171,000 t of waste wood in Units 1 and 2. Twelve

years after the plant first began burning wood, it remained the lowest-cost fuel by nearly a

factor of two. From 1980 to 1994, nearly 1.8 million t of wood waste were burned at the

plant.
11

Efforts to cofire wood and coal in these boilers were abandoned in the late 1990s because

of ash fouling and slagging problems caused by the interactions of the fuel and ash

properties of the two fuels. The coal used at the plant is an Eastern bituminous coal with

an acidic ash. Buildups of slag on the furnace walls hindered operations when the coal

and wood were cofired. The preferred mode of operation now is 100% coal or 100%

wood (and a small percentage of shredded tires). The plant is now evaluating a gas

topping technology developed by Gas Research Institute (GRI), which would cofire wood

and natural gas. If successful, the use of gas topping could make coal firing obsolete in

Units 1 and 2.

Plant Flowsheet and Design Information

Bay Front Station, Units 1 and 2

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condenser

tower pumps

Deaerator Condensate

and

feed pumps

Turbine Electricity

Boiler Steam generator 30 MW

 feed

 water Flue gas

 Tire-derived fuel

Wood

wastes Fuel Stoker Multiclones &

blending and boilers electroscrubber

preparation (2) granular filters

 Ash Fly ash Stack

 Combustion air

Fuel System

All the wood the plant receives is currently delivered by trucks, which are weighed

entering and leaving. Bottom-dumped wood is either stockpiled or immediately reclaimed

with a large front-end loader with an oversized bucket. Trailers are dumped into a live

bottom receiving hopper that conveys the wood waste on an inclined belt conveyor to a

rotating disk screen. A 10-ft permanent magnet is located at the discharge end of the

receiving hopper to collect tramp iron and steel. Oversized material from the disk screen

passes into a 600-hp, 1200-rpm hammerhog for further size reduction. The waste wood

fuel is then conveyed to the top of a 450-ton storage bin, where a distribution conveyor

evenly distributes the waste wood fuel.
12

Bay Front does not use any type of dust suppression/collection system to control wood

dust. Weather covers over the conveyors and enclosures around the hog and similar

equipment help keep the dust in and rain and snow out. On very windy days, dust from the

wood pile can be a nuisance. Green wood dust does not pose as great a threat of explosion

as does fugitive coal dust.

The 450-ton wood bin is rectangular, with a flat bottom and an aspect ratio of 1.8 to 1

(lower than the recommended maximum of 3 to 1). Numerous areas throughout the wood

handling system are monitored by the boiler control room operator via closed-circuit

television. This system very effectively reduces equipment damage and labor costs. All

enclosed chutes are protected with sonic sensors that automatically shut down the

equipment feeding the transfer point in the event of overloading or plugging.

As fuel is required by the boilers, a discharge auger removes a cross section of the stored

wood from the bottom of the storage bin and dumps the well-mixed fuel product onto a

conveyor belt. The belt transfers the fuel for both boilers to a diversion gate where the fuel

is proportioned as needed to four metering bins, two for each boiler. These act as surge

bins between the fuel handling and combustion systems, and provide accurate and

redundant metering of fuel to the boiler. Fuel is fed from the metering bins to rotary air

locks by variable speed augers located at the bottom of the bins.

The rotary air locks feed the material into an 8-inch diameter blow line that is fed by a highpressure blower. The fuel is then pneumatically transported into the plant and to the front of

the boiler, where the high-velocity fuel flow terminates in a target box. The waste wood is

then gravity fed from the target box to a swinging spout fuel proportioner which serves

three of the boiler’s six combination wood/coal feeders. Because of the abrasive nature of

the fuel, all elbows and transition pieces in the fuel blow line are equipped with replaceable

wear plates.

Currently air used to transport the fuel is injected into the boiler along with the fuel.

Evaluation of possible efficiency and combustion improvements dictates that the

elimination of this cold transport air from use in the combustion system be given further

consideration.

Boilers

When NSP studied the feasibility of waste wood combustion at the Bay Front Station,

considerable attention was given to the evaluation of furnace volume requirements. The

boilers had enough grate area and furnace volume to satisfactorily burn wood fuel. When

burning 100% wood, however, the Bay Front boilers cannot reach the original rated boiler

capacity of 200,000 lb/h; only 140,000 lb/h.

Fuels

During 1991 the Bay Front Plant used 171,000 t of waste wood in Units 1 and 2. The

waste wood comes mainly from sawmills located within a 65-mile radius; one mill is

115 miles from the plant. Most of the wood consists of bark and sawdust from various

types of pine, aspen, hemlock, and spruce. As-received heating value and moisture content

of the wood vary considerably depending on the supplier, but overall during 1991 averaged

5000 Btu/lb and 43%, respectively. The overall ash content averaged less than 2%, and

sulfur averaged 0.02%.
13

In 1998 the plant had contracts for 200,000-225,000 t/yr of wood wastes, mostly mill

wastes. A Louisiana Pacific mill had a contract for 120,000-130,000 t/yr; the next largest

contract was for about 30,000 t/yr; about 12 additional mills supplied the remaining 50,000

t/year. The use of shredded railroad ties as fuel was increasing in 1998, to more than

30,000 t/yr. The estimated maximum capacity to burn shredded ties is 60,000 t/yr. This is a

“higher Btu” fuel compared to the 35%-55% moisture content mill residues. Tire chips

(about 2000 t/yr) are even higher in heating value, at about 12,000 Btu/lb.

Because of its light weight, sawdust is handled better when mixed with bark. A 50/50

blend is preferred for handling and firing. Green mill waste quality usually falls within the

following ranges: Btu/lb 4000-6000, moisture 35%-55%, ash 1%-5%, and sulfur 0.01%-

0.1%. Other, drier wood wastes can yield heat contents of 6500-7500 Btu/lb. Shredded

railroad ties average 6500 Btu/lb; shredded pallets average 7000 Btu/lb; and some flooring

and other dried manufactured products wastes are approximately 7500 Btu/lb. Most of the

ash in mill waste is contained in the bark. Logs harvested in wet conditions contain more

dirt. Mishandling by loader operators when retrieving wood from stockpiles can also add

dirt to the fuel.

Operating Experience

The wood fuel feed rate for a given heat input is about twice that of coal on a weight basis,

and more than four times that of coal on a volume basis. Wood fuel quality varies more

than coal quality. Proper tuning of the automatic combustion controls is more important

when firing wood. Operators must pay close attention, and periodically adjust feeders to

maintain even fuel distribution, adjust the ratio of overfire to underfire air, etc.

Combustion gas temperatures in the upper furnace area in the Bay Front units typically

average 1700°-1900°F when burning 100% wood. In the case of 100% coal, the

temperatures are typically a few hundred degrees higher. Wood combustion requires more

excess air and more overfire air than coal combustion.

Coal is usually worse than wood for slagging and fouling. However, a combination of

wood and coal firing often produces worse slagging and fouling conditions than coal firing

alone. This is because of the combination of alkali in the wood and sulfur in the coal. For

these reasons, Bay Front no longer cofires wood and coal.

Wood contains less ash than coal, but ash can be more difficult to collect because of its

physical and electrical properties. Bottom ash, and fly ash from various mechanical

collectors, are removed via a pneumatic system that conveys the ash to a

separator/baghouse on top of the plant’s ash silo. There has been one fire in the pneumatic

system’s baghouse; other than this the plant has experienced very few problems with this

system.

Fly ash reinjection from a primary collector helps improve boiler efficiency when operating

on wood, but may also introduce more fine particles into the flue gas stream, potentially

increasing emissions.
14

Environmental Performance

Wood is inherently low in sulfur content, so sulfur dioxidet (SO2 ) emissions are not of

concern. Another advantage of wood combustion compared to coal or oil combustion is a

reduced level of nitrogen oxidet (NOx ) formation and discharge. The fuel-bound nitrogen

in wood is typically 10% that in coal, and the lower combustion temperature reduces

fixation of air-bound nitrogen. Carbon monoxide (CO) emissions from wood burning

typically exceed those from coal burning, and can be minimized by using preheated

combustion air, preparing good fuel, and carefully controlling excess and overfire air.

Particulate emissions are controlled by electrified gravel bed filters. NSP chose this

technology because of concerns about poor performance with precipitators and fires with

baghouses. One disadvantage of this technology is a high pressure drop through the filter

media. The addition of gravel bed filters along with higher excess air requirements created

the need for larger induced draft (ID) fans.

Bay Front Station has a common ash system for all its boilers (except for bottom ash from

the one cyclone boiler, which fires coal only). The combination coal/wood ash is trucked to

a licensed solid waste disposal site. No unique problems have been encountered in

handling and disposing of the ash.

Economic Information

The main advantage of waste fuel combustion at the Bay Front Station is fuel cost savings.

Oil prices during the mid to late 1970s dictated that the Bay Front plant, then owned by

Lake Superior District Power Company, find alternative, lower-cost, fuel options. Using

wood residue as a boiler fuel made productive use of a material that was previously

disposed in a landfill. Use of waste wood helps stimulate the local economy by keeping

fuel dollars in Wisconsin Waste wood is Bay Front’s lowest-cost fuel option by nearly a

factor of two.

Specific fuel cost information for the Bay Front Station is confidential. In 1994, NSP stated

in a conference paper that “the weighted average delivered cost for wood fuel in the entire

NSP system is expected to be less than $0.75 per million Btu.”

Lessons Learned

The Bay Front Station has benefited from its conversion from coal and oil to biomass and

other waste fuels. The reduction in fuel costs has helped keep this old generating station

operating and has provided continued employment.

Although the fuel handling and feeding systems allow for operation on 100% wood, 100%

coal, and any combination of the two fuels, experience with these stoker boilers has shown

that ash fouling and slagging problems are too severe when cofiring wood and coal. NSP

now operates in either 100% coal or 100% wood firing mode.
15

Sources and Contacts

The information in this section is based primarily on two conference papers that were

presented by NSP personnel:

• Biomass Combustion Conference, Reno, Nevada, January 26-28, 1992. “A

Comparison of Wood, Coal, and RDF Combustion Systems—Focus on NSP Bay

Front and French Island,” by Kenneth Langr.

• BIOENERGY ‘94, Sixth National Bioenergy Conference, Reno/Sparks, Nevada,

October 2-6, 1994. “Biomass Utilization at Northern States Power Company,” by

Richard P. Ellis.

Additional information was provided by Joe Brobjorg of NSP’s fuel resources department,

in phone conversations during December 1998.

Joe Brobjorg

Fuel Resources Department

Northern States Power Company

414 Nicollet Mall

Minneapolis, MN 55401

Phone: 612-330-2856 Fax: 612-330-7671

joseph.brobjorg@nspco.com
16

KETTLE FALLS STATION,

KETTLE FALLS, WASHINGTON

________________________________________________________________________

Avista Corporation, previously known as the Washington Water Power Company

(WWP), has operated a 46-MWe (net) wood-fired steam turbine power plant at Kettle

Falls, Washington, since 1983. Avista is an investor-owned utility company located in

Spokane, Washington. The plant site is 86 miles north of Spokane next to the Columbia

River. Fuel consists primarily of lumber mill wastes from mills in northeastern

Washington, and some in Canada.

Vital Statistics

Design capacity, net MWe 46

Configuration Traveling grate stoker boiler

Fuels Wood wastes (mill residues)

Year 1995 1996 1997 1998

Net generation, MWh/yr 200,237 284,179 279,887 326,469

Annual CF, % 49.7 70.5 69.5 81.1

Net heat rate, Btu/kWh ~14,10

Thermal efficiency, HHV, % 24.2 0

History and Outlook

With new hydroelectric resources nearly exhausted in the Inland Northwest, WWP began

searching for affordable alternative energy sources during the late 1970s. Numerous

lumber mills scattered throughout the Pacific Northwest were coming under increasing

scrutiny for the visual and atmospheric pollution caused by their wigwam burners.

Feasibility, site selection, and preliminary design studies were completed during 1978 and

1979. Based on favorable results of these studies, the company began the licensing phase

of the project, which included preparing a preliminary plant design to support the

development of a budget, obtaining licenses to construct, and securing fuel supplies for the

plant. This effort was finished in January 1980, but the project was put on hold for a year

because of economic conditions. Detailed engineering and procurement of equipment

began in February 1981, and site construction commenced in June 1981. Construction of

the Kettle Falls Generating Station went smoothly, finishing ahead of schedule. The facility

began commercial service in December 1983. With the plant’s opening, WWP became the

first utility in the nation to operate a stand-alone power plant of this size fired entirely by

wood waste.
17

Licensing

In November 1979, applications for 22 permits were submitted to state and federal

agencies. The state issued a draft environmental impact statement in December 1979 and

the final environmental impact statement in March 1980. All state permits were then

approved.

An application for a Prevention of Significant Deterioration construction permit was filed

with the U.S. Environmental Protection Agency (EPA) in July 1979. The application was

judged to be complete in December 1979 and a Preliminary Determination was issued in

May 1980. The final permit was issued in July 1980. For a project of this size burning

waste wood the major air quality concern is emission of particulate matter (PM). The

EPA determined that an electrostatic precipitator (ESP) with an outlet grain loading of

0.02 grains per dry standard cubic foot (gr/dscf) at 12% CO2 represented Best Available

Control Technology. To meet this requirement, a precipitator capable of 99.46%

collection efficiency was specified.

The licensing phase of the project, which included preliminary engineering to support the

licensing process, required an expenditure of $1,420,000 over an 18-mo period.

Plant Flowsheet and Design Information

Kettle Falls Generating Station

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condenser

tower pumps

Deaerator Condensate

and

feed pumps

Turbine Electricity

Boiler Steam generator 46 MW

 feed 1500 psig

 water 950 deg F Flue gas

Wood

wastes

from

mills Fuel Spreader Cyclone

blending and stoker & ESP

preparation boiler

 Ash Fly ash Stack

 Combustion air
18

Fuel System

The wood fuel handling system is designed to minimize transfer points and storage bins

because of the strong tendencies of wood waste to “bridge” and “rat-hole.” The wood

handling system was furnished by Lamb-Grays Harbor. Wood waste is delivered to two

truck dumpers at the plant. The wood waste is conveyed from the truck dumpers to a disk

screen (designed to reject oversized material) to a hammerhog. The disk screen is designed

so wood waste as large as 3 in. is directed to a conveyor belt for transfer to the stackout

system. A self-cleaning magnet and metal detector are included upstream of the disk screen

to remove tramp iron.

Two stackout systems are provided: a tripper conveyor to distribute fuel on the pile for

long-term storage, and a rotating boom that distributes fuel onto the live storage pile. A

bulldozer is used to help distribute the fuel on the storage pile and to reclaim fuel. Wood

waste is stored in an outdoor pile with a capacity equivalent to a 60-d fuel supply.

The fuel is reclaimed on a first-in, first-out basis to minimize problems associated with

spontaneous combustion. The primary method of reclaiming fuel is a top-of-the-pile

conveyor that rotates in a semicircle about the stacker tower structure. An under-pile

dragchain is included for backup when maintenance is being performed on the primary

system.

The reclaimed wood waste is transported via a belt conveyor to a second disk screen, the

purpose of which is to remove frozen chunks of wood waste during the winter or

oversized pieces that have not been initially screened. The rejects are dumped into a storage

bin for manual recycle to the hammerhog. The wood waste is then conveyed to the

powerhouse after passing under a magnet further remove tramp iron.

In the powerhouse, the wood fuel is distributed to six fuel feeder bins using a dragchain To

avoid problems of bridging and rat-holing associated with large bunkers, the feeder bins

have limited storage capacity. The input conveyor system is specified for a capacity of 10%

more than the maximum expected fuel flow rate to avoid starving any fuel feeder bins.

Excess fuel is returned to the wood storage pile via a belt conveyor. Fuel is removed from

the bottom of the fuel bins by screw feeders, which direct it to pneumatic distributors,

which in turn feed it to the traveling grate located at the bottom of the boiler.

Boiler

The traveling grate spreader stoker boiler was furnished by Combustion Engineering and

has the following specifications: Type VU-40, subcritical, natural circulation, wood-wastefired, balance-draft boiler with furnace volume of 42,649 ft3

 and rated 415,000 lb/h (MCR)

steam flow at 1500 psig and 950°F superheater outlet temperature. No external dryers are

provided; the wood waste dries in the boiler combustion section. The steam generator is a

balanced draft unit with forced draft (FD) and ID fans. Natural gas is the backup fuel and is

used for ignition and for flame stability at loads lower than about 70% of maximum. The

boiler is enclosed in a building to provide weather protection and to facilitate maintenance

during the winter.
19

The boiler has upper and lower drums with water wall tubes in the furnace section. In the

convection section are a two-stage superheater, an economizer, and a tubular air heater.

Design feedwater temperature to the boiler is 463°F. Main steam temperature is controlled

by attemperator sprays between the superheater stages. Steam soot blowers are used to

clean the boiler heat transfer surfaces. The design efficiency of the boiler is 70%.

Turbine/Generator

Steam from the boiler is expanded through a General Electric (GE) 17-stage, single flow,

condensing turbine to produce mechanical energy for driving a direct coupled alternating

current generator. The turbine is specified for design inlet steam conditions of 1450 psig

and 950°F with a design exhaust pressure of 2.5-in. Hg abs. The turbine nameplate rating

is 46 MW while extracting steam for five stages of feedwater heating.

The turbine cycle uses five stages of regenerative feedwater heating, including four closed

heat exchangers plus a deaerator. Two 100% capacity boiler feed pumps are provided. The

primary pump is electrically driven, and a steam turbine-driven pump is maintained in a

rolling standby condition to serve as an emergency backup for boiler superheat protection.

This is necessary because of the large fuel inventory on the boiler grate. The two BinghamWillamette full-capacity, high-pressure boiler feed pumps are rated 985 gpm at 1950 ft

TDH. The single-flow centrifugal pumps feature 11 stages. The main boiler feedwater

pump is driven by a 1500-hp electric motor. An auxiliary pump is driven by a 1470 Terry

turbine designed to operate on 900 psig steam supplied from the main steam header.

The GE generator is a 13.8-kV, 3600-rpm, three-phase, hydrogen-intercooled,

synchronous machine, and rated at 53,400 kVA at 0.95 power factor, with a 0.58 shortcircuit ratio. Excitation is provided by a GE solid-state, power-potential transformer/

power-current transformer, thyrister-controlled, self-excitation system. A step-up

transformer is included in the plant to transmit power to the grid at 115 kV.

Turbine exhaust steam is condensed in a shell-and-tube surface condenser furnished by

Transamerica DeLaval. The condenser has a carbon steel shell and stainless steel tubes. A

two-cell evaporative, mechanical draft, counterflow cooling tower, furnished by Research

Cottrell, is used to reject plant heat. A counterflow tower was selected instead of the more

economical cross-flow tower to provide additional freeze protection for cold weather

operation. The power plant makeup water source is the domestic water supply from the

City of Kettle Falls, Washington.

Ash Removal

The ash removal system consists of a combination of dragchain and screw conveyors that

collect ash from the boiler grate, siftings hopper, air heater, mechanical collector, and

precipitator. Bottom ash is discharged from the traveling grate to a water-filled bottom ash

hopper. Bottom ash is continuously removed from the bottom ash hopper by a submerged

chain conveyor system. Fly ash from the economizer hopper, air heater hopper, cyclone

collectors, and ESP hoppers is removed in a dry condition with dragchain conveyors and

mixed with the wet bottom ash for transfer to portable containers. The ash is then trucked

to a nearby landfill for disposal.
20

Emissions Control

The particulate removal system, an ESP furnished by Flakt, Inc., is designed to limit

emissions to a maximum of 0.02 gr/sdcf. Large particles and char are removed by cyclone

collectors at the exit of the air heater. Smaller particles are removed in an ESP. Because the

char can ignite in an oxygen-rich environment, the ESP is positioned at the discharge of the

ID fan to ensure a positive pressure and prevent air leakage into the precipitator. The clean

flue gas leaving the ESP is dispersed through a 180-ft high stack.

The Flakt Inc. ESP has 122,723 ft2

 of collecting surface area, four fields, and maximum

power consumption of 190 kW. It limits emissions to 0.020 gr/sdcf. The single 180-ft tall

corten-steel stack, 10 ft in diameter, has test ports and opacity meters located about halfway

up. (The original ESP had 99,456 ft2

 of collecting surface area, and was replaced during the

plant’s first year of operation, as discussed under Operating Experience.)

Plant Control

The integrated, coordinated Bailey Controls Network 90 system operator interface consists

of three, eight-color interactive graphic CRT/keyboard terminals, two printers, and selected

electronic manual-automatic selector stations. The turbine is equipped with a GE Mark III

digital electro-hydraulic control system.

Fuels

The Kettle Falls plant is designed to burn approximately 500,000 t/yr of 50% moisture

wood waste. Fuel consists of bark, sawdust, shavings, and slabs—milling by-products

from about 15 log processing plants in northeast Washington, southeast British Columbia,

and northern Idaho—approximately a 100-mi radius. The economic haul distance is longer

in cases where backhauls are possible. The average fuel higher heating value (HHV) is

about 4,700 Btu/lb as received. The average one-way haul from suppliers under contract is

about 46 mi. Average transportation costs were estimated in 1983 at 10.8¢/t-mi. Average

delivered fuel costs were estimated in 1983 to be about $12/green t (approximately

$1.40/MBtu).

The supply of hog fuel generated by the lumber mills in the Kettle Falls area continues to

be more than adequate. The plant has had to curtail fuel deliveries from major suppliers at

times. The mills in Canada are generating more biomass fuel than ever, as environmental

restrictions on wigwam burning are tightened.

Operating Experience

The plant has consistently run very well throughout its history, with no major problems

after the initial operating year. During the first year of operation, problems were

experienced with the ESP. The ESP box was undersized, which caused too much fly ash

to be collected on the fourth field plate. When the plate was rapped to discharge the fly ash

to the hopper, some of the fly ash was emitted from the stack. The ESP manufacturer paid

for a replacement unit, which was sized with much greater volume. The new ESP,

supplied by Flakt, can meet the permit specifications with only two of its four fields

operating.
21

From the start of commercial operation in 1983 through the early 1990s, the station’s CF

averaged 88.9%, which includes 6 months the plant was off line for precipitator

replacement shortly after opening. The CF has been lower in recent years, not because of

problems at the plant, but because of the very low market prices for hydroelectric energy in

the Pacific Northwest. Production statistics for 1994-1998 are as follows:

1994 _______ 1995 _______ 1996 _______ 1997 _______ 1998 _______

Net generation, million kWh

Annual CF, %

Annual service factor, %

329.8

81.9

82.3

200.2

49.7

56.5

284.2

70.5

82.0

279.9

69.5

326.5

81.1

During 1997 and 1998 some equipment items were replaced because of wear or corrosion.

These included the superheat section in the boiler, and some tubes or tube sections in the air

heater.

Originally rated at 42.5 MW (net), the Kettle Falls plant can operate continuously at

46 MW (net). On average, the plant generates 1000 kWh of electricity for every 1.5 t of

sawmill waste burned. This is equivalent to a net plant heat rate of about 14,100 Btu/kWh

(24.2% thermal efficiency, HHV basis).

Environmental Performance

No mention was made of any difficulties in complying with the plant’s environmental

permit requirements after the ESP was replaced during the first year of operation. The

stack opacity is generally 1.2%-1.5%.

Economic Information

In 1983 dollars, the estimated capital cost at completion of the project was $82.5 million.

This is about $1940/kW in 1983 dollars, or about $3100/kW in 1998 dollars using the

GDP deflator index. This figure includes all capitalized items including electrical

transmission required to integrate the output into the system. The costs of financing are not

included in this figure.

Lessons Learned

Using wood waste as a renewable resource for power generation has proven to be a

successful operation for Avista Corporation and a sound environmental solution for the

wood products industry. Long-term residents in the Kettle Falls area reported major

reductions in haze after the plant went into operation. The plant improved air quality by

eliminating numerous wigwam burners in Stevens County.

In terms of operating performance, the Kettle Falls plant has an exemplary record. Outside

of planned outages, the plant has an availability factor of about 98% over a continuous 16-

year period. The plant superintendent has high praise for the people on the staff. The plant

is always exceptionally clean and neat.
22

Interestingly, the Williams Lake plant, which started up 10 years after the Kettle Falls plant,

directly benefited from the lessons learned from successful operation at Kettle Falls. WWP

was a 49% owner in the Williams Lake project, and passed the Kettle Falls plant’s

solutions along during design and early operation of Williams Lake. WWP’s share in the

project was subsequently bought out. Williams Lake, which is documented elsewhere in

this report, is the largest and most efficient biomass power plant currently operating.

Sources and Contacts

Most of the information in this section was obtained from plant brochures and Power

Magazine articles (January 1983 issue and 1984 Generation Planbook). Updates on

operating experience were obtained from George Perks, former plant superintendent, in

June 1984 and February 1997. The most recent update on the plant’s operating experience

was given by the current plant superintendent, Dean Hull, in January 1999.

Dean Hull

Plant Superintendent

Kettle Falls Generating Station

Avista Corporation

P.O. Box 3727

Spokane, WA 99220

Phone: 509-738-2449

Fax: 509-738-2598
23

MCNEIL GENERATING STATION,

BURLINGTON, VERMONT

________________________________________________________________________

The Joseph C. McNeil Generating Station of the Burlington Electric Department (BED),

located in Burlington, Vermont, has a nominal capacity of 50 MWe and has operated since

1984. This plant is the largest U.S. utility-owned plant burning wood. When built, it was

the largest dedicated wood-fired electric generating station in the world. Plant operation has

been successful, although New England Power Pool (NEPOOL) economic dispatch

procedures have limited the operations. The plant was retrofitted in 1989 to burn natural

gas, either alone or in combination with wood. The plant has cycled and switched fuels, as

demanded by fuel prices, fuel availability, and NEPOOL’s requirements. It has had to start

up as often as 210 times annually. Between 1990 and 1994, about two-thirds of the fuel

requirements were supplied by wood and one-third by gas. In 1995, about 7% of the

energy input was from natural gas, and in 1996 through 1998 virtually all the fuel burned

was wood, except for the use of gas during startup. During 1997 and 1998 the plant ran at

a CF of about 35%.

Vital Statistics

Design capacity, net MWe 50

Configuration Traveling grate stoker boiler

Fuels Wood wastes: Forest residues

Mill residues

Urban residues

Natural gas (when economical)

Year 1995 1996 1997 1998*

Net generation, MWh/yr 136,000 137,000 155,000 155,000

Annual CF, % 31.0 31.1 35.4 35.4

Net heat rate, Btu/kWh 13,714-14,125

Thermal efficiency, HHV, % 24.2-24.9

 *Projected in December 1998.

History

During the 1970s, most of the power supply for Burlington came from the Moran

Generating Station, which consisted of three 1950s-vintage, 10-MW stoker coal-fired

units. Electric load growth, the aging of the Moran station, and outdated emission controls

prompted BED to examine ways to provide additional generating capacity to meet the

city’s needs. Studies were conducted, and wood fuel scored high on all counts: locally
24

available, reliable, cost-effective, nonpolluting, and acceptable to the public. Using wood

fuel as a generation source could produce important benefits: putting money back into the

Vermont economy, improving the condition of the state’s forests, and providing jobs for

Vermonters.

The pulp and paper industry had proven for years that bark and wood chips could be

burned efficiently and with good environmental controls. The real unknown was the

availability of a fuel delivery network that could reliably supply wood fuel at a reasonable

price. In 1977, Unit 1 at Moran Station was modified for wood chip cofiring. Based on the

success with Unit 1, a second unit was converted to wood in 1979. In 1983 the Moran

plant used more than 100,000 t of wood chips for fuel in addition to 30,670 tons of coal,

146 million ft3

 of natural gas, and 121,011 gal of No. 2 fuel oil. Economic and technical

studies verified that expanded wood firing was viable.

A bond issue was passed by the voters of the City of Burlington in 1978 to finance the

construction of the McNeil Generating Station. In 1979, C.T. Main was hired to design the

plant and to help with the permitting requirements and construction management. The

station was sited on a parcel of land known as the Intervale on the north side of Burlington.

In September 1981, permits were received and site preparation began.

By October 1983 the ESP and steel building structure were essentially completed.

Construction of the main power boiler began in August 1982; the boiler was hydrotested in

April 1983. The turbine-generator set, manufactured in Switzerland, arrived in May 1983

and was first operated in January 1984. On June 1, 1984, the McNeil Generating Station

began commercial operation, producing power as dispatched by New England Power

Exchange.

The final cost of constructing McNeil was $67 million (1984 dollars)—$13 million below

the budget estimate of $80 million. The McNeil Station is jointly owned by BED (50%),

Central Vermont Public Service Authority (20%), Vermont Public Power Supply

Authority (19%), and Green Mountain Power Corporation (11%).

Advanced Renewable Technology Development

Vermont Gasification Project

In August 1994 the U.S. Department of Energy (DOE) entered into a cooperative

agreement with Future Energy Resources Corp. and an industrial and utility consortium to

design, construct, and validate large-scale integrated gasifier and gas turbine combined

cycle technology at the McNeil Station. The “Vermont Gasification Project” is testing and

operating an indirect biomass gasifier developed by Battelle Columbus Laboratories.

During the initial operating phase (ongoing), the gas produced by the gasifier is burned in

one of the natural gas burners of the McNeil boiler. Upon successful demonstration of the

gasifier, a hot gas cleanup system and a commercial-scale (15-20 MWe) gas turbine will be

incorporated into the system.

The Battelle gasification process is an indirectly heated CFB system that has more than

20,000 successful hours of operation at Battelle Columbus at the 10 t/d pilot plant scale.

Wood or other biomass is gasified with a mixture of steam and hot sand. Hot medium-Btu

gas leaves the gasifier with the sand and a small amount of charred wood. The sand is

captured and recycled, while the charred wood is combusted in an FBC that provides heat
25

to reheat the sand, generate steam, and dry wet wood. Capital costs are expected to be low

as the process operates at low pressures without the requirement of an oxygen plant.

Various problems have been encountered in the attempts to operate the scaled-up gasifier at

the McNeil plant, but progress is being made. About 18 months after the completion of

construction, the unit has not yet operated continuously for a sustained period of days or

weeks. The specific problems that have been encountered have not been disclosed, and

work is ongoing. Some major changes were made to the gasifier in late 1998, and funding

is available to continue with the project for at least one more year.

Burlington EcoPark

Burlington is planning an environmentally acceptable industrial park adjacent to the McNeil

Station to use waste heat from the cooling system of the plant. This park will encourage

agriculturally based industries to locate there, which will hopefully create by-products that

can be used as fuel at McNeil. Funding has been finalized for this project, and the design

phase is underway.

Salix Project

More than 5000 short-rotation energy crop trees have been planted at the McNeil site to

determine their success in the Vermont climate. These trees include willows and poplar

trees of various species.

District Heating

Feasibility studies are being completed for installing a district heating system to use the

environmentally acceptable energy from the McNeil Station. This system would initially

provide heat for the University of Vermont campus 1 mile from McNeil. The system

would be expanded to include many other concentrated heating loads in Burlington.

Outlook

After more than 14 years of successful commercial operation, the outlook for the McNeil

Station is uncertain. On September 15, 1998, the Vermont Public Service Board opened

Docket No. 6140, “Investigation into the Reform of Vermont’s Electric Power Supply.”

The four utilities that own the McNeil Station (the “joint owners”) have different

considerations and may pursue different strategies with respect to deregulation and

competition in the electric power industry. The joint owners are preparing to conduct an

analysis of the present and future value of the McNeil Generating Station and its associated

activities. They may take a broad view of investigating the economic values attributed to the

McNeil Station (e.g., environmental benefits, sustainable forest harvesting, participation in

DOE-sponsored R&D such as the Salix short rotation woody crop project and the

Vermont Gasification Project, local economic benefits, emerging green power markets,

and contribution to meeting climate change goals).

Burlington Electric Department’s submittal to Docket No. 6140 suggested the need for

increased access to transmission capacity for the McNeil Station, which would enhance

McNeil’s ability to sell more renewable power in the region and mitigate its costs. BED

advocates an aggressive Vermont policy on renewable energy, especially “native Vermont

renewable energy” such as that generated by the McNeil Station. Included would be a
26

renewable portfolio requirement as a precondition to retail choice in Vermont, and creation

of competitive “green markets” that use indigenous resources.

Plant Flowsheet and Design Information

McNeil Generating Station

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condenser

tower pumps

Steam Air Deaerator Condensate

Dried and

wood Gasification feed pumps

demonstration Turbine Electricity

unit Syn- Boiler Steam generator 50 MW

 Ash gas feed 1275 psig water 950 deg F Flue gas

 Natural gas (when economic)

Wood

wastes Fuel Spreader Cyclones

blending and stoker and

preparation boiler ESP

 Ash Fly ash Stack Combustion air

Boiler

The boiler, a two-drum, top-supported Sterling design with water wall construction, was

furnished and erected by Zurn Industries. It was originally designed to be capable of PC

firing in the future. Initially, three oil burners were installed for startup and flame

stabilization with a maximum heat input of 250 MBtu/h. Provisions were made for an

additional three burners for future consideration. The boiler has two traveling grates and is

rated at 480,000 lb/h at 1275 psig and 950°F when burning 100% wood at 55% moisture

content.

Turbine Generator

The turbine generator for the McNeil Station was manufactured by Brown Boveri

Corporation in Oerlikon, Switzerland. It has 36 stages of rotating blades, five extraction

points for feedwater heating, and 25-in. last stage blades. The turbine is directly connected

to a 3600-rpm air-cooled generator rated at 60,037 MVA. The turbine generator was

specifically designed to accommodate the cycling service expected at the station, as well as

possible future district heating capability. The turbine generator set can supply a maximum

of 59.4 MW gross when exhausting 348,000 lb/h of steam to the condenser at 2 in. of

mercury. Approximately 42,000 gpm of cooling water are required.
27

Cooling Water

The McNeil site is approximately 1 mile from Lake Champlain. During the design phase,

analyses were done to compare obtaining cooling water for the station from Lake

Champlain versus an onsite cooling tower. Economically, the options were very close. A

cooling tower was selected primarily for environmental considerations. A two-cell

mechanical draft counter flow cooling tower was purchased from Research Cottrell. The

tower handles a cooling water flow of 44,000 gpm and a 71°F ambient wetbulb

temperature for thermal design conditions.

Ash Removal

Flue gas is cleaned via a bank of cyclones and an ESP. Combined particulate removal

efficiency is about 99.9%, and particulate emissions are typically about 0.0007 gr/dscf. The

unit generates approximately 5000 t/yr of ash; approximately 10% of this ash comes from

the bottom ash pit. The cyclones capture 65% and the ESP accounts for the remaining

25%. The ash is mixed with agricultural-grade limestone and used as a soil conditioner for

farmlands.

Fuel System

The on-site processing of wood is limited to magnetic separation of tramp metal and

grinding of oversized wood feed. Fuel chips are stored in an open pile (~30 days supply,

~7 acres), fed by conveyor belt through an electromagnet and a disk screen, then fed to the

surge bins above the boiler by belt conveyors. From the surge bins the fuel is metered into

the boiler's pneumatic stokers by augers.

Staffing

McNeil Station has a full-time staff of 39 employees, including four foresters and 20

operators.

Fuels

An average of 70% of the wood fuel used by the plant consists of whole tree chips from

low-quality trees and harvest residues that are cut and chipped in the forest, and transported

by trailer truck to the station or to a railcar loading site in Swanton, Vermont. Wood chips

may be obtained from any forestland where low quality trees are found. Most of these

wood lots are privately owned, although timber is also purchased from large land holding

companies, wood product manufacturers, and wood sales on public lands.

Approximately 25% of McNeil’s wood requirements are met by sawmill residues. Mill

chips and bark are purchased from local sawmills. The amounts of sawdust and mill

residues burned at the McNeil plant have increased in recent years, with the reduced

number of Vermont farms that use sawdust for bedding material. The McNeil plant also

receives approximately 5% of the fuel requirements in the form of clean urban wood waste

from the surrounding area.

Approximately 60% of the wood used by the station is hardwood and 40% is softwood.

Approximately two-thirds of the wood supply comes from Vermont; the balance comes

from New York, Quebec, and occasionally from New Hampshire and even

Massachusetts. The McNeil Station also has a trial onsite plantation where short rotation

energy crops are grown as future fuel for the McNeil Station.
28

Based on figures published by the U.S. Forest Service, 50% of Vermont’s forest inventory

is made up of wood, branches, and bark that have no potential for manufacturing quality

products such as woodenware or furniture. This unusable wood largely consists of tops

and cull portions left behind after trees have been conventionally harvested as sawlogs or

pulpwood. The amount of wood available for whole tree chip harvesting has been

conservatively estimated at 1 million green t/yr in Northern Vermont alone. This is twice

the forecasted need to operate the McNeil Station annually at an estimated 70% load factor.

Wood for the McNeil Station is harvested under strict guidelines developed in conjunction

with the State of Vermont. Burlington Electric is required to have four professional

foresters on staff to supervise the procurement. Every harvesting site and harvesting plan is

reviewed by a forester and approved by the state before the trees are cut. The foresters

ensure that the wood is cut in such a way as to minimize any adverse effects on wildlife

and the land, while optimizing regrowth potential.

Clearcuttings are generally limited to areas where the trees are of very poor quality. It may

also be used in some cases to promote wildlife habitat. In these cases, the size of the area is

limited to a maximum of 25 acres. Clearing is used in cases where the land is converted to

other uses such as development, agriculture, or tree planting.

The Vermont Public Service Board required that 75% of all wood fuel be delivered by rail

to McNeil Station. Burlington is the largest city in Vermont and there were concerns about

traffic congestion from the trucks bringing wood to the station. A typical wood truck

carries 25 t of wood, so three truck loads of wood are required for every hour the plant is

operating at full load on wood fuel.

A remote wood yard is located in Swanton, Vermont, 35 miles from Burlington and 8

miles from the Canadian border. Seventy-five percent of the station wood is delivered to

Swanton by truck. This wood is stored temporarily and loaded into 21 bottom dump

gondola railroad cars. Each car can carry 75 tons of wood chips, or 7000 ft3

. At the McNeil

Station, the railcars are unloaded three at a time through an unloading trestle.

Wood chip costs depend on such factors as the distance from the point of delivery, the type

of material (such as bark, sawmill residue, or whole tree chips), and the mode of

transportation. Chips delivered directly to the plant by truck are less expensive than those

delivered to the Swanton site and shipped by railcar to the McNeil Station. The range of

prices is $10-$23/t delivered (~$20-46/dt, or ~$1.20-$2.70/MBtu). Shipping wood in by

rail imposes an estimated 17% premium on the delivered fuel cost.

After an initial experience with over-storage onsite, which led to serious odor problems and

spontaneous combustion in the wood piles, the plant developed a very tight management

plan for on-site wood chip storage and handling. Piles are limited in size and are monitored

to ensure that they do not reach the odor-producing stage. Fuel is consumed on a first-in,

first-out basis to control the age of the material.
29

McNeil Station is currently economically dispatched by NEPOOL on a least energy cost

basis. As a result, McNeil Station cycles according to alternative fuel pricing, competitive

unit availability, and New England energy demands. McNeil has cycled as often as 210

times annually. The unpredictability of dispatch greatly complicates fuel procurement.

In 1990, the City of Burlington established a waste wood recycling facility at McNeil

Station. Residents of Burlington brought their tree trimmings and leaves to the station

instead of to the landfill. Approximately 1300 t of leaves are composted and spread on

farmlands. Approximately 3000 t of waste wood were processed annually and added to the

McNeil fuel supply. In 1993 the recycling facility was made available to members of the

Chittenden County Solid Waste District, which increased the waste wood supply to 5,000

t/yr. During 1998, approximately 20,000 t of fuel were received from the waste wood

recycling facility. The increased capacity was because of a major ice storm in January

1998.

In 1989, the ability to burn natural gas was added to McNeil Station. Summer pricing for

Canadian gas was at one time more attractive than wood prices. Having an additional fuel

somewhat simplified the fuel procurement/consumption variations. Six fossil fuel burners

were installed allowing full load capability on gas and 15 MW capability on No. 2 oil.

When gas burners were first installed the state NOx emission limits could not be met. A

flue gas recirculation system was added which reduced the NOx emissions from

0.32 lb/MBtu to 0.1 lb/MBtu, well below the standard of 0.13 lb/MBtu.

The annual wood consumption has varied from a maximum of 460,000 t in 1985 to a

minimum of 125,000 t in 1986. After full load capability on natural gas became possible in

1990, about two-thirds of the fuel requirements were met by wood and one-third by gas

until gas prices rose during the mid-1990s. During 1997 and 1998, the McNeil Station

burned almost no natural gas, and burned about 260,000 t/yr of wood (assuming 50%

moisture).

Operating Experience

Following the initial startup, most O&M challenges resulted from the cycling operation of

the plant and uncertainty of fuel requirements. Lower dispatch than anticipated caused

wood inventory to grow to more than 100,000 t in 1985. Some of the wood on site was

more than a year old and was badly deteriorated. The smell from the wood was

objectionable to neighbors. The older wood became very acidic, which caused steel

components in the wood handling system to wear faster than anticipated.

A misalignment of the boiler grates during erection caused high maintenance in that area.

The almost daily cycling of the unit resulted in higher maintenance in the ESP when

carbon-rich ash on the collecting plates would burn when exposed to fresh air after

shutdown. Despite these difficulties, the station has maintained an average availability of

more than 90.9% since June 1984.

Environmental Performance

The air quality permit for the McNeil Station limited the particulate emissions from the

stack when burning wood to 0.007 gr/dscf of flue gas corrected to 12% CO2 . This was far

more stringent than any solid fueled source licensed at the time. To meet these

requirements, GEESI supplied and erected 50-in. diameter mechanical cyclone collectors
30

and a nine field-weighted wire ESP with an overall efficiency of 99.5%. The design gas

velocity in the precipitator was limited to 3 ft/s, resulting in more than 7 acres of collection

plates.

In actual operation, the stack particulate emissions are about 0.0007 gr/dscf. This is 10% of

the state requirements and about 1% of the 0.1 lb/MBtu particulate standards that were

typical of solid fuel stations built when McNeil was built.

The chimney at McNeil is a precast concrete design with a 10-ft diameter corten liner. It

extends 257 ft above grade with a platform midway for monitoring opacity, CO2 , O2 , SO2 ,

flue gas flow, moisture, and NOx . In addition, CO is monitored at the boiler gas outlet.

The plant’s location is less than ideal. It is adjacent to a residential neighborhood of a

metropolitan area. The topography is such that the top of the boiler is at about the same

elevation as some residences on a nearby hill. Truck traffic, noise, odors, and emissions

were problems during project planning and initial operations.

Ash produced from McNeil Station is temporarily stockpiled on site in a landfill area. A

private contractor reclaims the ash, mixes it with agricultural-grade limestone, and markets

it as a soil conditioner for farmlands.

Water removed from the McNeil Station is monitored for pH, temperature, flow, and

metals. It is treated to maintain a balanced pH, allowed to cool to a temperature that will not

adversely affect aquatic life, then pumped to the Winooski River, located about 1000 ft east

of the plant. The wastewater quality is required to be equal to or better than that of drinking

water before being discharged to the river.

Economic Information

The plant cost approximately $67 million to build, or $1340/kW, in 1984 dollars. Adjusted

using the GDP deflator, this is about $2080/kW in December 1998 dollars. The interest

rate on the municipal bonds that financed BED’s 50% share of the plant in the early 1980s

was about 12%. The bonds have been refinanced three times, a costly process. O&M costs

total about $4 million/yr, including $1 million/yr in local property taxes. Spread over the

annual plant output of about 155 million kWh/yr, O&M costs are about 2.6¢/kWh.

Fuel costs depend on market prices and the amount of fuel used to meet NEPOOL

dispatch requirements. In late 1998, the price of natural gas was $2.80-$3.00/Mbtu, so gas

was not used. Wood fuel cost varied between about $1.30 and $1.70/MBtu, which at a net

plant heat rate of 14,125 Btu/kWh was equivalent to 1.8-2.4¢/kWh.

Lessons Learned

John Irving, the station superintendent, believes that the primary lesson learned from the

McNeil plant experience is careful attention to the siting of a biomass-fueled plant. The

plant's site has caused a number of problems and extra expenses over the years: a permit

requirement to use trains for fuel supply, high taxes, high labor rates, local political

involvement, and neighborhood complaints about odors and noise. There are advantages of

an urban setting, such as the ability to obtain urban wood wastes. Although Burlington’s

urban wood waste supply is a small fraction of the plant’s fuel requirement, it effectively

lowers the average cost of fuel and avoids costly and environmentally poorer choices for
31

disposing of this material. Linking the plant’s steam output to a district heating system has

been studied, but has not yet been implemented because of low alternative energy costs

causing marginal economic benefits. Generally speaking, it is best to site a biomass plant

as close as possible to the center of its fuel supply, and far from residential neighborhoods.

Another lesson learned at McNeil was that the long-term fuel contracts insisted on by the

financing institutions can create some costly problems. As required, McNeil had 15 or

20 long-term fuel contracts when it started up, and enjoyed a good first year of operation

with a 70%-80% CF. When the CF dropped during the second year as a result of

NEPOOL dispatch requirements, the fuel kept coming and the plant fuel yard was awash

in wood chips. The resulting lawsuits and settlements with the fuel suppliers were

expensive, and the odors emanating from the aging wood piles became a major nuisance

for the neighbors. After working through these problems, the plant now runs more

economically and flexibly by buying wood fuel with a series of short-term contracts,

thereby avoiding long-term commitments and expensive spot market pricing.

Sources and Contacts

John M. Irving

McNeil Station Superintendent

Burlington Electric Department

585 Pine Street

Burlington, VT 05401

Phone: 802-865-7482 Fax: 802-865-7481
32

WHEELABRATOR SHASTA ENERGY COMPANY,

ANDERSON, CALIFORNIA

________________________________________________________________________

Wheelabrator Shasta Energy Company or "Shasta," an affiliate of Wheelabrator

Environmental Systems Inc., manages a 49.9-MW (net) wood-fired power plant in

Anderson, California (about 140 miles north of Sacramento, just south of Redding). The

plant processes about 750,000 t/yr of mill waste and forest residues from Shasta County

and surrounding areas. The plant, which has three Zurn traveling grate boilers, became

operational in December 1987. In 1996 the plant produced 418 million kWh of electricity

for sale to Pacific Gas and Electric Company (PG&E) under a Standard Offer #4 contract.

The 10-year fixed price portion of the contract expired on April 30, 1998.

Vital Statistics

Design capacity, net MWe 49.9

Configuration 3 traveling grate stoker boilers

Fuels Mill wastes

Forest residues

Agricultural residues (shells, prunings)

Urban wood wastes

Natural gas

Net heat rate, Btu/kWh 17,200

Thermal efficiency, HHV, % 19.8

Net generation, MWh/year 418,000

History and Outlook

Shasta was formed to manage one of Northern California’s most modern independent

wood-fired power plants. Engineering and equipment procurement started in June 1986,

and construction started at the site near Anderson, California, in November 1986. The plant

became operational in December 1987. The project owner and operator is Wheelabrator

Environmental Systems Inc. The owner’s engineer was Rust International Corporation.

Construction financing was provided by Ford Motor Credit Lease, and long-term financing

was provided by Citicorp USA.

The 49.9-MW (net) plant processes about 750,000 t/yr (350,000-400,000 dry t/yr) of mill

waste and forest residues from Shasta County and surrounding areas. Redding is the main

milling center for timber produced in Northern California. Unmerchantable wood wastes

from Shasta-Trinity and Lassen National forests, as well as from private lands in the area,

are selectively removed and processed to improve remaining standing timber.
33

The plant produces more than 400 million kWh of electricity/yr for sale to PG&E under a

Standard Offer #4 contract. The plant design includes three independent wood-burning

units, composed of three state-of-the-art wood-fired traveling grate furnaces with utilitytype high-pressure boilers. The highly automated wood yard design includes capabilities to

accept mill wastes, chips, and unmerchantable whole logs (culls) as large as 6 ft in

diameter, which are chipped on site for fuel.

Shasta has shown excellent performance. On-peak availability has been 100% since

January 1, 1989, and overall availability exceeded 99% during 1995 and 1996. The annual

CF in 1996 was 95%. The net plant heat rate is about 17,200 Btu/kWh (about 19.9%

thermal efficiency based on HHV). The furnaces are specially shaped and have staged

overfire air to reduce NOx emissions. Particulate emissions are controlled by highefficiency ESP.

Like the other California biomass power plants with Standard Offer #4 contracts, Shasta

receives special payments collected from electricity customers and distributed by the

California Energy Commission (CEC) during the 4-year transition period to a restructured

electric industry (1998 through 2001). The California legislation (AB 1890) that established

this support system for extant renewable energy power plants also tasks the state Solid

Waste Management Board with developing a fuel “cost shifting” strategy that would place

the cost burdens more equitably on those who receive the direct benefits (e.g., the farmers

and foresters who produce biomass residues and sell them as fuel). Through these

programs, the owners of biomass plants in California hope to make a successful transition

to the new world of competitive electricity markets.

Plant Flowsheet and Design Information

Boilers

The plant has three Zurn traveling grate, staged combustion furnaces that consume about

100 t/hr of mill waste and forest residues at 50% moisture. The membrane waterwall

boilers each produce about 170,000 lb/h of steam at 900 psig and 905°F.

Turbine Generators

The plant has three Elliott condensing turbine generators. Heat is rejected through three

surface condensers with two multicell evaporative cooling towers.
34

Plant Flowsheet and Design Information

Wheelabrator Shasta Energy Plant

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condensers

towers (2) pumps (3)

Deaerator Condensate

and

feed pumps Turbine Electricity

generators 49.9 MW

Boiler Steam (3)

 feed 900 psig

 water 905 deg F Flue gas Natural gas

Wood

wastes Fuel Stoker blending and ESPs boilers

preparation (3) (3)

 Bottom ash Fly ash Stacks (3) Combustion air

Fuel System

The fuel receiving and processing system consists of two truck scales, three platform truck

dumpers, one hydraulic log loader, one 24-in. knife chipper, and one 72-in. drum chipper,

and infeed/offload conveyors. The fuel storage and reclaim system includes one 50-ft high

stacker with two 130 t/hr overpile reclaimers (each 1100 ft long), one log debarker, and 50

t/hr hammerhog, scalpers, and conveyors. On average, the plant must unload a chip van of

fuel every 15 min, 24 h/d, 7 d/wk, to fuel the plant.

Emissions Control

The furnaces are specially shaped and have three stages of overfire air injection; in addition,

ammonia (NH3 ) is injected into the flue gas to control NOx emissions. The plant has three,

three-field, high-efficiency ESP to collect fly ash. Collected fly ash is spread on farm fields

and bottom ash is used as road base. The staged cooling towers provide for zero water

discharge from the plant.

Plant Control

The plant has a Bailey computer-based distributed control system with multiple CRTs.
35

Staffing

The plant provides full-time employment for about 45 people. Over the years the operating

staff has been reduced by about eight positions. The plant generates related local

employment for more than 125 people to supply, transport, and handle fuel.

Fuels

Maintaining adequate fuel supply in the midst of a declining regional timber industry has

been, and will continue to be, the single biggest challenge for Shasta. By 1991, competition

for fuel had become intense, with more than 400 MW of wood-fired capacity in the region

chasing perhaps 200 MW worth of mill waste. The remainder had to flow directly from

the woods and farms, bypassing the milling operation, or appear as plant output

curtailments, which became typical for many plants during off-peak periods. Battles

between the logging industry and environmentalists over the spotted owl and other issues

caused the wood fuel availability situation in the region to continue to deteriorate.

Almost from startup, Shasta has attempted to diversify its fuel sources and reduce its

demand for wood fuel. From an initial list of permitted fuels that included only mill waste,

logging/thinning residue and cull logs, Shasta had added the following to its permitted fuel

list by January 1992:

• Agricultural residues such as almond, walnut, and pistachio shells.

• Orchard prunings and removals.

• Hog fuel from eucalyptus and poplar plantations.

• Hog fuel from clearing of PG&E and public road rights-of-way.

• Hog fuel from permitted land development projects (roads, subdivisions).

• Fuel from commercial tree trimming companies.

• Fuel from yard waste processing operations.

• Fuel from city, county, and state tree trimming activities.

In addition to expanding its list of fuels, Shasta revamped its cull log chipping system to

begin producing salable paper chips from usable portions of the cull log. Previously, the

cull, or unmerchantable, logs purchased were chipped totally into fuel. In times of high

chip prices, however, Shasta was priced out of the cull log market as the logs were

debarked and chipped elsewhere for paper chips, primarily for the Japanese market. With

the addition of a debarker, high-speed V-drum chipper, chip screen, and overhead bins,

Shasta could offer to custom chip logs, keeping the 35% of the log not suitable for chips.

In times of low chip prices, Shasta purchases the whole log. Shasta successfully marketed

the program to some of the largest landowners in California.

To reduce wood fuel use, Shasta:

• Purchased, rather than produced, off-peak auxiliary power from PG&E, breaking

even on cost and eliminating 7% of its fuel demand.

• Purchased natural gas under long-term contract, supplemented by spot purchases,

that displaced 12%-20% of its wood fuel demand.

• Tested and implemented a fly ash reinjection system on all three boilers, lowering

fuel demand by 3%-4%.

Expanding the list of fuels because of wood fuel shortages placed a decided burden on the

plant’s fuel quality program. The fuel mix that evolved, compared to the design fuel mix,

had a much greater variation in density, size, and moisture content. In addition, the fuels
36

were much dirtier and Shasta was taking more risks with respect to ash properties. The

operators learned to blend all the fuels into a homogeneous mixture that allowed the boilers

to fire at a consistent rate and maintain maximum load under all conditions, without

violating tight environmental standards, excessively corroding heat transfer surfaces, or

slagging beyond the point where the boilers required cleaning more than twice per year.

Shasta accomplished this via fuel contracting and monitoring practices, operating practices,

and equipment selection.

Fuel contracts contain sliding scales of prices base on moisture content, encouraging

suppliers to provide as dry a fuel as possible. Contracts are on a delivered price per BDT,

forcing the supplier to pay the higher freight on a wet load. Contracts specify maximum

percentages of contaminants and fines that will be accepted at full contract prices, and

prohibit any material that cannot be accepted under the plant’s permits, because of either

quality or fuel source.

The fuel receiving, moisture determination, and contract payment functions are all tied

together in a single computer program. All data are entered from electronic displays so no

transposition of numbers is possible. Separate computer databases are maintained for

suppliers, fuel types, carriers, and contracts so all loads are cross-matched to ensure the

plant receives the fuel contracted for, it is traceable for permit purposes to an approved

source, and it is paid for under correct contract terms.

Once the fuel is received and sampled, the blending process, which is the key to stable

operation, begins. The first blend occurs in the three truck dumps that discharge onto a

common belt conveyor. A particularly wet load, for instance, can be held until drier

material is delivered to the other dumps.

A second blend occurs when the bark, fines, and overs from the cull log chipping operation

dump onto the conveyor carrying the truck delivered fuel. Cull log decks are filled by

winter, so maximum winter chipping can be done when chip prices are typically higher and

the need for the drier cull log fuel is greatest. The combined streams then pass over a disk

screen that sends the larger pieces to a hammermill and bypasses the finer material. The

two streams are then combined again on the belt feeding the stacker.

Before being delivered to the stacker, a third blend occurs when the boiler return fuel is

added to the stacker belt. Typically, 15%-20% of the total fuel sent to the boilers is returned

to the stacker to ensure adequate fuel is available at all times to handle boiler swings.

The automated stacker runs on a 1000-ft long track and can stack 40-ft high windrows on

each side of the track. Prudent use of the stacker piles can mean that perhaps 80% of all

fuel received annually is never touched by mobile equipment, but some fuel must be

pushed to dead storage beyond the reach of the reclaimers and then pushed back to even

out the seasonality of the forest products industry. By pushing fuel out to inventory in the

fall, and reclaiming it during the winter and early spring, Shasta can stay within the

6-month fuel rotation requirement of Shasta County and prevent spontaneous combustion

fires.
37

Reclaiming the fuel with automated overpile reclaimers presents two additional

opportunities for blending. The reclaimers have a different pivot point than the stacker, so

they cut across numerous loads of fuel in the process of pulling the fuel in. The use of both

reclaimers simultaneously presents the opportunity to blend fuel from the two windrows

continuously. During heavy rainfall periods, the reclaiming runs can be shortened and the

reclaimer moved to steep sections of the pile so as little surface area of the pile as possible

per ton reclaimed is exposed to rainfall.

The result of these above blending opportunities is a very homogeneous fuel blend going to

the boilers from a very heterogeneous mix of incoming fuel. Typically, the boilers can hold

full load continuously while maintaining a header pressure of ±2 psig.

The fuel variety and sources were not expanded without problems, however. Simultaneous

combustion of natural gas and almond shells created a higher than normal superheater inlet

gas temperature; this, combined with the low melting point of shell ash caused by high

potassium content, created a corrosive environment in the secondary superheater. This was

countered by segregating the almond shells and burning them only when the gas burners

are not in use.

The increase in fuel contamination (dirt, sand, and gravel) led to accelerated wear on the

fuel feeder screws and drop chutes and to additional problems with the traveling grates.

Also, clinkering in the furnace increased with the increase in contamination, but Shasta has

been able to maintain a twice yearly cleaning schedule.

Fuel from a Short-Rotation Woody Crop

Simpson Timber Company in Corning, California, has established a 10,000-acre

eucalyptus plantation called the Tehama Fiber Farm about 44 mi from the Shasta plant.

Hybrid eucalyptus are being grown at very high rates using drip irrigation and fertilization.

The first block of trees was planted in 1989, and the first harvests took place in 1997 (an 8-

year rotation). Pulp chips go to the Simpson Paper Company’s pulp mill, and fuel (ground

bark, tops, and limbs) goes to the Shasta plant. Once the plantation reaches a mature steady

state it could provide a substantial portion of Shasta’s fuel. The future of the fiber farm is

somewhat in doubt, however, because Simpson has the paper mill up for sale. Also, the

fiber farm is working on ways to convert portions of the fuel fraction to higher value

products, such as feedstock for eucalyptus oil manufacture. Success in this area would

reduce the amount of fuel provided by the fiber farm.

Operating Experience

Shasta has shown excellent performance. On-peak availability has been 100% for 8 straight

years, and overall availability exceeded 99% during 1995 and 1996. The annual CF in 1996

was 95%. The net plant heat rate is about 17,200 Btu/kWh (about 19.9% thermal efficiency

based on HHV).

Shasta has improved operations and reduced costs in several ways:

• Markets have been developed for all of the ash. Fly ash is used as soil amendment

on farm land, and bottom ash goes to developers who use it as road base. The plant

pays only part of the freight cost for delivery of the ash, rather than the much higher

disposal costs it paid previously.
38

• The cost of operating the plant’s zero water discharge system, which uses staged

evaporative cooling towers, has been reduced by using some of the water for onsite irrigation and natural evaporation.

• A large hammermill was added to the fuel processing system to allow the use of a

broader range of fuels. This has reduced fuel costs by allowing the plant to process

“opportunity fuels” such as railroad ties, brush, prunings, etc.

• The payroll has been reduced by about eight people. The total staff, including

management and office personnel, is now 45 people.

Environmental Performance

The plant has complied with all permit requirements.

Economic Information

Not provided.

Lessons Learned

Bill Carlson, vice president and general manager, Western Region, Wheelabrator

Environmental Systems, Inc., provided the following discussion of “lessons learned in

burning biomass” in a presentation to the 1995 NBIA/UBECA Joint Annual Meeting.

These lessons were derived from Wheelabrator’s experience in operating biomass plants

for 10 years in California, Maine, and Florida:

• “Never put your faith (and dollars) behind someone’s official natural gas price

projection, particularly when that agency is trying to help you.

• Never design a biomass plant thinking you know what your fuel is going to be.

Design in flexibility of fuels, both in your capital equipment and in your permits.

• Always place a high value on reliability and dependability, for these will allow you

to be considered a ‘player’ and thus a participant in the development of special

programs with the utility.

• Beware of entering a regulatory system in which the utility commission or

legislature has determined that it is acceptable for ratepayers to pay the full cost of

your technology. Such things do not last.

• Never allow a fuel supply system to be developed in which you pay the Btu

“value” of the fuel. Instead, participate in a system that starts with the assumption

that you represent another waste disposal option.

• Other participants in the debate over future electric supply will grant that you have

value in the system only when you are threatened with extinction, and only then

while continuing to complain about your cost.”

Mr. Carlson’s 1995 recounting of the California biomass experience explains the basis for

the six lessons above:

“Like others, we joined the rush to California following the passage of PURPA

seeing gold in the high power rates and abundant biomass fuel supply. The state

was most willing to help, offering ‘standard offer’ contracts with 10 years of

escalating rates based on their lofty projections of avoided costs of natural gas

followed by 20 years of the utility’s actual short run avoided cost. This was teamed

with front end loaded capacity payments for a truly seductive package.
39

“Plants sprang up throughout the northern two thirds of California, numbering at

peak more than 50 plants and totaling a capacity in excess of 800 MW. The fuel

demand quickly outstripped the availability of cheap mill waste and agricultural

processing waste, driving fuel prices steeply upward. Individual entrepreneurs

invested in capital equipment to produce fuel from the forest, the urban waste

stream, orchards and vineyards. These fuels were expensive to produce, but we

could afford it, and many plants had agreed to burn such fuels in order to provide

emission offsets in nonattainment areas. Many of us revisited our air permits

regularly, constantly seeking to broaden the range of fuels that we could burn.

“Before the ink was dry on the contracts, natural gas prices collapsed, leaving our

power well above market. This made renewable power an excellent whipping boy

for the utilities, regulators, and politicians seeking to explain the high cost of power

in California. This clamor culminated in the issuance of the Public Utilities

Commission’s Blue Book in early 1994, a proposal to restructure the electric utility

industry in California. The original proposal called basically for a ‘price only’

system, throwing out previous purchase mandates and fuel diversity goals. It was a

system in which we could not possibly survive.

“The Blue Book caused us all to re-examine the system of biomass energy that had

evolved. By that time we were disposing of about 20% of all solid waste in

California via combustion, we were providing substantial air quality benefits by

eliminating burning of agricultural wastes and forest residues, and we were

restoring forest health and lowering fire potential in substantial portions of

California’s forests. But far from collecting for those services from the parties

benefiting, we were paying premium prices for the fuel and charging it all to the

investor owned utility ratepayers. Not a system that could be sustained in the

current political and regulatory climate.

“The shock of what appeared to be coming caused many biomass producers to

accept utility buyout offers, and nearly 20 plants have since closed. This at least

knocked fuel demand back in balance with supply, and prices are dropping rapidly.

[Note: this was written in November 1995.] In addition, many of us participate in

utility pay-for-curtailment programs, putting further downward pressure on fuel

prices.

“As we organized to try and tell our side of the story, we found that we had

accumulated a substantial number of friends over the years. We had integrated

ourselves into the State’s forestry, agriculture, and solid waste industries to the

point that they rose to defend us at the PUC. State agencies as diverse as the

Department of Food and Agriculture, Cal EPA, Air Resources Board, Forestry and

Fire Protection, Integrated Waste Management, and the Energy Commission

convened a summit to see what they could do to help us. Even environmental

groups weighed in on our behalf because of the positive benefits we provided to

forest practices in California. Clearly we had something positive going here, but we

had certainly structured it all wrong when we placed the full burden of the system

on the backs of ratepayers.
40

“The original PUC proposal has gone through numerous iterations, and its final

form is far from certain. [Again, in November 1995.] The biomass industry has

introduced legislation that would create a competitive pool among biomass energy

producers, driving down prices for biomass power. The pool would only have

room for about two-thirds of current biomass power, making it imperative that you

bid prices low to secure a spot. The pool would phase out in 5-7 years when we

would be at ‘market’. The transition period would give us time to eliminate debt

and to restructure the fuel supply system to dramatically lower prices.

“We have no idea what the outcome will be to the debate in California, but we all

certainly have a lot riding on it. My gut feeling is that we will indeed get some kind

of a transition program, but will be in the open market within 5 years. [Note: a

four-year transition program of support payments to renewable energy generators

was created by the California Legislature, expiring at the end of 2001].

“The debate in California has also caused us to focus on our real strengths and

weaknesses in a way we had not previously. As you all know, our real weakness is

that the power is just too expensive. With ownership costs running 2.5 to 3¢/kWh

for a baseload facility and operation and maintenance costs of 2 to 2.5 ¢/kWh, the

resulting 4.5 to 5.5¢/kWh is not competitive today. And the above number includes

no fuel costs.

“On the strengths side, we have a number of key items that we are relying on in the

current debate:

1. Wood is truly a renewable, domestic resource, with no concerns about being

held hostage by foreign energy suppliers and their governments.

2. Wood energy is primarily rural in nature, at a time when many seek to assist

weak rural economies.

3. Wood energy can be added in small increments, matching the load growth of

the local utility.

4. Wood energy creates more permanent jobs per MW than other technologies

both at the plant and in the fuel supply infrastructure.

5. Wood energy is highly reliable and dependable for the utility. Plants average

95+% annual CF. Our Shasta plant in Anderson, California just completed its

seventh straight year of 100% summer peak CF.

6. Wood energy provides substantial air quality benefits, both globally and in the

location of the plant. As opposed to field burning of agricultural and forestry

residues, there are major reductions in particulates, CO, and hydrocarbons.

7. The wood energy technology is exportable to developing nations, particularly

those without other domestic sources of energy. Wood’s small increment size

and low technology make it particularly appropriate.

8. Solid waste recycling systems achieve better results when wood can be

removed and sent to wood energy plants. In California, nearly 20% of all

material is diverted for wood energy.

9. Agriculture has less public resistance to its activities when byproducts are sent

to wood plants instead of open field burned.
41

10. Forest management practices improve in effectiveness and drop in controversy

when excess nonmerchantable biomass is removed to improve forest health

and lower fire potential. Wood plants can mimic the role of natural fires.

“With the above list of strengths, and our only Achilles Heel being cost of power,

this cries out for a new approach. We have thought long and hard about this and

think that we may have an idea that could restart wood plant construction in the

West, but on different, more sustainable terms. If you will indulge me, I will

describe the concept.

“The New Approach...

“The forests of the Inland West are overgrown, sick and dying because of 80 years

of suppression of natural fires. Without the periodic thinning provided by low

intensity fires, the forest becomes choked with excess vegetation, in many cases

20-50 times the historic number of trees per acre. This condition exists on over 100

million acres in the West.

“At the same time, we are not addressing the issue because of the policy stalemate

over the use of our public forests. Annual harvests are down 80%-90%,

unemployment is high in the rural West, and many communities are suffering

mightily as we endlessly debate the future of the public forests.

“After 60 years of declining numbers of annual acres burned in wildfires, the

number has once again begun to rise. In 1994, over 4 million acres burned in the

West and the suppression cost to the US Forest Service alone was over $1 billion.

And unlike the gentle, cleansing fires of 100 years ago, the excess vegetation today

spawns massive raging fires that kill everything in their path, sterilizing the soil and

which are virtually unstoppable. Today, a burned site may not be capable of

supporting a future forest for several hundred years. The loss of high quality

wildlife habitat is staggering.

“In California, the existence of a string of wood burning plants has spawned some

new forest management techniques that address these issues. Combined with

traditional sawmills and pulp mills, the wood burning plants provide a market for

all of the products removed in a thinning operation, making such an operation

economic for the first time. The landowner is now able to practice a reverse form of

forestry, leaving the older, larger trees that historically populated the site while

economically removing the excess vegetation that used to be consumed by low

intensity fires.

“The result is a healthier, faster growing forest that has a dramatically lowered

potential to be destroyed by fire. There is now adequate moisture, nutrients and

sunlight for the remaining trees and net growth often triples. The remaining trees

regain their traditional resistance to insect and disease attack.

“The results are dramatic. These thinning techniques have been practiced on over

500,000 acres of private and public land in California over 10 years and, as we

found out in the restructuring debate, the results are heavily supported by the public,
42

environmental groups, state and local government and public land managers. It is

your classic win-win situation and would not have happened without the existence

of the wood burning plants. This is a compelling story, and one that needs to be

repeated over the West and, in actuality, in many other forested areas in the world.

“We have set out to do that, starting with a short term demonstration project in the

Blue Mountains of Eastern Oregon, in the heart of some of the most severe forest

health problems. But this time we want to start off differently, based on our lessons

learned in California. Because of the benefits to the landowner and the public, we

will expect the fuel portion to be delivered to the plant for free. The economics of

the overall thinning operation will support that, as the higher valued sawlogs and

pulp chips will pay for the thinning, plus give a return to the landowner, while

paying for fuel processing and delivery. This takes care of our current California

problem of high fuel costs.

“To eliminate capital costs for the demonstration project, we will start with an

existing generating asset, a closed 6 MW plant in Long Creek, Oregon. This will

drop required power contract revenues down to 4¢/kWh to run a break-even

demonstration project. So far, we have only been offered about 2.8¢/kWh for the

power from the Bonneville Power Administration, and so we requested a grant

from the Department of Energy for the difference under their Biomass Power for

Rural Development RFP, but were turned down. We have forged ahead anyway,

hoping to find a way to close this gap.

“The environmental aspects of the thinning will be studied by the Blue Mountain

Natural Resource Institute and reports issued. We expect their work to be funded

by environmental groups interested in the outcome. We expect to bring numerous

elected officials, environmental groups, public land managers, the media and the

public to the Blue Mountains to witness the results on the ground. We will discuss

environmental benefits and economics at length. We expect the demonstration

project to result ultimately in a policy shift toward such thinnings as a way to both

protect and utilize our public forests while at the same time protecting and

enhancing their environmental values.

“Particularly with elected officials, our discussions will center on how to cause

these techniques, and the wood burning plants integral to their success, to spread

throughout the West. With new capital investment, the plants will still need

5.5¢/kWh to earn a reasonable return, a number still well above market. But, if the

existing biomass production tax credit (currently under attack in the House) would

be extended to this activity, that cost would drop to a competitive 3.5¢/kWh. We

should be able, by this time, to demonstrate that the savings to the federal

government, in terms of reduced land management and fire suppression costs, will

be greater than any tax credits granted. The tax credit will hopefully only need to be

for an interim period, since we were less expensive than natural gas before, and we

will be again.

“Should this scenario play out as I described above, there will be a need for 100-

150 (30 MW) plants to accept the thinnings from activities on the lands needing

treatment over the next 20-30 years. This is a significant boost to our industry.
43

“These are our thoughts on how the biomass industry can go forward by

integrating itself into other sectors of the economy, in this case forest products, and

by being paid for the value it brings to the table with free fuel. There are

undoubtedly other opportunities in linking with agriculture, solid waste

management, or just to provide dispersed, small increment, reliable power to rural

areas.

“But these new approaches must go forward on a very different basis than our past

biomass developments. They must go forward in partnership with utilities. It is

easy for a utility, for instance, particularly a rural utility, to grasp the value of the

integrated forest products model I just described, to project the economic benefits to

their service territory, and to appreciate the stability it brings to existing industry.

While the utility may want to participate in such systems, they will not and cannot

do so unless the cost to ratepayers is very close to that of other generating options.

The future world is just too uncertain for them to take any other stance.

“So, we must use our lessons learned to design a system that gets the costs of our

technology out of the pockets of those getting the benefits, and not out of the

pockets of utility ratepayers. If we can do this, the biomass industry can indeed

have a bright future. I hope that you will join us in pushing to get our

demonstration project rolling next Spring and that you will monitor its progress. I

hope that you will join us in pushing the concept of the expansion of the tax credit,

but only at the time that we can demonstrate the value to the public at large of taking

care of their lands with such a system, and when we can demonstrate that the US

government will save more in management costs than it gives in tax credits.”

Sources and Contacts

Most of the information in this section came from two conference papers written and

presented by William H. Carlson, general manager, Alternate Energy Group, Wheelabrator

Environmental Systems Inc.:

• Biomass Combustion Conference, Reno, Nevada, January 26-28, 1992.

“Managing Fuel Quality at a Wood-Burning Power Plant,” by William H. Carlson.

• Strategic Alliances for Biomass Energy, National Bioenergy Industries Association

and Utility Biomass Energy Commercialization Association, Washington, DC,

November 14-16, 1995. “Lessons Learned in Burning Biomass,” by Bill Carlson.

A Wheelabrator Shasta brochure provided descriptive information on the plant, and Bill

Carlson provided information by telephone in February 1997. Contact information:

William H. Carlson

Vice President & General Manager, Alternate Energy Group

Wheelabrator Environmental Systems Inc., Western Regional Office

20811 Industry Road; P.O. Box 7000

Anderson, CA 96007-7000

Phone: 530-365-9172 Fax: 530-365-2035
44

SAN JOAQUIN VALLEY ENERGY PARTNERS,

CHOWCHILLA, EL NIDO, AND

MADERA, CALIFORNIA

________________________________________________________________________

NRG Energy, Inc. of Minneapolis, Minnesota, and its partners own three biomass energy

plants in central California near Fresno. The bubbling FBCs have burned more than 35

types of agricultural and wood wastes, including almond prunings, cotton stalks, corn

stalks, vineyard prunings, straw, and forest residue fuels. Originally four plants were

developed by CAPCO Energy, started up in 1988 through 1990, were bought by the

present owners in July 1992, and shut down in March 1995 after negotiating a buyout

agreement with PG&E. Chowchilla I has been sold and dismantled. Chowchilla II, El

Nido, and Madera remain in operable condition. The owners are soliciting offers for these

plants, to be sold “as is, where is.”

Vital Statistics

Chowchilla II El Nido Madera

Design capacity, net MWe 10 10 25

Configuration Bubbling fluidized bed boiler

Fuels Agricultural residues (prunings, etc.)

Forest residues

Mill residues

Urban wood wastes

Natural gas

CF (peak/partial

peak periods), 1994 98% 99% 93%

History and Outlook

The four CAPCO facilities were built within a 25-mi radius in central California with their

general office in the city of Chowchilla. (Chowchilla is on Highway 99 about 30 miles

north of Fresno and about 20 mi south of Merced. Madera is between Chowchilla and

Fresno, and El Nido is about 15 mi west of Chowchilla.) The Chowchilla I plant came on

line in December 1987; El Nido in October 1988; Madera in July 1989; and Chowchilla II

in February 1990. All operated under Standard Offer #4 contracts with PG&E, which

provided a lucrative schedule of capacity and energy payments for a 10-yr period,

following which the energy payments would be based on the utility’s avoided cost.

The Chowchilla II, El Nido, and Madera plants use bubbling FBCs supplied by Energy

Products of Idaho (EPI). Chowchilla I was a multi-hearth plant that gasified biomass,

producing a low heat content gas that was used by the plant as a fuel for power generation.

A by-product of the Chowchilla I gasification process was a charcoal-like substance that
45

was used as fuel in other facilities. Chowchilla I was shut down in January 1991 because

of various problems. The facility was refurbished by the new owners and returned to

commercial operation in May 1994.

The facilities were permitted to burn more than 50 types of agricultural and wood wastes as

fuel. Madera’s air quality permit required that 25% of the plant’s fuel be offset fuel

(agricultural residues such as orchard prunings that would otherwise be burned in the

field). The other plants’ permits did not require a specific percentage of offset fuels.

In July 1992, NRG and its partners (San Joaquin Valley Energy Partners) bought the

facilities. During the early 1990s, natural gas prices collapsed, and biomass fuel prices

doubled or tripled in California. The cost of power from biomass facilities was much

higher than the market price of energy in the utilities’ systems. In October 1993, PG&E

asked the owners to curtail operations. Under this curtailment plan, the plants generated at

full capacity during peak and partial peak periods, and reduced to minimum load during the

off- and super off-peak periods on weekdays. The plants were taken off line on weekends

and holidays. For 15 months these facilities demonstrated their generation flexibility as

load following facilities.

In April 1994 the California Public Utilities Commission published its Blue Book, a

proposal to restructure the electric industry in California. PG&E offered to buy out the

contracts of many biomass power plants. In general, these offers paid the plant owners

more than they would make from continuing to operate under their contracts, while at the

same time saving the utility money. San Joaquin Valley Partners accepted the utility’s

offer, transferring their power purchase agreements (PPAs) back to PG&E on March 1,

1995. The plants were shut down and are being continuously maintained while being

offered for sale. In the 3 years since, 16 biomass power plants in California, rated

collectively at more than 200 MW, accepted buyout offers and shut down.

Fluidized Bed Combustor Design Parameters and Advantages

The fluidized beds operate at bed temperatures of about 1500°F. Furnace temperatures

above the bed are approximately 1700°F. Average gas velocities in the bed are 8ft/s and

average velocities in the furnace above the bed are 10 ft/s. Underbed air accounts for about

70% of the combustion air supply. Underbed average velocities are approximately 2 ft/s.

Bed energy densities are about 750,000 Btu/ft2

. Static bed depth is maintained at 18 in. The

expanded bed operates at 24 in.

Combustion performance of fluidized bed boilers is generally superior to that of stoker

grate boilers using biomass fuels. The combustion is complete, in that very little char is

present in the boiler fly ash. Normally the ash is light gray. Boiler operation is stable for

biomass fuel; moisture content is 30%-60%. Fuel moisture content is controlled by mixing

biomass wastes (as described in the Wheelabrator Shasta section). Better combustion air

distribution is responsible for reduced CO and hydrocarbon emissions. CO emissions are

typically 100 ppm; O2 levels are 4.5%.

Fluidized bed boilers burning biomass operate approximately 400°F cooler than do stoker

grate boilers. Cooler flame temperature is responsible for a lower percentage conversion of

fuel nitrogen content to NOx . The uncontrolled NOx emissions are 25% lower from

fluidized bed boilers. Further, operating temperatures of fluidized bed furnaces more
46

closely match the temperatures for optimum NH3 and NOx reaction. Control efficiency of

NH3 injection for NOx control is superior in fluidized bed boilers. Temperatures in

fluidized bed boilers are more stable than in stoker grate boilers, which is also a benefit in

NOx control. Lower flame temperatures result in less furnace slag formation and buildup

on boiler surfaces.

Chowchilla II Plant Flowsheet and Design Information

Chowchilla II Biomass Plant

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condenser

tower pumps

Deaerator Condensate

and

feed pumps Turbine Electricity

generator 10 MW

 Boiler Steam

 feed 650 psig

 water 750 deg F Flue gas

 Natural gas (startup)

Biomass

wastes Fuel Bubbling Multiclone

blending and fluidized bed and

preparation boiler baghouse

 Limestone Fly ash Stack

 Combustion air

Boiler

• Atmospheric FBC (bubbling bed) provided by EPI.

• 700-hp ID fan.

• 600-hp FD fan.

• Two boiler feed pumps, one with 250 hp motor, the other with Terry steam turbine

driver.

• Forced circulation boiler

• 650 psig and 750°F main steam pressure and temperature.

• 130,000 lb/h main steam flow.

• 12 t/h maximum solid fuel feed rate.

Turbine/Generator

• General Electric turbine.

• General Electric generator (12.5 MW, 13,800 volts).
47

Electrical

• Main transformer: 16,000 KVA.

• Main line voltage: 120,000 volts.

• Capacity loss adjustment factor: 0.989.

Water

• Raw water supplied from onsite well with backup from city water system.

• Firewater system charged by city water system.

• Reverse osmosis and demineralization water treatment for boiler makeup capable of 12

gpm throughput.

• Cooling water 14,000 gpm circulation rate.

• Two cell evaporative cooling tower.

Emissions Control

• Multiclone separator and fabric filter baghouse for particulate control.

• Ammonia injection for NOx control.

• Limestone injection to fluidized bed for SO2 control.

• Ash utilized as soil amendment on local soils.

• Wastewater routed to onsite evaporation/percolation basins and used for onsite dust

control, etc.

• Continuous emissions monitoring of criteria pollutants.

Plant Site

• Total site acreage: 14 acres (net).

• Perimeter fenced and key card gated access.

• Zoning: I 2, Heavy Industrial.

Permitting

• All permits active.

• No offset requirements.

El Nido Plant Flowsheet and Design Information

Boiler

• Atmospheric FBC (bubbling bed) provided by EPI.

• 700-hp ID fan.

• 600-hp FD fan.

• Two boiler feed pumps, one with 250-hp motor, the other with Terry steam turbine

driver.

• Forced circulation boiler

• 650 psig and 750°F main steam pressure and temperature.

• 130,000 lb/h main steam flow.

• 12 t/h maximum solid fuel feed rate.

Turbine/Generator

• General Electric turbine.

• General Electric generator (12.5 MW, 13,800 volts).
48

El Nido Biomass Plant

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condenser

tower pumps

Deaerator Condensate

and

feed pumps Turbine Electricity

generator 10 MW

 Boiler Steam

 feed 650 psig

 water 750 deg F Flue gas

 Diesel fuel (startup)

Biomass

wastes Fuel Bubbling Multiclone

blending and fluidized bed and

preparation boiler baghouse

 Limestone Fly ash Stack

 Combustion air

Electrical

• Main transformer: 16,000 KVA.

• Main line voltage: 72,500 volts.

• Capacity loss adjustment factor: 0.9741.

Water

• Raw water supplied from onsite well.

• Firewater system charged by plant water system with backup diesel driven pump.

• Demineralization water treatment for boiler makeup capable of 200 gpm throughput.

• Cooling water 14,000 gpm circulation rate.

• Two cell evaporative cooling tower.

Emissions Control

• Multiclone separator and fabric filter baghouse for particulate control.

• Ammonia injection for NOx control.

• Limestone injection to fluidized bed for SO2 control.

• Ash used as soil amendment on local soils.

• Wastewater routed to onsite evaporation/percolation basins and used for onsite dust

control, etc.

• Continuous emissions monitoring of criteria pollutants.
49

Plant Site

• Total site acreage: 76 acres.

• Perimeter fenced and key card gated access.

• Zoning: A 1, General Agricultural.

Permitting

• All permits active.

• No offset requirements.

Madera Plant Flowsheet and Design Information

Madera Biomass Plant

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condenser

tower pumps

Deaerator Condensate

and

feed pumps Turbine Electricity

generator 25 MW

 Boiler Steam

 feed 850 psig

 water 850 deg F Flue gas

 Propane (startup)

Biomass

wastes Fuel Bubbling Multiclone

blending and fluidized bed and

preparation boiler baghouse

 Limestone Fly ash Stack

 Combustion air

Boiler

• Atmospheric FBC (bubbling bed) provided by EPI.

• 1500-hp ID fan.

• 1750-hp FD fan.

• Two boiler feed pumps, one with 600-hp motor, the other with Terry steam turbine

driver.

• Forced circulation boiler

• 850 psig and 850°F main steam pressure and temperature.

• 260,000 lb/h main steam flow.

• 28 t/h maximum solid fuel feed rate.
50

Turbine/Generator

• Elliot turbine.

• Brush generator (28.5 MW, 13,800 volts).

Electrical

• Main transformer: 37,333 KVA.

• Main line voltage: 120,000 volts.

• Capacity loss adjustment factor: 0.989.

Water

• Raw water supplied from onsite well.

• Firewater system charged by plant water system with backup diesel driven pump.

• Reverse osmosis and demineralization water treatment for boiler makeup capable of 20

gpm throughput.

• Cooling water 16,000 gpm circulation rate.

• Three cell evaporative cooling tower.

Emissions Control

• Multiclone separator and fabric filter baghouse for particulate control.

• Ammonia injection for NOx control.

• Limestone injection to fluidized bed for SO2 control.

• Ash used as soil amendment on local soils.

• Wastewater routed to onsite evaporation/percolation basins and used for onsite dust

control, etc.

• Continuous emissions monitoring of criteria pollutants.

Plant Site

• Total site acreage: 160 acres.

• Perimeter fenced and key card gated access.

• Zoning: ARE 40, Agricultural Rural Exclusive > 40 acres.

Permitting

• All permits active.

• Offset requirements: 25% of fuel to be offset fuel.

Fuels

Although most biomass plants in California concentrated on burning a high percentage of

clean orchard or urban wood materials, the San Joaquin Valley Energy Partners

experimented in combusting low-cost, low-demand agricultural waste materials such as

grape pomace, green waste, onion and garlic skins, and bedding materials not desired by

competing facilities. This operating philosophy resulted in changes to standard operating

practices and alteration of the original plant design to successfully consume a much higher

percentage of these low-cost materials. (Details were not made available.)
51

NRG stated in its offering memorandum that this practice enabled the facilities to control

and reduce average fuel costs below these of competing facilities and ensure a reliable

supply during tight wood fuel market conditions. The owners were able to operate these

plants with wide fuel flexibility, thus acquiring an economic advantage over the other

biomass energy producers. (Interesting that the owners accepted a buyout offer if they had

an economic advantage.)

Biomass materials that were successfully combusted fell into four categories:

• Agricultural wood: wood derived from whole orchard removal and orchard

pruning harvested annually. Almond, nectarine, grape, orange, and olive prunings

are examples of this category.

• Miscellaneous agricultural wastes: waste materials generated in processing

agricultural produce such as olives, almonds, prunes, peaches, and many others.

These materials include nut shells, grape and olive pomace, and stone fruit pits.

• Urban wood: derived from construction wood waste, demolition wood, tree

prunings, and other wood wastes sorted from landfill materials generated by

municipalities throughout California.

• Rangeland/forest wood waste: wood materials in the forms of logs, limbs, stumps,

and brush that are not marketable for fiber or lumber products.

• Green wastes: urban tree trimmings, stumps, grass clippings, leaves, and any other

plant material that has become a disposal liability to waste processors.

Fuels burned at the San Joaquin Valley Energy Partners facilities are listed below. The

fuels in categories P1 through P3 are the primary fuels, which constituted more than 50%

of the plants’ fuel. Secondary fuels (S1 through S4) made up 20%-50% of the total fuel,

and tertiary fuels (T1 through T3) accounted for less than 20% of the total fuel to the plants.

Operating Experience

All three plants proved to be reliable. They demonstrated the ability to burn a wide variety

of biomass fuels, including waste materials that other similar biomass plants avoided

burning in significant quantities because of operating difficulties. To maintain high

reliability, planned maintenance shutdowns were scheduled for 2 weeks during the spring

and 1 week during the fall. Major repairs were done during these planned shutdowns to

prevent emergency failures and outages. Typical outage repair work included refractory

repair; boiler tube replacements and installation of shields; electric motor preventive

maintenance work; fire side cleaning, baghouse cleaning and bag replacements; and bearing

replacements, motor control center cleaning, and preventative maintenance inspections of

all pumps, motors, gear boxes, fans, and other key components. The historical profiles of

forced outages indicated an improving trend for reliability for all three plants. The facilities’

operating histories are tabulated below, in terms of annual percent availability and percent

CF (during peak and partial peak periods):
52

Almond prunings P1

Apple prunings P1

Apricot prunings P1

Cherry prunings P1

Citrus prunings P1

Fig prunings P1

Generic orchard prunings P1

Grape prunings P1

Nectarine prunings P1

Olive prunings P1

Peach prunings P1

Pecan prunings P1

Pistachio prunings P1

Plum prunings P1

Walnut prunings P1

Cedar bark P2

Forest slash/cull P2

Hog fuel (mill residue) P2

Sawdust P2

Construction wood waste P3

Demolition wood P3

Landfill derived wood P3

Landscape tree trimmings P3

Pallet/bins wood P3

Urban development clearing trees P3

Grape pomace S1

Olive pomace S1

Raisin pomace S1

Tomato pomace S1

Cherry pits S2

Nectarine pits S2

Olive pits S2

Peach pits S2

Prune pits S2

Almond shells S3

Peanut shells S3

Pecan shells S3

Pistachio shells S3

Walnut shells S3

Cotton stalks S4

Coffee grounds T1

Cotton gin trash T1

Turkey (wood) shavings T1

Ditchbank or canal weeds T2

Tumbleweeds T2

Alfalfa straw T3

Barley straw T3

Bean straw/stalks T3

Corn stalks T3

Milo/sorghum T3

Rice straw T3

Wheat straw T3

Char T3
53

Chow II El Nido Madera

Date commissioned February 1990 October 1988 July 1989

% Availability:

1992 79% 87% 83%

1993 84% 95% 86%

1994 89% 94% 90%

1995 (Jan & Feb only) 99% 95% 99%

Project 87% 87% 87%

% CF

(peak/partial peak periods):

1992 94% 99% 99%

1993 96% 96% 98%

1994 98% 99% 93%

1995 (January and

February only)

99% 93% 99%

Sustainable maximum 97% 97% 97%

Sustainable minimum 55% 55% 55%

The load-following capability, or dispatchability, of the bubbling fluidized bed units

depends on the startup, ramp, and shutdown period requirements as shown below. The

best load-following scenario for these facilities is operating the units at maximum load

during peak/partial peak periods, then reducing to minimum load during off-peak periods.

The generating units may be taken completely offline on weekends and holidays and

started up for normal weekdays.

Chow

II

El Nido Madera

From cold shutdown to maximum load, h 12 12 12

From hot shutdown to maximum load, h 5 5 5

From min. load to maximum load or vice versa, h 1 1 1

From maximum or minimum load to zero, h 0.5 0.5 0.5

From synchronization to maximum load, h 2 2 2

From hot shutdown condition to cold shutdown

(unforced), h 60 60 60

Sustained maximum load, MW 10.8 10.8 24.6

Sustained minimum load, MW 6 6 14
54

Environmental Performance

The facilities’ air quality permits were issued by the San Joaquin Valley Unified Air

Pollution Control District. Continuous emissions monitoring equipment records the levels

of SO2 , NOx , CO, opacity, and NH3 emissions from the units. Permit and emission levels

of the criteria pollutants at each plant are as follows, in lb/h:

SO 2 NO x CO VOC PM 

Chow II: Permitted 10.4 10.4 22.9 10.4 6.2

 Actual 2.6 8.0 14.7 0.1 5.4

El Nido: Permitted 8.0 10.4 22.9 10.0 6.0

 Actual 1.9 8.9 12.2 0.1 0.9

Madera: Permitted 29.0 50.0 60.0 24.0 10.0

 Actual 0.5 16.0 30.0 0.3 6.5

The facilities’ water permits are covered by the Waste Discharge Requirements (WDR) of

the Regional Water Quality Control Board (RWQCB). The WDR allow for disposal of

nondesignated wastewater into unlined ponds on the site. Plant systems are set up to allow

all water to be disposed in this manner.

The facilities’ solid wastes consist of ash (the noncombustible components of the biomass

fuel) and spent bed material, including the limestone added for sulfur control. The ash is

nonhazardous and is useful as a soil amendment. All the ash produced (100%) is recycled

to farms throughout the San Joaquin Valley as a beneficial soil additive. Routine sampling

and analysis procedures ensure that the ash so distributed complies with all requirements

for such use. This method of ash disposal is permitted under the WDR issued by the

RWQCB.

Economic Information

Not provided. In general, fluidized bed boilers cost more than stoker grate boilers.

Operating cost is also greater. Fluidized bed boilers cost more because of two additional

boiler support systems, the preheat burner and the bed sand recycle system. Additional

operating expense for fluidized bed boilers is a result of forced draft fan energy

requirements and bed sand use.

A forced outage in a fluidized bed boiler is more costly than for a stoker grate boiler.

Preheat expense and increased down time are increased cost factors for fluidized beds. Bed

clinkering also requires replenishment of bed material, which can be expensive.
55

Lessons Learned

Not provided. The primary lesson learned from the experience of the San Joaquin Valley

Energy Partners was apparently that agricultural residues can be burned successfully in

FBCs. However, the most difficult agricultural residues were assigned to the “tertiary” fuel

category and mixed in small percentages with better fuels, primarily wood. All the primary

fuels on the plants’ fuel list are wood waste fuels, which constituted at least 50% of the

total fuel. The secondary fuels consist of materials such as pomace, pits, shells, and stalks,

and were kept in the range of 20% to 50% of the total fuel mix. The tertiary fuels are the

notoriously difficult ones: straw, gin trash, weeds, etc. These fuels were kept below 20% of

the total fuel mix.

Sources and Contacts

The information in this section was obtained from an offering memorandum dated May 1,

1997, posted on the NRG Energy, Inc. web site (www.nrgenergy.com). A telephone call

to Mark Anderson of NRG (612-373-5350) on September 3, 1998 confirmed that the

Chowchilla II, El Nido, and Madera plants were still for sale.

Contact information:

NRG Energy, Inc.

1221 Nicollet Mall, Suite 700

Minneapolis, MN 55403

Attn: Mark Anderson

Phone: 612-373-5350
56

BORALEX STRATTON ENERGY,

STRATTON, MAINE

________________________________________________________________________

The 45-MW Stratton Energy plant is the largest biomass-fired independent power project

developed in Maine in response to PURPA regulations enacted by the state Public Utilities

Commission. Originally developed by the ARS Stratton Group, the plant was bought in

September 1998 by Boralex Inc., a Canadian company that owns a number of

hydroelectric plants, three biomass plants, and one natural gas combined cycle plant.

Central Maine Power Company (CMP) bought out its contract with the plant on July 28,

1998, and Boralex Stratton Energy now sells its power to Cinergy, a broker, under a 3-year

contract. This new arrangement has allowed the plant to operate at full capacity; the CF

from July 28, 1998 through December 31, 1998 was 100%.

Vital Statistics

Design capacity, net MWe 45

Configuration Traveling grate stoker boiler

Fuels Sawmill residues ~75%

Whole tree chips ~25%

Year 1995 1996 1997 1998

Net generation, MWh/year 305,000 305,000 353,000

Annual CF, % 77.4 77.4 89.5

Net heat rate, Btu/kWh ~13,500

Thermal efficiency, HHV, % 25.3

History and Outlook

Central Maine Power Company, the largest electric utility company in the state, issued a

series of requests for project proposals during the 1980s. The Stratton Energy plant was

developed by the ARS Stratton Group. The project manager was HYDRA-CO Enterprises

Inc., which was acquired by CMS Generation Company in 1995. The plant owner was

then Stratton Energy Associates, a partnership of the ARS Stratton Group and CMS

Generation Company. On July 28, 1998, CMP bought out the plant’s PPA. On September

25, 1998, Boralex Inc., bought the plant from Stratton Energy Associates. Boralex Stratton

Energy has a 3-year contract with Cinergy, who resells the power as a broker. On April 1,

1999, the Maine power market will be opened to wholesale customers, and in 2000, retail

customers will be directly available to Boralex Stratton Energy.
57

The in-service date was November 1989, and the first “power year” (November 1, 1989

through October 30, 1990) was the only year so far in which the plant did not deliver its

full contracted amount of electricity to CMP. The original contract with CMP called for

delivery of 295 million kWh/yr. In 1994 the amount was increased to 305 million kWh/yr.

The contract was complicated, calling for some zero dispatch and 19.8 MW output periods

on weekends. Since July 28, 1998, when the CMP contract was bought out, the plant has

run at 45 MW (100% CF). Plant availability has been consistently in the 99% range.

The actual rated net capacity of the power plant is considerably higher than 39.8 MW,

which was the contracted amount of capacity under the original contract with CMP. Twice

each year NEPOOL runs a capability audit. Based on these audits, the Stratton Energy

plant can deliver as much as 47.68 MW of electricity to the grid. A nominal 45-MW

capacity has been used here to calculate CFs.

CMP Press Release, July 28, 1998

The following press release, issued by CMP on July 28, 1998, is instructive about the

Stratton contract buyout, as well as the context in which it occurred:

AUGUSTA, Maine, July 28, 1998—As of today, Central Maine Power Co.’s

purchases of electric energy from a non-utility power plant in Stratton are subject to

a new arrangement with that will save the present-value equivalent of more than

$28 million for CMP and its customers.

The power-sales contract with CMP that was formerly held by Stratton Energy

Associates has been transferred to an affiliate of Cinergy Capital & Trading, a

subsidiary of Cinergy Corp. of Cincinnati, Ohio. Meanwhile, the wood-fired power

plant’s owners have sold 100% interest in the plant to Boralex, Inc., of Montreal,

Canada.

Under new contractual arrangements, the 45-megawatt Stratton plant’s output will

be devoted to supplying CMP’s needs through mid-2001; deliveries through 2009

could be provided by any resources available to Cinergy. The Stratton facility

would operate as a “merchant plant” after 2001, competing freely in the electricity

marketplace.

Necessary approvals were obtained from the Maine Public Utilities Commission

and the Federal Energy Regulatory Commission. The FERC review included a

new transmission interconnection agreement for the plant.

Like many other non-utility power contracts signed under state and federal energy

policies of the 1980s, the Stratton contract provides energy at prices substantially

above current market levels. CMP has bought out, legally terminated, or

restructured 42 of these contracts since 1992, for savings estimated at $258 million

over the next five years. The indexed price-cap system administered by the Maine

PUC provides for such savings to be shared between CMP and its customers

during the annual price-cap adjustments.
58

Maine’s 1997 electric-competition law requires CMP to seek further economies in

these contracts and other commitments. The aim is to reduce any “stranded-cost”

transition charges that might appear on distribution customers’ bills after retail

competition starts on March 1, 2000 to continue recovery of previously authorized

costs. (End of press release.)

In a different press release about a similar contract buyout, CMP stated that the average

price of electricity across all of its nonutility power contracts was about 8.4¢/kWh, and

stated that this was approximately twice the current (1998) wholesale electricity price in the

state.

Plant Flowsheet and Design Information

Boralex Stratton Energy Plant

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condenser

tower pumps

Deaerator Condensate

and

feed pumps

Turbine Electricity

Boiler Steam generator 45 MW

 feed 1485 psig

 water 955 deg F Flue gas

Wood

wastes

from

mills Fuel Spreader Cyclone

blending and stoker &

and preparation boiler ESP

forestry Ash Fly ash Stack Combustion air

The plant has one traveling grate stoker boiler, provided by ABB-CE, that can produce

400,000 lb/h of 1485 psig, 955°F steam. Mitsubishi provided the steam turbine and Brush

provided the generator. Mechanical dust collectors and an ESP remove the PM from the

stack gas. Staged combustion air is used to reduce NOx emissions to 0.18-0.20 lb/Mbtu.

Staffing

In 1997, the plant had 33 employees.
59

Fuels

Before July 28, 1998, the biomass fuel for the plant consisted of about 60%-70% sawmill

residue (sawdust and bark), and about 30%-40% whole tree chips (which are mostly chips

produced from unmarketable tops and limbs in forestry operations). The mill residues are

considerably lower cost than the whole tree chips. Boralex has been able to increase the

percentage of mill residues to about 75%, which has reduced the overall fuel cost

somewhat. Plenty of fuel is available in the area, but availability varies from season to

season.

A variety of fuel purchasing arrangements are used: 5-, 3-, 2-, and 1-year contracts, plus

some spot market purchases. Before the contract change, when the plant generated about

305,000 MWh/yr, the annual biomass use was about 464,000 t (as-received basis at

nominally 50% moisture). Now that the plant is running at close to 100% CF, the fuel

consumption rate is about 550,000 t/yr. The average net plant heat rate is about 13,500

Btu/kWh (25.3% thermal efficiency, HHV basis).

Operating Experience

The only area of the plant that required significant modifications after startup was the fuel

yard. The original owners spent about $1.8 million during the first year of operation to

improve the operation of the fuel yard. Since that time the plant has operated reliably.

Boralex Inc. has made no major changes in the plant equipment or operations since it took

over in September 1998.

Environmental Performance

No mention was made of any difficulties in complying with the plant’s environmental

permit requirements. The plant is a zero discharge facility.

Economic Information

Statements by CMP imply that the original contract provided Stratton Energy an electricity

price of about 8.5¢/kWh. The new contract provides a price that is less than half the old

contract price—probably about 4¢/kWh. Because the plant has a new owner who agreed to

the new power purchase contract, the operation is most likely profitable, or at least close to

profitable, at this price level. In March 2000, the owner will be able to sell green power

directly to retail customers, presumably at a premium over the current wholesale price.

Lessons Learned

The Stratton plant is a relatively large, efficient wood-fired plant with an excellent operating

history. It appears to have a reasonable chance of surviving the transition from the

regulated market of the 1980s with PURPA incentives to the competitive electric market of

the 2000s. The plant managers in 1997 and 1999 did not identify any specific lessons

learned, other than improvements to the fuel yard.
60

Sources and Contacts

The primary sources of information on the Stratton Energy plant have been the plant

managers—Dan Noel in February 1997 and Jean Roy in February 1999.

Mr. Jean Roy

General Manager

Boralex Stratton Energy

Route 27 - P.O. Box 140

Stratton, ME 04982-0140

Phone: 207-246-2252, ext. 12 Fax: 207-246-2257
61

TRACY BIOMASS PLANT, TRACY, CALIFORNIA

________________________________________________________________________

The Tracy Biomass plant is an 18.5 MW (net) wood-fired plant that burns a little less than

50% orchard wood waste (“agricultural fuel”) and a little more than 50% urban wood

waste. The agricultural fuel is required by the permit, which provides an offset from open

burning emissions. The plant has a heat rate of 13,500-14,000 Btu/kWh. Plant availability

has been high, and CF is more a function of contractual requirements than of availability.

Vital Statistics

Design capacity, net MWe 18.5

Configuration 1 water cooled vibrating grate stoker boiler

Fuels Agricultural residues (orchard removals & prunings)

Urban wood wastes

Net heat rate, Btu/kWh 13,500-14,000

Thermal efficiency, HHV, %24.4-25.3

Net generation, MWh/yr ~130,000

The plant is in a good location, near the intersection of major freeways I-580 and I-5 about

35 mi east of Oakland. Highway 99, which runs through the heart of California’s

agricultural San Joaquin Valley, is about 15 mi east of Tracy. One million acres of orchard

land are both north and south of the plant, and the major landfills for the San Francisco Bay

Area are in the vicinity (as is the Stanislaus County Waste-to-Energy plant). Thus the plant

is well situated to receive agricultural and urban wood wastes.

History and Outlook

The plant came on line in 1990, and will receive “year 1-10” Interim Standard Offer #4

(ISO4) payments for its electricity through 2000. Under a negotiated change in the contract,

PG&E has the right to curtail the plant’s operation by up to 1000 h/yr, and does so. Tracy

Biomass will pay off its construction loan by 2000, and the challenge will be to operate

“lean and mean” enough to stay in business after the CEC transition payments and the

ISO4 year 1-10 payments expire.

Tracy Biomass is noted for a dedicated effort to inform and educate the local population

about biomass and the advantages of biomass power. The public education is not formal

program, but a varied collection of regularly practiced effective efforts. These efforts have

included local and regional speaking engagements, use of local print media for timely story

coverage, participation in Chamber of Commerce and Farm Bureau activities, sponsorship

of local festivals, manning of booths at agricultural fairs, conducting tours for school
62

children and teachers, and regular communication with local political representatives. As a

part of its good neighbor policy and in recognition of a need, Tracy Biomass developed a

yard waste program, in which local residents could dispose of clean wood wastes at very

low cost. The material was blended into the plant’s fuel mix. The onsite wood recycling

center was closed in 1995 when the City of Tracy recycling center began operation.

Plant Flowsheet and Design Information

Tracy Biomass Plant

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condenser

tower pumps

Deaerator Condensate

and

feed pumps Turbine Electricity

generator 18.5 MW

Boiler Steam

 feed

 water Flue gas

Wood

wastes Fuel Stoker Multiclones

blending and boiler and

preparation ESP

 Bottom ash Fly ash Stack Combustion air

Boiler

The Babcock & Wilcox stoker boiler has a Detroit Hydrograte water-cooled vibrating

grate. (See the section on the Camas Cogeneration plant for a discussion of water-cooled

vibrating grates.)

Fuel System

The plant weighmaster records all shipments and obtains a representative sample of each

load, which is used for moisture analysis. The plant has two truck tippers and a typical fuel

yard. Tracy Biomass keeps only about 2-3 weeks fuel inventory on hand. All the fuel

passes through a screen before being conveyed to the boiler. Oversized particles are sent

through a hog.
63

Emissions Control

The plant has multiclone dust collectors and an ESP for particulate control. Ammonia is

injected for NOx control, and NH3 slippage causes a slightly visible plume. Fly ash is

spread on farm fields and on cattle pens adjust pH. Bottom ash is stored at the plant and is

occasionally used as aggregate material in road building and similar applications. The plant

obtains its water supply from deep wells on the property, and is a zero discharge facility

with a cooling tower and an evaporator. The evaporator has been a source of problems for

the operators.

Staffing

The total plant payroll is 21 people.

Fuels

During the early years of operation, Tracy Biomass built up an orchard wood waste service

operation, including two large chippers, a fleet of trucks, and drivers. Workers were able to

pull whole trees from the ground and feed them through a $400,000 chipper, removing 5

to 10 acres of orchard trees per day. They provided excellent service to orchard owners,

helping remove the wood waste from trees and prunings. This was during the high

biomass fuel price era of 1990-1993.

When the ISO4 contract buyouts began in 1994-1995 and biomass fuel prices dropped,

Tracy Biomass discontinued the orchard wood waste service. The prunings are much more

expensive to collect than the whole trees harvested during orchard removals, because the

yield is about 1 t/acre for prunings versus 20-30 t/acre for removals. Tracy Biomass

mostly takes orchard removals as its agricultural fuel now. The cost of this fuel delivered to

the plant is probably about $15-20/dry t.

All fuel is processed offsite by independent wood processing companies and delivered in

clean form. The chips (agricultural fuel) flow easily through the plant feed equipment. The

shredded or tub-ground fuel particles (the urban wood waste) cause more difficulties,

sometimes hanging up and making birds’ nests.

One of Tracy Biomass’ main fuel suppliers is a fuel processing company in Livermore that

charges tipping fees for wood wastes. The wood wastes probably come from throughout

the East Bay Area. The distance from the processor to the Tracy Biomass plant is about 15

mil over the Altamont Pass. The plant pays about $5/t for the urban wood waste from the

processor. The average moisture content is in the low 20% range.

The total fuel consumption by the Tracy Biomass plant is approximately 100,000-120,000

dry t/yr of waste wood (assuming 18.5 MW net output, a heat rate of 13,500-14,000

Btu/kWh, 17 MBtu/dry t of wood, and 7,000-8,000 h of operation per year). Slightly less

than half of the fuel is agricultural fuel; the remainder is urban wood waste.

Operating Experience

Operation has been mostly trouble free. There is enough chlorine in the fuel to have caused

serious chloride corrosion of superheater tubes, which were replaced with stainless steel.
64

Environmental Performance

Tracy is in a nonattainment area; thus, the permitting of any new facility requires some type

of emission reduction or offset. Burning agricultural fuel (this prevents growers from

burning in the field) provides the offset in the Tracy Biomass permit. The plant brochures

and other public relations materials strongly emphasize the environmental benefits of

collecting orchard wastes and burning them in the plant. However, the agricultural fuel is

more expensive than the urban wood waste, and its use would be minimized if not for the

permit requirement.

No mention was made of any difficulties in complying with the plant’s environmental

permit requirements.

Economic Information

Cost information was not disclosed, but a reasonable estimate of the cost of electricity is

5¢/kWh. As discussed earlier, fuel costs are approximately $6/dry t for urban wood wastes

and $15-$20/dry t for agricultural fuel. The overall average is probably about $12/dry t,

which at 13,500-14,000 Btu/kWh is equivalent to about 1¢/kWh. The EPRI BIOPOWER

model estimates O&M costs for an 18.5-MW wood-fired stoker plant to be 2¢/kWh.

Annualized capital costs (construction loan payments), net of the 1.5¢/kWh incentive

payment provided by CEC, are probably about 2¢/kWh.

Tracy Biomass has indicated its intention to pay off its construction loan by the end of the

10-year “high-price” period on its ISO4 PPA. At that time (2000), the plant will have to

begin selling power into California’s competitive power exchange, and will still be eligible

to receive as much as 1.5¢/kWh in transition payments from CEC through 2001. Once the

transition payments are phased out, the cost of electricity from the Tracy Biomass plant

will probably be about 3¢/kWh.

Lessons Learned

Tracy Biomass was not willing to share what it considered to be the most important

lessons learned from 8 years of operating the facility. The plant operations and fuel

managers are proud of the plant and its operating record. The numbers (CF, heat rate, etc.)

are excellent. There is a recognition that none of that would have been possible without the

subsidy provided during the first 10 years of the ISO4 contract, and there is a real concern

about the fate of the project after year 10.

Lessons that can be inferred from the information about the Tracy Biomass project include:

• Urban wood waste can be a comparatively inexpensive fuel (~$0.35/MBtu) if the

plant is located close to the urban area. Setting up a tipping fee fuel processing yard

at the plant and reducing the cost of much of the urban wood waste fuel to $0/MBtu

or less should be possible.

• Compared to urban wood waste, orchard wood is a relatively expensive fuel

because growers are used to simply pushing and burning it, and are generally not

willing to pay a fee to have the wood removed. Tracy Biomass spends

approximately $1/MBtu for fuel from orchard removals.
65

Sources and Contacts

Most of the information in this section was obtained during a plant tour conducted by

Andy Carlin, fuel manager, and Brian Pillittere, plant operations superintendent, on July

16, 1998. Information was available from articles about Tracy Biomass in the Stanislaus

Farm News and the Biomass Processors Association newsletter.

Brian K. Pillittere

Plant Operations Superintendent

Tracy Operators

P.O. Box 1209

Tracy, CA 95378-1209

Phone: 209-835-6914

Fax: 209-835-6918
66

CITY OF TACOMA STEAM PLANT NO. 2,

TACOMA, WASHINGTON

________________________________________________________________________

Tacoma Steam Plant No. 2 is a multifueled generating facility located on an urban site in

the tideflats industrial area of Tacoma, Washington. The plant was originally built in 1931

and was repowered during the late 1980s with FBC to cofire wood, RDF, and coal. The

repowered plant started commercial operation in August 1991. The plant is owned and

operated by Tacoma Public Utilities, a municipal utility that provides water, electric, and

rail service. On April 22, 1998 the Steam Plant was placed into reserve shutdown, and on

June 15, 1988 the utility issued a request for qualifications for organizations to submit

ideas and concepts about the possible acquisition or lease of Steam Plant No. 2 facilities

and some adjacent properties.

Vital Statistics

Design capacity, net MWe ~40 (see discussion below)

Configuration 2 bubbling FBC boilers

1995 1996 1997

Fuels, % by heat input: Wood 54 60 68

RDF 14 20 20

Coal 32 20 12

Net heat rate, Btu/kWh 17,252 19,955 24,426

Thermal efficiency, HHV, % 19.8 17.1 14.0

Net generation, MWh/yr 91,688 94,083 88,488

The Steam Plant’s two turbine generators have a total rated capacity of 50 MWe (gross).

However, the capabilities of the combustion and ash removal systems constrain the plant’s

maximum output to 30-40 MW, depending on the fuel blend. In brief tests, the plant has

operated at levels as high as 42 MW. During normal operations, the highest net output

from the plant has been about 18.5 MW, running one combustor and one

turbine/generator. The supply of RDF, the demand for power, and prices available in the

secondary energy market have determined operating levels at the plant. During 1997 and

1998, the price of electric energy in the Tacoma market was generally less than 1¢/kWh. A

biomass/waste-fueled plant cannot produce power at these low prices unless the fuels

command substantial tipping fees. Steam Plant No. 2 operated only as much as necessary

to burn the RDF it received—resulting in net generation rates of about 11-13 MW from

1994 to 1997. The plant has burned, on average, about 60% wood, 20% RDF, and 20%

coal.
67

History and Outlook

Steam Plant No. 2 was originally built in 1931 as a 25-MW coal-fired steam-generating

facility (later modified to burn oil and expanded to 50 MW) to supplement the area’s

hydroelectric power supply during low-water years. It was removed from service in 1973

because of problems with the superheaters and the capital expenditures necessary to bring

the plant into full environmental compliance. At the time, it had logged less than 1 year of

cumulative operation.

A feasibility study conducted in 1974 concluded that it would not be economical to

refurbish the plant for continued peaking or baseload service. A 1979 plan to convert the

facility into a cogeneration plant looked promising, but was halted because local industries

would not commit to long-term steam contracts.

In 1984, EPI approached the City with a proposal to lease Steam Plant No. 2, refurbish and

operate the facility, and sell power to Tacoma Power. Because of legal technicalities, the

project could not be conducted with private ownership, but it looked attractive to Tacoma

Power. After a feasibility study and several months of negotiations, the City took over the

project in the spring of 1986.

In 1986, the City of Tacoma applied for and was awarded a $15 million matching grant

from the Washington State Department of Ecology. The grant was used both by Tacoma

Power to repower Steam Plant No. 2 and by the local refuse utility to modify its resource

recovery facility to produce RDF. Moorhead Machinery & Boiler Company, a subsidiary

of Westinghouse Electric Corporation, was selected to complete the design and

construction. The total cost to the renovate Steam Plant No. 2 was approximately $45

million.

Startup testing began in December 1989 and was running on all three fuels by April 1990.

Acceptance testing was performed starting in May 1990. Commercial operation began

August 1, 1991. Power Magazine (April 1991), in awarding Steam Plant No. 2 its 1991

Powerplant Award, stated that “the major goal of the repowering project is to generate as

much power as possible—or as dictated by electric demands—at the lowest cost, while

combusting all of the city’s 300 tons/day of refuse-derived fuel (RDF).” As it turned out,

the amount of RDF delivered by the city’s Refuse Utility and burned by Steam Plant No. 2

from 1993 through 1997 ranged from 28,539 to 48,412 t/yr, or about 78 to 133 t/d.

Several design and mechanical problems were solved between 1991 and 1994, and a

reliable mode of operation was established, which involved running one combustor at a

time while the other was maintained on standby. From 1994 through 1997, net plant output

was equivalent to about 11-13 MW, with an onstream factor of about 86%-87%. Plant

availability (to operate one combustor at a time and consume RDF) was maintained in the

90%-96% range. Initially, the cost of power from the plant was competitive within the

utility’s system, but dramatic drops in market prices for electricity made the plant

uneconomical. Fuel costs decreased significantly in 1997, and a plan was developed to

convert the plant to a tipping fee facility that would generate net revenues from most or all

of its fuels. Implementation of this plan required modifications to the plant’s air quality

permit, which were underway when Tacoma Public Utilities put the plant on reserve

shutdown in 1998. The future of the plant depends on the outcome of negotiations with the

successful bidder, on the operating and business strategy pursued by the new owner, on
68

alternative disposal options for Municipal Solid Waste, and on developments in electricity

and fuel markets.

Plant Flowsheet and Design Information

 

The repowering project consisted of installing two bubbling atmospheric FBCs, four

refractory-lined cyclones that allow ash and unspent limestone to be reinjected into the

combustors, and ductwork that connects the combustors to the boilers, which were

converted to heat recovery steam generators (HRSGs). In addition, a mechanical draft

cooling tower to replace salt water from the Hylebos waterway for steam condensing, fuel

handling, pollution control and ash handling equipment, and a continuous emissions

monitoring and computerized distributed control system were installed.

Combustors

The bubbling FBCs provided by EPI were designed to cofire a combination of wood

waste, coal, and RDF. The design values were 15% RDF, 35% wood, and 50% coal. The

combustors can fire 0%-100% wood, 0%-50% coal, and 0%-50% RDF (permit

limitation). The fuel mix is fed to the FBCs overbed and limestone is added directly to the

beds for SO2 absorption. Bed temperatures are maintained at approximately 1550°F to

minimize ash agglomeration and maximize sulfur capture. The combustors are designed

for a total fuel input of 831 MBtu/h, which corresponds (at full rated net output of 50 MW)

to a net plant heat rate of about 16,620 Btu/kWh. The permit limitation is 718 MBtu/h.

Combustion air is provided by 1500 hp FD fans directly to the fluidizing air manifold of

each combustor, with no air preheat.

Refractory-lined cyclones (two per combustor) installed between the combustors and the

HRSGs capture ash and unspent limestone for reinjection into the combustors. The

refractory-lined cyclones are 18 ft in diameter and capture PM larger than 30 . Reinjection

Tacoma Steam Plant

Evaporate

Water Water

Cooling Cooling water Condensers

tower pumps (2)

 ~~

Steam

Steam HRSGs Steam Turbine

separators (2) Water (Old boilers) generators 50 MWe

(2) 750F (2)

RDF Steam/ Water ~1,650F 400 psig

water BFW ~~

Flue Cyclones Flue gas Condensate

Wood Fuel Bubbling bed gas (2) Flue gas

preparation combustors Economizers BFW Deaerators &

& storage (2) Ash (2) feed pumps

 Flue gas Trona

Coal (HCl scrubbing)

Bed material Lime feed Fabric filters ID fans

Air FD fans separators (2) systems (2) (2) (2)

(2) Stack

 Tramp Fines Lime Fly ash

 or limestone

μ
69

ensures complete combustion, reduces the amount of fly ash to be removed downstream

by the plant’s fabric filters, and enhances limestone use. The reinjection system was

disabled soon after startup because of excessive wear problems. As a result, lime has been

used instead of limestone for SO2 control. (Lime is more expensive than limestone.)

The combustor operation most closely resembles a bubbling bed process, although the

combustion air flow is great enough to carry some limestone and smaller unburned fuel

particles from the combustion unit into the cyclone separators, somewhat like a circulating

FBC process. The configuration of the combustors relative to the HRSGs gives at least 5 s

of residence time for the flue gas at temperatures of approximately 1600°F.

Heat Recovery Steam Generators

The boilers were converted to HRSGs by removing the burners and installing steam

separation equipment, external superheaters, and economizers. Refractory ducting conveys

the flue gas from the combustors through the cyclones to the waste heat boilers. The

superheaters are mounted in the hot gas ductwork just ahead of the boiler fronts. This

configuration allowed the superheaters to be shop fabricated and located in a very hot

section of the flue gas stream (where the temperature is generally higher than 1650°F). The

superheaters employ bare, horizontal tubes with vertical headers, allowing full drainage of

the units.

Steam Generation

In the forced circulation feedwater loop, water is taken from the front boiler drum by

gravity flow to a new steam separator tank next to each combustor. Each tank provides

suction for two 50%-capacity pumps that circulate the water through the combustors’ heat

removal tubes. These tubes help maintain desired bed temperatures and evaporate

approximately 60% of the feedwater.

The water/steam mixture from the combustors returns to the separator tanks where water is

fed back to the circulation loop; steam continues to the front drum of the boiler. The steam

is then directed through each boiler’s rear drum and into the external superheaters. Final

steam conditions are 750°F and 400 psig. Either combustor-boiler combination can supply

steam to drive either steam turbine.

Ash and Tramp Material Removal

Fly ash is collected from the fabric filters and pneumatically conveyed to a silo that stores

900 t or approximately 7 d of production at maximum generation levels. Ash is also

collected from the hot cyclone separators, HRSGs, and economizers. The ash is discharged

from the silo through a conditioner into trucks for transport.

Each FBC is equipped with a system to continuously remove undesirable (tramp) material

from the bed media. The system allows bed media to flow from the cones making up the

bottom section of each combustor (eight cones per combustor) through timed slide gates

onto a divided vibrating pan conveyor. The vibrating pan conveyor is divided into two

layers by a screen. As the bed media travels along the conveyor, the smaller particles pass

through the screen and are transported to a bucket elevator for recycle into the combustor.

The larger material that does not pass through the screen is composed primarily of glass,

metal, rocks, and agglomerated bed media.
70

Fuel System

Wood and RDF are delivered to a covered storage building by truck. These fuels are

reclaimed from the storage building by ladder-type chain reclaimers and deposited on a

dragchain conveyor. The conveyor deposits the wood/RDF mixture onto a belt conveyor

for transfer to the fuel metering system. In addition, some wood is stockpiled in a nearby

storage area. This area was designed as a full-scale ash demonstration project using fly ash

and lime as a sub-base stabilizer for an asphalt application.

Wood fuel suppliers weigh in and out through an automated scale system and deposit their

loads into a single truck dumper. The hog fuel passes over a disk screen and the overs that

accumulate are resized by the Solid Waste Utility at no cost to the Steam Plant. The fuel is

conveyed to one of five bays in the fuel building or deposits at an overflow bay at the end

of the building. Normally, fresh wood is deposited at the overflow area and is stacked by

loader on a current pile being built. The fuel handler also reclaims the wood and stages it

under one of the reclaimers in the fuel house. Typically, Bays 4 and 5 are used for RDF.

A mix of wood and RDF is forwarded to the metering system on a belt conveyor. This

mix passes under an electromagnet and over a magnetic head pulley to capture ferrous

materials. The ratio of wood to RDF is established in the fuel house by gates over the

dragchain that delivers fuel to the forwarding belt. The wood/RDF metering system was

replaced with a totally redesigned auger system that can feed and meter a wide range of

wood, RDF, and mixed fuels. This system can feed and meter almost any sized material

smaller than 6 in., and has been successfully tested with coarser RDF in the wood-RDF

mix. Key factors in the success of the wood/RDF metering system include:

Coal is delivered to the plant by self-unloading barges or trucks. The barges are moored in

the Hylebos Waterway where they transfer their contents to a series of belt conveyors that

place the coal in a storage pile. The coal is then moved from the storage pile by a wheel

loader to a reclaimer that feeds a series of belt conveyors. The conveyors transport the coal

into the day bunker in the boiler building where it is then forwarded to the combustor fuel

metering system. The coal feed system was also replaced with auger feed equipment. The

10-in. standard AR augers are driven by 5-hp motors with a Woods inverter electronic

drive. The turndown is limited by low-speed torque needs, but the fluidized bed system

allows use of one, two, or three feeds as needed to achieve low-end performance.

Emissions Control

Granular limestone is injected into the FBCs to control SO2 emissions. The limestone

handling system consists of a silo, where truck deliveries are accepted; a variable-speed

dragchain conveyor that delivers the limestone to a flow splitter at the combustors; and a

bucket conveyor that carries the limestone into the combustors.

• Negative slope bin with minimal surface discontinuities

• Large (28-in. outside diameter) augers with continuously varying pitch

• Large (20-in. square) discharge chutes

• Hydraulic drive for infinite control and full torque at low feed

• All stainless construction (except for AR flighting of augers)
71

Two fabric filters, one for each flue gas exhaust train, control particulate emissions. Each

baghouse has 1920 6-in. diameter by 14-ft long fiberglass bags. The filters are designed to

remove 99.8% of the PM from the flue gas. Two 600-hp ID fans direct the two flue gas

streams to a common 213-ft tall stack.

In 1997, an alkali sorbent injection system was installed upstream of the baghouses to

remove trace amounts of hydrochloric acid (HCl) from the flue gas. The scrubber uses

trona (sodium sesquicarbonate) to react with the chlorine to form sodium chloride (table

salt), which is removed along with the fly ash in the fabric filters. The chlorine originates

primarily from plastics and other chlorine-containing materials in the RDF. Uncontrolled

HCl emissions were typically about 260 PPM in the flue gas; with lime and trona injection,

HCl emissions drop to about 19 ppm. Overall HCl removal efficiency averages about

93%.

Plant Control

The plant is controlled by a DCS supplied by Westinghouse Electric Corporation. Control

is accomplished through the combination of local programmable logic controllers (PLCs)

and direct connection of the DCS central computer to the process. All systems critical to

the immediate operation of the plant are automated through the DCS and are under the

control of the operator. Stand-alone systems such as ash handling are controlled by PLCs,

with monitoring and limited operational control from the DCS.

Staffing

During plant operation, Steam Plant No. 2 is staffed with a crew of three, working 12-hour

shifts per day. The crew consists of a control room operator, a roving auxiliary operator,

and a fuel handler. Additionally, during normal business hours the plant is staffed with a

manager, assistant manager, office assistant, relief control room operator, auxiliary

operator and fuel handler, electrician, mechanic, and two engineers. The total staff on site

during normal business hours is approximately 21 employees.

Fuels

As shown in the table on p. 82, the largest contributor to the fuel mix on a heat input basis

has been waste wood (54%-68% from 1993 to1997). Coal, the most expensive fuel used,

accounted for 27%-32% of the total from 1993 to 1995, but its use was reduced to 12% in

1997 as cost reduction became paramount. RDF, the zero-cost, “must-burn” fuel,

accounted for 12%-20% of the total heat input to the plant from 1993 to 1997.

Waste Wood

From 1993 to 1996, all the waste wood for the plant was purchased on the spot market

from about 100 authorized suppliers. About 64% of the wood fuel was from mill and

logging sources, 23% from land clearing, and the remaining 13% from urban and

industrial wastes. Moisture content was 22%-55%. The annual average price paid by the

plant for wood waste was $0.72/Mbtu-$0.88/MBtu from 1993 to 1996. Wood waste

prices tend to increase significantly during the winter.

Beginning in 1997 a concerted effort was made to obtain lower-cost wood fuel, resulting in

an annual average price of $0.28/MBtu. In 1997, approximately 65 active vendors supplied

waste wood to the plant on a spot market or tipping fee basis. Storm debris in February
72

and land clearing wood from May through October were obtained at zero or nearly zero

cost. The reduction in the cost of wood and in the amount of coal burned (which cost more

than $1.70/MBtu), reduced the plant’s fuel bill by more than $600,000 from 1996 to 1997.

RDF

The City of Tacoma Refuse Utility delivers RDF at no cost to the Steam Plant. After sorted

residential garbage reaches the Tacoma Resource Recovery Facility, it is shredded, air

classified (separated by density), and mechanically separated. The mechanical separation

steps include a drum magnet that separates ferrous metals, a primary disk screen that sends

oversized material (ROF) through a secondary shredder back to the feed point, and sends

undersized material (grit) to a secondary disk screen that discharges grit to be landfilled,

and RDF to a compactor that feeds the compacted RDF to trucks that carry it to the Steam

Plant. Ferrous metals are recycled; light plastics, paper, and wood are compacted into RDF.

Year 1993 1994 1995 1996 1997

Fuel burned, t/yr:

 Wood 175,806 118,511 87,949 118,997 162,900

 RDF 48,412 32,812 28,539 42,188 39,540

 Coal 39,563 33,262 25,539 19,373 13,295

Fuel HHV, Btu/lb:

 Wood 4,929 4,929 4,833 4,730 4,521

 RDF 4,546 3,918 3,886 4,556 5,361

 Coal 9,907 9,875 9,983 9,480 9,948

Fuel burned, MBtu/yr:

 Wood 1,733,096 1,168,281 850,115 1,125,712 1,472,942

 RDF 440,162 257,115 221,805 384,417 423,948

 Coal 783,901 656,925 509,912 367,312 264,517

 Total 2,957,159 2,082,321 1,581,832 1,877,441 2,161,407

Fuel burned, % by heat:

 Wood 59 56 54 60 68

 RDF 15 12 14 20 20

 Coal 27 32 32 20 12

Fuel prices, $/t:

 Wood 8.52 8.68 7.00 7.19 2.53 RDF 0.00 0.00 0.00 0.00 0.00

 Coal 35.61 33.88 33.50 34.03 34.42

Fuel cost, $/yr: Wood 1,497,867 1,028,675 615,643 855,588 412,424

 RDF 0 0 0 0 0

 Coal 1,408,838 1,126,917 855,557 659,263 457,615

 Total 2,906,706 2,155,592 1,471,200 1,514,852 870,039

Fuel cost, $/MBtu:

 Wood 0.86 0.88 0.72 0.76 0.28

 RDF 0.00 0.00 0.00 0.00 0.00

 Coal 1.80 1.72 1.68 1.79 1.73

 Total 0.98 1.04 0.93 0.81 0.40

Gross generation, MWh/yr 160,311 120,274 113,290 114,557 109,881

Net generation, MWh/yr 130,253 97,091 91,688 94,083 88,488

Fuel cost, ¢/kWh 2.2 2.2 1.6 1.6 1.0

Net heat rate, Btu/kWh 22,703 21,447 17,252 19,955 24,426

Thermal efficiency, % 15.0 15.9 19.8 17.1 14.0
73

Any newspaper that is not separated at drop-off recycling sites becomes part of the RDF.

A small portion of the city’s yard waste ends up in the RDF as well, but most goes to a

private topsoil firm for recycling. There is a separate drop-off center at the landfill for

batteries, and crews on the tipping scales, tipping floor, and curbside are trained to separate

out household batteries. The noncombustible portion of the garbage processed at the

resource recovery facility is landfilled.

In a memorandum of understanding between the Solid Waste Utility and Tacoma Public

Utilities, the Solid Waste Utility committed to producing and delivering to Steam Plant No.

2, at its sole expense, 100-350 t/d of RDF conforming to the fuel specification in the

agreement. Tacoma Public Utilities committed to receive, store, and incinerate the RDF at

its sole expense. This arrangement is open to renegotiation for future owner/operators of

Steam Plant No. 2. In 1997, Steam Plant No. 2 burned 39,540 t of RDF at an average rate

of 125 t/d. (Weekday deliveries averaged 150 t/d.) The Solid Waste Utility has indicated

that it would like to increase RDF production.

Combustion of RDF is currently limited to 30% by weight as stated in the Puget Sound

Air Pollution Control Authority (PSAPCA) Notice of Construction issued January 27,

1998. This restriction allows the plant to operate as a cofired combustor and avoid

compliance under the Municipal Waste Combustor rules (Subpart Cb of 40 CFR 60).

Coal

Obed coal from Oxbow Carbon & Minerals, Inc., Canada, and Decker Coal from Kiewit

Mining in Wyoming have generally been the lowest-cost coals available to the plant that

met the PSD (air quality) permit requirement of less than 0.8% sulfur. The Obed coal is

shipped by barge. The Decker coal is transported by rail to a nearby rail unloading facility,

where it is transloaded onto trucks and delivered to the plant.

Natural Gas and Fuel Oil

Natural gas and fuel oil are used during startup. These fuels accounted for less than 1% of

the total fuel consumption, and are not included in the fuel consumption figures shown in

the table. Each combustor has two 50-MBtu/h above-bed gas burners that operate during

startup until the flue gas temperature is raised sufficiently to allow the baghouse to be put

into service. Each combustor also has a 10-MBtu/h distillate fuel oil burner located in the

air supply plenum, which is used to heat the fluidized bed during startup.

Opportunity Fuels

The FBCs can burn a wide variety of fuels. Finding more opportunity fuels that command

a tipping fee or can be obtained free became a high priority in 1997. The plant had received

some wood for free, usually during winter and early spring as a result of major storms.

Cities and counties paid the cost of collecting, processing, and delivering the storm debris

to the plant, which was less expensive to them than landfilling. Analysis showed that by

setting up a wood processing yard on site instead of buying prepared wood fuel from

wood processors, the plant would be able to charge fees of about $15-$25/t for stumps,

tree wastes, and other wood wastes. The cost of grinding these materials on site would be

about $5-$15/t. Wood processing yards in the area charge tipping fees for these types of

wood wastes of $31-$46/t.
74

In addition, the utility investigated the possible use of a variety of industrial wastes, such as

asphalt roofing shingles (tear-offs), wood laminates, on/off-specification oil, oil sludges,

oil-contaminated sorbents and rags, textile and plastic waste, green petroleum coke,

nonrecyclable paper waste, and pulp mill clarifier solids that could generate revenues if they

were acceptable fuels. Tipping fees for some of these items are $80-100/t, and transport

distances to facilities that accept them are longer than 100 mi. Burning some of these

petroleum-based waste fuels might allow the plant to operate with no coal in its fuel mix.

Technically, the bubbling FBCs and environmental control systems at the plant could

probably handle any of these fuels. From 1997 to 1998, Tacoma Public Utilities acquired

permits and developed a test burn plan for many of these fuels. The permits allow a 180-d

period to burn the various fuels and conduct all necessary testing and monitoring to

determine operational constraints required to assure compliance with current regulations.

By eliminating coal and replacing most or all the purchased wood with tipping fee wastes,

the plant’s annual fuel cost, which in 1997 was still almost $870,000/yr or 1.0¢/kWh,

could be converted to a net revenue stream of at least that amount, and possibly more.

Operating Experience

Significant improvements have been made to the fuel feed, combustion, and control

systems since 1991. The plant has demonstrated successful operation on a wide variety of

fuel mixes, including wood only, wood and RDF, coal and RDF, wood and coal, and

varying combinations of all three fuels. Major factors that negatively affected power

production and availability during early operations were:

• Shutdowns to remove wire from the combustors. Wire comes in the RDF and

hangs up on the air manifolds, forming large nests that impede air flow in the

combustor.

• A slagging condition in the combustor and cyclones that increases with increased

firing rate and vapor temperatures.

• A fuel feed and metering system that delivered fuel to the combustor in an erratic

manner. This fuel feed system was replaced in the fall of 1994.

• Insufficient heat transfer surface in the fluidized bed. More surface was added to

increase the steam production capability.

Fuel consumption, electricity generation, and plant efficiency data from 1993 through 1997

are shown in the table on page 82. Basically, the plant was run at the rate needed to

consume all the RDF delivered. From 1994 to 1997, the net generation was 88,000-97,000

MWh/yr, which is equivalent to production of 11-12 MW during the 7,500-7,700 h/yr that

the plant operated. About 12%-20% of the heat input was provided by the RDF, and the

remainder by wood and coal, as required by the plant’s air quality permit conditions and

operating considerations.

Usually, one FBC unit operated while the other received maintenance or sat in standby

condition. After 2-3 months of operation, the operating unit was shut down for inspection

and maintenance and the other unit was started up. In 1997, for example, unit 1 operated

4127 h and unit 2 operated 3535 h, giving a total plant operating time of 7662 h, or 87.5%

of the 8760 h that year. Plant availability (operating one combustor at a time, to consume

RDF) was 95.8% in 1995, 92.4% in 1996, and 93.4% in 1997.
75

Because of the plant’s unique (retrofitted) design and low steam temperature and pressure,

the thermal efficiency of Steam Plant No. 2 is relatively low. As the table on page 82

shows, the net plant heat rate increased from 17,252 Btu/kWh in 1995 to 24,426 Btu/kWh

in 1997 as the percentage of coal in the fuel mix decreased from 32% to 12% by heat input.

The heat rate would improve if the plant were run closer to its design output. If the

development of an on-site fuel processing capability produced a net revenue stream from

tipping fee fuels, improving the plant’s thermal efficiency would not be an important

consideration.

The auxiliary power requirements of Steam Plant No. 2 (the difference between gross and

net generation) are also relatively high, at about 18%-20% of the gross MWh/yr. This is

also explained by the unique plant design and by the low CF at which the plant has

operated.

Environmental Performance

Steam Plant No. 2 has met or operated significantly below all required state, federal, and

local air emission requirements. Fluidized bed combustion with limestone injection results

in very low SO2 and NOx emissions. The fabric filters remove 99.8% of the PM from the

flue gas stream. A continuous emissions monitoring system measures SO2 , NOx , CO, and

O2 levels in the exiting flue gas. Opacity is measured and roughly indicates particulate

concentration. In 1997 an alkali sorbent injection system was added upstream of the

baghouses to remove HCl from the flue gas. Operation of this unit has been successful,

with greater than 90% HCl removal.

The permitted emissions, with the control method used, are as follows:

• SO2—0.18 lb/MBtu 30-d rolling average or at least 70% control. Control—Lime or

limestone injection and the use of a low (0.8% or less) sulfur coal.

• NOx—0.50 lb/MBtu (hourly average). Control—Maintain temperature in

combustion zone at 1450-1550°F.

• CO—0.52 lb/MBtu or 425 ppm (hourly average). Control—Proper combustion

control, 5-s residence time.

• Opacity—10% for an aggregate of more than 3 min in any 60-min period; 5%

hourly average. Control—Baghouse.

• Particulate matter—0.010 gr/sdcf of flue gas, corrected to 7% O2 total catch, 0.0068

gr/dscf front half catch (first test indicates 0.004 gdscf actual). Control—Baghouse

with Ryton filter bags.

Nearly all the plant’s generation by-products (fly ash, aggregate, and tramp residues) are

recycled. An extensive 3-year ash testing program culminated in April 1994 when Tacoma

received a Certificate of Designation from the Washington State Department of Ecology

certifying Steam Plant No. 2 fly ash as a solid waste under federal and Washington State

laws. Most of the ash is used for waste stabilization of oily sludges; some is sent to a

cement manufacturing facility in Seattle where it displaces clay in the cement

manufacturing process. Some is being used as a soil amendment in mine reclamation

efforts. The tramp, or bottom ash material, is separated and the aggregate portion used as a

road base material. The metals are sold to a recycling facility and the remaining tramp,

consisting mostly of glass, wire, plastic, and clinkers, is then landfilled.
76

During the last 5 years of operation, the ash generated has averaged 14,000 t/yr. More than

98% of the ash generated in 1997 was supplied to users at an average cost to the utility of

about $3/t. During 1997, 242 were landfilled at a cost of about $36/t.

Economic Information

The total cost to renovate Steam Plant No. 2 was approximately $45 million, partially

funded by a $15 million grant from the Washington State Department of Ecology. In

1993, the variable cost of power from the plant averaged about 4¢/kWh, 2.2¢ of which

were fuel costs. At that time, this 4¢/kWh cost was lower than the costs of power from

other potential resources that were being considered for development by Tacoma Public

Utilities. It also favorably offset the purchase of outside power from the Bonneville Power

Administration. The situation had changed by 1996-1997, however. Although the plant’s

fuel cost had been reduced to 1.6¢/kWh in 1996 and 1.1¢/kWh in 1997 (annual averages),

and the variable cost of power from the plant was in the 1.5-3¢/kWh range, the energy

market in the Pacific Northwest had dropped to about 0.5¢/kWh (off peak) and 0.7-

0.8¢/kWh (on peak).

In early 1998 Tacoma Public Utilities was operating Steam Plant No. 2 at an estimated loss

of about $3 million/yr. The Solid Waste Utility was benefiting from the combustion of

RDF by about $1 million/yr, so the city-wide loss was about $2 million/yr. Work was

proceeding on the modification of the plant permits to allow onsite processing and

combustion of tipping fee fuels, which would allow the plant to eliminate the loss at some

point in the future. In April 1998, Tacoma Public Utilities put the plant up for sale.

Lessons Learned

Plant personnel suggested the following lessons learned from their experience at Tacoma

Steam Plant No. 2:

Fuel

• Fuel, fuel, fuel to a biomass/waste fueled power plant is like location, location,

location to a realtor. Don’t box the facility in with a limited fuel supply and/or

permit. The more options the better.

• Fuel procurement should be one of the highest priorities and a full-time job.

• Obtain a low-cost fuel supply in sufficient quantities to maximize generation.

• Focus on fuel cost (¢/kWh) rather than fuels that provide highest efficiency

(Btu/kWh) saved the plant $600,000/yr in coal costs. Opportunity fuels (with

tipping fees) have the potential to eliminate fuel costs and generate net revenues.

• Carefully evaluate the real costs of zero cost or tipping fee fuels. There are always

costs associated with fuel preparation and combustion that the plant must absorb.

• RDF fuel quality—elimination of aluminum and copper wire from RDF would

make this a more acceptable fuel. These elements significantly contribute to bed

fouling and slagging, which cause frequent plant shutdowns. The elemental

aluminum in the fly ash decreases its marketability. If the RDF were denser, the

plant efficiency would improve because of combustion in the bed rather than in the

vapor space. Acid gases from chlorine in the RDF require additional sorbent

expense and an injection system.
77

Fuel Feed System

• Take extra care at the beginning of the project with design of the fuel feed system.

Go with a proven fuel feed system; don’t let someone sell you an unproven feed

system.

• Make certain that fuel quantity can be accurately measured. Because wood and

RDF are transported to the combustor on one conveyor and commingled, Tacoma

cannot accurately measure the quantity of each delivered to the combustor. These

measurements are of obvious importance in recording heat rate and economics.

Redundancy and overall control of the process is sacrificed.

Plant Design

• Fuel flexibility - when developing combustor design and environmental permits for

a new plant, this should be one of the highest priorities. A CFB or increased height

on the combustors would have been more appropriate to eliminate slagging

problems.

• Design the plant for worst-case scenario fuels and for easy clean out. The Tacoma

plant needs a sand storage system that cleans, stores, and transports bed media

during the combustion cleanup process with minimum manpower.

• Expect fouling (especially with RDF in the fuel mix). Design the facility for easy

cleanup and perhaps with on line cleaning ability to minimize down time. A

preventative maintenance program is essential.

Operation

• Develop and follow standard operating procedures that eliminate operator variables

and give more consistency in operations. This avoids seesaw operations that

shorten run time. It also helps identify problems quickly. If the procedure is not

working it can be more easily identified and corrected.

• Multitasking of labor - train and assign personnel to do more than one job.

• Focus on preventative maintenance to reduce operating costs.

Ash Marketing

• Ash marketing/sales rather than disposal saved the plant $600,000/yr.

• Design the ash handling system to optimize ash as a product. That might mean that

the ash system drops out and stores ash at different locations for different

applications and better marketability.

• Research ash markets and determine just what the plant will be producing with each

anticipated fuel mix combination; then market it. Landfilling ash should be the last

resort.
78

Sources and Contacts

Much of the descriptive information in this report section was obtained from the following

published sources:

• Power Magazine , April 1991. “Bubbling Bed Combustors Achieve True Cofiring

of RDF, Wood, Coal.”

• Independent Energy (reprint not dated). “Fluidized Bed for Resource Recovery,”

by Patrick McCarty, P.E., Tacoma City Light and Thair Jorgenson, P.E., Tacoma

Refuse Utility.

• Proceedings: Strategic Benefits of Biomass and Waste Fuels. Electric Power

Research Institute (EPRI) TR-103146, December 1993. “RDF/Wood/Coal

Cofiring at Tacoma City Light Steam Plant No. 2,” by Mark B. Gamble.

• Request for Qualifications for Steam Plant No. 2 Business Opportunities, Tacoma

Public Utilities, June 15, 1998.

Mark Gamble was the Steam Plant manager from startup through September 1997, when

he left to become plant manager of a large fluidized bed project in Thailand. Laurie Hannan

was assistant plant manager until September 1997, when she was promoted to plant

manager. Dan Rottler, P.E., was plant engineer since February 1995. These people were

very generous with their time, and helpful in providing information and reviewing this

report section.

Contact information:

Tacoma Public Utilities

Steam Plant No. 2

1171 Taylor Way

P.O. Box 11007

Tacoma, WA 98411-0007

Laurie Hannan, Plant Manager phone: 253-502-8601

e-mail: lhannan@ci.tacoma.wa.us

Dan Rottler, P.E., Mechanical Engineer phone: 253-502-8605

e-mail: drottler@ci.tacoma.wa.us

Fax 253-502-8607
79

COLMAC ENERGY, MECCA, CALIFORNIA

________________________________________________________________________

Colmac Energy operates a 49-MW wood-fired power plant in Mecca, California (southeast

of Palm Springs in Riverside County). The plant has two circulating FBC boilers. The

permit conditions, established and monitored by the South Coast Air Quality Management

Board, are among the most stringent of any biomass power plant in the United States. The

plant runs very well and has operated at a net plant heat rate as low as 12,200 Btu/kWh

(thermal efficiency of 28.0%, HHV basis). The annual CF from 1995 to 1998 was 85%-

92%.

Vital Statistics

Design capacity, net MWe ~49 (see discussion below)

Configuration 2 circulating FBC boilers

Fuels: Urban wood wastes

Agricultural wood wastes

Petroleum coke

Year 1995 1996 1997 1998*

Net generation, MWh/year 368,000 395,000 382,000 393,000

Annual CF, % 85.8 92.1 89.0 91.6

Net heat rate, Btu/kWh 12,400-12,200

Thermal efficiency, HHV, % 27.5-28.0

 *Projected in August 1998.

Early documentation on the plant describes it as a 47-MW (net) facility. A Power

Magazine article (April 1992) says the turbine/generator is a nominal 47 MW unit. The

plant manager says the net capacity is 49 MW. A Colmac Energy brochure advertising

mobile grinding services describes the plant as a 49.9-MW facility.

History and Outlook

Colmac Energy is a privately owned subsidiary of Access Capital International. The plant

is located at the southern end of the Coachella Valley, on land leased from the Cabazon

band of Mission Indians in Riverside County. This is an arid region with mean monthly

temperatures of 31°-107°F and annual rainfalls of only 2.8 in. Phillip Reese of ReeseChambers Systems Consultants, Inc. (which permitted the development of 13 of the

California biomass plants) served as manager of project development and environmental

coordinator, and is now a director of Colmac Energy. Walsh Construction built the plant

under an engineering procurement contract with Colmac Energy. Following a 6-year

design, development, and permitting process, Colmac Energy started up in October 1991,

and entered full commercial operation in February 1992. Southern California Edison buys
80

45 MW of capacity and energy under an ISO4 contract. The 10-year high-priced period

runs until February 2002. Colmac is the newest of the ISO4 biomass plants in California.

Contract Buyout

On February 1, 1999, the following article appeared in “California Energy Markets:”

Southern California Edison recently filed an application for termination of a

power purchase contract with the 45 MW Colmac Energy biomass plant,

near Mecca in the Imperial Valley [A98-12-038]. Edison will pay Colmac

$127 million to terminate the contract, claiming the deal will result in

ratepayer savings of between $30.9 million and $58.8 million (net present

value) compared to contract prices.

The QF plant, which has been in operation since 1992, carries a 30-year

Standard Offer No. 4 contract that pays the independent producer

$198/KW-yr for capacity and forecasted avoided-cost rates for energy

deliveries during the first ten years of operations. The 1998 energy price

was listed at $0.146/KWh and would rise to $0.156/KWh by the end of

tenth year--in February 2002--before falling to Edison's short-run avoided

cost (SRAC) rate for the remaining 20 years of the contract. By that time,

however, SRAC is expected to revert to the Power Exchange clearing price.

The unit also is eligible for capacity bonus payments if it exceeds a CF of

85 percent during certain peak demand periods.

The Colmac unit has a long regulatory history. The SO4 contract was

originally signed in 1985 with the expectation of starting operations in 1987,

but Colmac later wanted to move the unit's location to land owned by the

Cabazon Indian Tribe and to defer its start-date. Though the utility did not

want to do that, Colmac won a 1989 California Public Utilities Commission

decision ordering Edison to accept the site change and deferral [D89-04-

081].

After some operational problems during start-up, the facility managed an

average CF of 85.5 percent. During 1995 the owner performed major

modifications to components of the combustion system and there was an

extended outage in April 1998 that required operators to install new boiler

equipment. According to the filing, the unit has achieved "record

production" since. During 1996 and 1997 the Colmac plant generated more

than 350 GWh of energy each year.

An independent consultant hired by Edison to verify the project's viability in

order to qualify for a contract restructuring concluded that the plant is

currently viable. It may be expected to continue operations for the duration

of its contract and is able to obtain economic and abundant fuel supplies for

the rest of its planned operating life, according to the consultant.
81

Greg Lawyer, president of Colmac Energy, declined to offer specifics of the

deal, citing a confidentiality agreement with Edison. He did say, however,

that the arrangement includes a restart provision allowing the utility to call

the plant into service within two years. "After that we're free to do what we

want," Lawyer said.

Possibilities include repowering the facility, selling into the competitive

marketplace--as is being done by former QF Burney biomass (see CEM

No. 490 [22])--or perhaps rededicating the plant to another use. Lawyer

noted that the Cabazon Indian Tribe operates a tire recycling facility right

next to Colmac. Using the circulating fluidized-bed combustion technology

already in place at Colmac might be a good fit for tire burning, he

suggested. "It all depends on driving costs down to be competitive," he

said.

Edison asked for CPUC approval without hearings. Though the application

was initially filed December 23, 1998 at the CPUC's Los Angeles office,

evidently it was lost in transit to San Francisco along with a large bundle of

other mail. Copies of the filing did not appear until January 12, but the

CPUC allowed the application to be logged as of the December date.

Urban Wood Waste Utilization

The Colmac plant is one of only three biomass plants in Southern California drawing fuel

from the greater Los Angeles basin area. (One of these plants is currently shut down.) The

Colmac plant is by far the largest combustor of urban wood wastes in the state, using

1000-1200 t/d (including moisture content) of fuel, of which 80%-90% would otherwise

be landfilled. The remainder of the plant fuel consists of agricultural residues, primarily

from citrus and date orchard prunings and removals.

By virtue of its urban fuel consumption, the Colmac plant is a major factor in Riverside

County's ability to comply with the mandatory landfill diversion and waste reduction

requirements of California’s recycling law (AB 939). The recovery of energy from

biomass has been allowed as recycling credit by the state Integrated Waste Management

Board.

Collection of orchard residues for use as fuel by the plant has almost completely eliminated

open field burning in the Coachella Valley. The Coachella Valley is also the location of

Palm Springs, Rancho Mirage, Indian Wells, La Quinta, and other desert resort cities that

depend on clear desert air for tourist attraction.

The plant staff has made some good progress in obtaining lower fuel prices as the supply

infrastructure has matured and wood waste processors have started to charge tipping fees.

The plant’s air quality permit was modified to allow the combustion of petroleum coke,

which can be a very inexpensive fuel at times. The financing bank wants the loan paid off,

and Colmac plans to do that before the end of the first 10 years of the contract. Colmac has

invested in equipment that should eventually reduce O&M costs. But, Phillip Reese wrote

in 1995: “will the Colmac plant be able to compete if California decides that low price

electricity is the only measure of the worth of a generating station? I doubt it.”
82

Plant Flowsheet and Design Information

Boilers

The plant has two ABB circulating FBC boilers. The boilers have a combined output of

464,000 lb/h of superheated steam at 1255 psig and 925°F. Fuel is discharged from a day

bin atop the boilers via screw conveyors, which feed it to the bed injection pipes. Fines that

exit the boilers are separated at the 10-15 : level from the gas stream by cyclones and

reinjected into the bed. The boilers are designed for limestone and NH3 injection to control

SO2 and NOx emissions.

Colmac Energy Plant

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condenser

tower pumps

Deaerator Condensate

and

feed pumps

Turbine Electricity

 Boiler Steam generator 49 MW

 feed 1255 psig

 water 925 deg F Flue gas

 Petroleum coke

Wood

wastes Fuel CFBC boilers Multiclones

blending and & cyclones & fabric filter

preparation (2) baghouses (2)

 Ash Fly ash Stack

 Combustion air

Colmac Energy has made numerous improvements to the boilers to improve operations

and reduce maintenance costs. Modifications have been made to the vortex tubes, cyclone

separators, grid nozzles, high-efficiency air preheaters, and furnace refractory. Natural gas

input, which was required initially for flame stabilization, has been reduced to nearly zero.

Turbine/Generator

The turbine/generator is a nominal ABB 47-MW axial-flow unit. The generator has a highpressure, gear-driven turbine section on one end and a low-pressure section mounted on

the opposite end. The condenser is mounted transversely at the low-pressure end.

Fuel System

The truck scale operator provides primary control for the plant’s fuel deliveries, visually

inspecting loads and ensuring that specified quality levels are maintained. Once admitted,

the trucks are sequenced to the scale, to a dumper, and back to the scale. Two truck

dumpers can each unload seven or eight trucks an hour under normal operating conditions.
83

Fuel is dumped onto a dragchain feeder and conveyed to a radial stacker that forms a

kidney-shaped stockpile 45 ft high. The stacker automatically luffs and slews within an arc

range set by the yard operator, who monitors stacking while operating other equipment in

the area, such as chip dozers. Wood fuel is reclaimed from the kidney-shaped pile by either

of two systems. One uses an underpile dragchain reclaimer similar to the dragchain device

on the dumpers. Chips are stacked or dozed into a pile that buries the tail end of the

reclaimer. The chips are reclaimed and discharged to a belt conveyor. The other system

uses a boom-type overpile dragchain reclaimer. The boom luffs and slews and is gradually

lowered as it reclaims layers of wood chips and discharges them to a belt conveyor. The

overpile reclaimer requires a contoured pile face for a steady reclaim rate; to do this, it first

dresses the pile to provide a smooth surface. It can then operate unattended for 8 or more

hours.

From the belt conveyor, the wood chips are screened and hogged in a redundant system.

Disk screens size the chips. These positive-displacement devices use rotating disks to

move the oversized chips forward while the sized material falls between the screen

openings. The sized material discharges directly to another belt conveyor. The oversized

material from the head end of the screen is discharged to a wood hog. Most of the wood

chips are within the required size range, so only a portion of the reclaimed material must be

hogged. The reclaim design rate is 60 t/h, the hog design rate is 20 t/h.

The processed fuel is conveyed to the fuel metering bins. A belt conveyor carries the fuel to

the first bin. The fuel discharges via a splitter gate to Unit 2’s surge bin, or remains on the

belt conveyor for Unit 1. The splitter gate can also divide the fuel to feed both units

simultaneously. Bin level is controlled automatically via level sensors. The processed fuel

has poor flow properties, so the metering bins are designed with a relatively low height to

minimize compaction. Bin sidewalls have a negative slope (the bin’s base is larger than its

top) to avoid nonflowing areas caused by converging hoppers. The bins also have a 100%

live bottom, using screw conveyors for discharge.

The fuel system must operate 100% of the plant’s on-line time. Fuel system downtime is

planned to coincide with scheduled and emergency maintenance on other plant systems.

For this reason, the reclaim, processing, and plant feed systems are conservatively

designed and feature redundant screens, hogs, and conveyor drives.

Emissions Control

Particulate emissions are removed in multiclones followed by pulse-jet fabric filter

baghouses. Ammonia is injected to the flue gas for NOx control. The ash produced by the

plant is used as a soil amendment and filler material for road construction.

Balance of Plant

The water treatment system includes a brine concentrator and demineralizer equipment that

minimize the amount of effluent water. The crystallized solids end up with the ash. Cooling

water is supplied through a closed system using a mechanical draft cooling tower. Each

circulating FBC unit has an ID fan that discharges to a common stack. Electric power is

transmitted to the utility via a 92-kV line.
84

Fuels

The plant design called for a total fuel requirement of 277,000 dry t/yr of biomass fuel,

based on 85% plant availability. The design fuel mixture ranges were: wood waste,

85%-100%; agricultural waste, 0%-15%; municipal agricultural, 0%-10%. The wood waste

specification called for clean wood by-products from commercial sources, with less than

1% paint, preservatives, glue, varnish, and foreign matter. Wood waste treated with

creosote is not acceptable. The wood must be ground or chipped by the suppliers so 99% is

smaller than 3 in. in all dimensions. The maximum allowable amount of foreign matter is

3%; the maximum allowable moisture level is 35%.

The plant design contemplated that the agricultural fuels would consist primarily of bales of

straw and Bermuda grass. A bale processing line, including a bale feeder, unbaling station,

tub grinder, and connecting drag conveyor, was provided. Shredded straw was to be

blended with the wood fuel on its way to the boilers. In a 1995 presentation, Phillip Reese

described the agricultural component of the plant’s fuel as orchard removals and prunings

(i.e., wood). How much experience the plant obtained with shredding bales of straw and

conveying and combusting the shredded material is not clear, but not surprisingly that

straw is no longer mentioned as part of the plant’s fuel mix.

When petroleum coke is not being fired, the plant uses 1000 to 1200 t/d (including

moisture content) of fuel, of which 80%-90% is urban wood waste from the greater Los

Angeles area that would otherwise be deposited in landfills. The remainder of the plant fuel

consists of agricultural residues, primarily from citrus and date orchard prunings and

removals. Colmac collects the orchard wood at its own expense, and has been arguing for

the state’s air quality regulations to restrict the number and frequency of “burn days”

permitted, or add a fee for a burn permit. This would increase the availability of agricultural

wood wastes to the plant and shift some of the cost burden to the waste generators

(growers).

The company’s Mobile Grinding Services brochure shows a Morbark Model 1200 tub

grinder and a Morbark Waste Recycler, as well as loaders with various buckets. The

services offered include orchard grinding, land clearing for development, diversion site

grinding, and construction wood waste grinding. To qualify as acceptable fuel for the plant,

wood waste must be free of contaminants and noncombustibles, and must not be painted

or treated with wood preservatives of any type.

Initially, the generators of urban wood wastes could avoid paying landfill tipping fees by

delivering the wastes to Colmac’s fuel suppliers, which accepted those wastes free. In

1995, Colmac began encouraging its fuel suppliers (there are many, and all are independent

businesspeople) to charge tipping fees, and thereby reduce the cost of the fuel to Colmac.

Colmac Energy has asked the state Waste Board to encourage diversion of the wood

wastes to its fuel suppliers by, for example, instituting a surcharge on the landfill disposal

of wood wastes where a biomass plant alternative is reasonably available.

Colmac Energy has been very active in improving its fuel mix, trying to reduce problems

such as corrosion and fouling caused by potassium, sodium, and other elements in the

biomass fuels. Recently, the plant received a permit to burn as much as 50% (by heat

input) petroleum coke, which is about 6 t/h in each boiler. Operations with coke have been

successful, although the price of coke is very cyclical. At times when coke prices are low,
85

petroleum coke will provide fuel cost savings and operational benefits. During August

1998 the plant was burning a fuel mix of approximately 80% wood and 20% petroleum

coke by heat input.

Operating Experience

During startup, a number of equipment malfunctions, wiring discrepancies, and control

philosophy changes were experienced—none major. The size of the rotary fuel feed valves

was increased to accommodate the varying density of the fuel. The valve motor operators

were increased in horsepower and provided with reversing capability so any jams could

easily be cleared. A modification was made to the boilers’ wood storage day bin. To

prevent potential motor overloads on the feed screws, the back portion of the bins was

modified to stop biomass material from entering the last few feet of the screws. Changeout

of control valve trim was required on three valves—the condensate minimum flow control

valve, the desuperheater valve, and the auxiliary steam control valve. The actual flows and

pressures varied from design by an amount sufficient to warrant trim changes but not valve

body changes.

Overall, the plant operation has been highly successful, with high annual CFs and a low

heat rate for a biomass plant, as described earlier.

Environmental Performance

No mention was made of any difficulties in complying with the plant’s environmental

permit requirements.

Economic Information

By the year 2002, the plant will have to cover its O&M and fuel costs by selling power into

California’s competitive power exchange, plus any incentives that may be provided for

biomass energy generation. The plant’s actual O&M costs have not been divulged. The

EPRI BIOPOWER model estimates O&M costs for a 50-MW circulating FBC plant to be

about 1.7¢/kWh.

In early 1997 the plant manager mentioned that the plant’s wood waste fuel costs were

about $1.50/MBtu (about $25-$27/dry t). At that time, petroleum coke costs were about

10% higher than wood fuel costs, not including the added costs for limestone sorbent, so

the plant was not burning petroleum coke. In August 1998, the plant was burning about

20% petroleum coke, which indicates that the price for that fuel had dropped below the

price of some of the wood fuel available to the plant.

Not knowing specific fuel prices, or what to project for future fuel prices at the Colmac

plant, we can look at a range of possible values and convert them to ¢/kWh using a net

plant heat rate of 12,400 Btu/kWh:

Fuel, $/ MBtu Fuel, ¢/kWh O&M, ¢/kWh Total, ¢/kWh 

1.50 1.9 1.7 3.6

1.00 1.2 1.7 2.9

0.50 0.6 1.7 2.3
86

This hypothetical exercise shows that the plant could produce electricity for less than

3¢/kWh, if it can reduce fuel costs to $1/MBtu or lower. Other plants that burn urban wood

wastes (e.g., Tacoma Steam Plant No. 2 in Washington and Ridge Generating Station in

Florida) have shown that fuel costs can be reduced well below $1/MBtu, and even below

zero. To accomplish this the middlemen (fuel processors) must be eliminated and a tipping

fee waste wood processing yard must be set up on the biomass plant site. Whether

Colmac’s location in the desert beyond Palm Springs (about 120 mi from downtown Los

Angeles) would be conducive to such an arrangement is questionable.

Lessons Learned

Colmac Energy was not willing to share what it considered to be the most important

lessons learned from more than 6 years of operating the facility. The plant manager is

clearly very proud of the plant and its operating record. The numbers (CF, heat rate, etc.)

are excellent. There is clearly a recognition that none of that would have been possible

without the subsidy provided during the first 10 years of the ISO4 contract; there is real

concern about the fate of the project without the high contract prices.

Lessons that can be inferred from the information above about the Colmac Energy project

include:

• Urban wood waste can be a comparatively expensive fuel (~$1.50/MBtu) if the

plant is located far outside the urban area. The transportation cost is significant, but

more importantly, a distant plant probably has no alternative other than to contract

for fuel with wood processing companies that are located in the urban area.

Processors add at least $1-2/MBtu to the fuel cost. A properly located urban

biomass plant derives income from its fuel rather than paying for it—but

accomplishing this requires a location and a tipping fee structure that attracts wood

waste generators with loads to dump. (Location, location, location!)

• Nonwoody agricultural residues such as straw cause much more trouble and

expense than some design engineers realize. This can occur in all phases: collection,

transport, storage, preparation, feeding, and combustion. If these types of

agricultural residues are to be used as fuel, others who have used them successfully

must be found and emulated.

• As at Tacoma, Colmac Energy has found it worthwhile to modify its permit to

allow the use of petroleum-based waste fuels such as petroleum coke. At times,

waste fossil fuels can be more economical than biomass. Allowing for such fuel

flexibility during project development, design, and permitting phases is wise.
87

Sources and Contacts

The bulk of the information in this section was obtained from two published sources:

• Power Magazine , April 1992. “Biomass Plant Relies on Variety of Local Fuels,”

by William Frazer, Daniel Mahr, and Peter Goldbrunner.

• Strategic Alliances for Biomass Energy, National Bioenergy Industries Association

and Utility Biomass Energy Commercialization Association, Washington, DC,

November 14-16, 1995. “Colmac Energy, Inc.—An Agricultural Residue and

Urban Waste-Fueled Electric Power Plant,” by Phillip Reese.

Information was also provided by the plant manager, Graeme Donaldson, during telephone

calls in February 1997 and August 1998.

Graeme R. Donaldson

Plant Manager

Colmac Energy, Inc.

62-300 Gene Welmas Drive

P.O. Box 0758

Mecca, CA 92254-0758

Phone: 760-396-2554

Fax: 760-396-2834
88

GRAYLING GENERATING STATION,

GRAYLING, MICHIGAN

________________________________________________________________________

The 36 MW Grayling Generating Station in north-central Michigan near Grayling provides

electricity to a remote region, using wood waste material from local industries as fuel. The

town’s treated municipal wastewater is used as raw cooling water in the plant, which came

on line in 1992. The plant operates as dispatched by the utility, typically cycling daily from

its maximum capacity of 36 MW during peak load periods to about 15 MW during offpeak periods. From 1995 through 1998, the plant has consumed 289,000-347,000 t/yr of

wood wastes (at 44%-47% moisture), and has generated 165,000-200,000 MWh/yr.

Vital Statistics

Design capacity, net MWe 36

Configuration Traveling grate stoker boiler

Fuels—Wood wastes: Hog fuel bark) 35%-40%

Forestry residues 35%

Mill residues 25%-30%

Year 1995 1996 1997 1998

Net generation, MWh/year 182,400 186,500 165,994 199,843

Annual CF, % 57.6 58.9 52.4 63.1

Net heat rate, Btu/kWh 13,600

Thermal efficiency, HHV, % 25.1

The plant is owned by the Grayling Generating Station Limited Partnership. Members

include Decker Energy International Inc., Winter Park, Florida; CMS Generation Co., a

subsidiary of CMS Energy, Dearborn, Michigan; and Primary Power, Bay City, Michigan.

History and Outlook

A growing need for energy and environmental remediation made the Michigan location an

ideal site for an integrated wood-fired power plant. Sandy soils in the region are not ideal

for a wide variety of crops, but the use of lime to increase pH levels has helped sustain a

healthy timber resource, which includes aspen, northern oak, jack pine, and white pine.

Numerous small sawmills dot the hills and valleys.

By the early 1980s water purity had become a pressing local issue. Waste slab wood and

sawdust from milling operations contributed to acidic pollution of streams and lakes, and

the outdated sewage plant at Grayling was becoming inadequate. Grayling’s city leaders set

out to identify innovative engineering methods to solve these problems. After reviewing

several options, spray irrigation of a 120-acre hybrid poplar plantation with treated
89

wastewater was identified as a means of adjusting pH levels in the starved soils to improve

growing conditions and to take full advantage of newly purchased pumping capacity. The

concurrent planning and development of the 17-acre Grayling power station provided the

opportunity for a direct link with the city sewage plant, improving the economics of both

facilities.

Commercial operation began 90 days ahead of schedule; the owners took possession

August 1, 1992. Plant startup was very smooth and performance has been excellent.

Through March 1993, availability averaged higher than 95%, including 5 days of scheduled

outages. Through December 1998 the plant availability has averaged 96.2%.

The plant is dispatched into the Consumers Energy Company system. Output fluctuates

daily, typically between 10 MW during off-peak hours and 36 MW during peak hours.

The bulk of the electricity produced (about one-half to two-thirds of the 36 MW) is

consumed by major strand board and resin plants in the area; the remainder is distributed to

local homes.

Plant Flowsheet and Design Information

Grayling Generating Station

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condenser

tower pumps

 Blowdown

 (to/from city WWT plant) Deaerator Condensate Makeup water and

feed pumps

Turbine Electricity

Boiler Steam generator 36 MW

 feed 1250 psig

 water 950 deg F Flue gas

Wood Char

wastes Fuel Spreader Cyclones

blending and stoker & ESP

preparation boiler

 Ash Fly ash Stack Combustion air
90

Fuel System

The fuel yard stores 45 days of fuel at 100% boiler capacity. As many as 7 weeks pass

between the time fuel enters the yard and when it is sent to the furnace. This yard storage is

necessary to provide adequate drying time. Fuel mix to the furnace averages 40%-45%

moisture but may reach 50% after a heavy rain. High moisture levels adversely affect

impact plant operation—conveyors plug up, fuel does not blow into the furnace efficiently,

and CO emissions increase.

Fuel diversity requires a flexible materials handling system. Storage-pile management is

critical. Truck dumpers unload directly to grade and mobile equipment handles storage and

blending requirements to provide flexibility in fuel-receiving operations.

Fuel entering the plant is mixed into the fuel pile as it arrives and as it is moved into the

short-term storage pile. Fuel yard operators use track-type dozers to spread and blend fuel

to provide good mixture of fines and coarse material. Because of the high level of fines in

the fuel, the belt-cleaning and return-belt systems were designed to minimize carry-back

problems. All fuel conveyors are fully hooded.

Boiler

The plant uses a single Zurn Industries Inc., traveling grate spreader stoker boiler.

Although stoker fired, the furnace resembles a pulverized-fuel design because of its ability

to efficiently burn fines. Approximately 60% of the total combustion air is overfire and

40% is undergrate air—the reverse of most wood-fired boiler designs. Overfire air is

supplied through four levels of front-wall and three levels of rear-wall ports. As much as

62 t/hr of fuel enter the furnace through six pneumatic distributors. Most of the fuel burns

in suspension. The fuel/ash bed on the grate is relatively shallow. The boiler produces

330,000 lb/h of steam at 1250 psig and 950°F. The plant’s net heat rate, as tested, is 13,600

Btu/kWh (25.1% thermal efficiency, HHV basis). Char collected in downstream cyclones

and separated from noncombustibles is reinjected into the boiler.

The ability to use wood waste with a high fines content is a unique feature of Grayling.

Forty to fifty percent of the fuel particles are smaller than 1/4 in. The plant is designed to

handle fuel with a higher heating value of 4500 Btu/lb and a moisture content of 48%.

Magnesium oxide is used to control boiler slagging. It is added at the wood bins feeding

the boiler and at the reinjection lines twice a day. The compound conditions the material so

that the slag is loose, not glasslike, which makes it easier to remove from boiler tube

surfaces with sootblowers.

Char Reinjection

Char is collected in cyclones downstream of the boiler, separated from noncombustibles,

and reinjected into the boiler. Char reinjection lowers the carbon content of the fly ash and

increases overall plant efficiency.

Steam Turbine/Generator

ABB Power Generation Inc., provided the steam turbine/generator.
91

Emissions Control

Urea is injected into the upper sections of the furnace to reduce NOx emissions by 50%.

Injection lances/nozzles are located on the front and back walls in the upper third of the

furnace. The system supplier fine-tuned the process with respect to nozzle opening size and

spray patterns to minimize urea consumption.

Urea consumption depends on the nitrogen and moisture contents of the fuel being fired in

the boiler and on plant load. Because the plant is on full dispatch by the utility, it operates at

low loads, around 10 MW, during off-peak hours. During this time, urea injection is

minimal. During peak periods, the plant is dispatched at 36.17 MW and the urea injection

system is needed. Reagent consumption is approximately 0.56 gal/ton of fuel fired, or

roughly 50%-60% of the design value. Dry fuel consumption leads to higher NOx levels

and higher reagent consumption.

Fly ash is collected in a three-field ESP downstream of the cyclones. The plant has been

permitted to land-spread fly ash in lieu of lime on farmland for adjusting pH upward. The

pH of the ash is generally 12-13. The plant currently landfills the ash. This was an

economic decision; the cost of landfilling is lower than the handling fee of the disposal

company doing the land spreading.

Water Treatment

Scheduling and permitting considerations demanded innovative approaches to water

management. No surface watercourses nearby can serve as discharge points. Options for

discharge included percolation ponds, spray irrigation, or deep-well injection. All were cost

and time prohibitive. Instead, the plant chose to intertie with the city’s treatment plant to

provide benefits to both parties.

Grayling Station takes water from the tertiary portion of the city’s wastewater treatment

facility to supplement the plant’s makeup requirement, an average of 120 gal/min. Plant

operators manage and control the pumping systems in both directions to ensure that water

taken for makeup is always in excess of that returned to the city for disposal. The warmer

water that returns to the city sewage plant has been stripped of NH3 ; it therefore enhances

waste treatment bacteriology. Discharges to groundwater in the Grayling area are avoided

and the total discharge is reduced because of evaporative loss through the power plant

cooling tower. With a 60 gal/min net reduction in water returned from the power plant, the

City of Grayling estimates that its electricity bill for the pumping to irrigate poplar trees has

been reduced by 17%.

Water treatment at the plant includes primary and secondary strainers for solids and

chlorination for biotreatment. The cooling water system features all stainless steel

construction. During startup, cycles of concentration were high and defoaming agents

necessary. Since then, optimum cooling tower cycles of concentration have been

determined to be 6.5-7.0 and need for defoaming agents has been eliminated.

Staffing

The plant has 26 employees.
92

Fuels

An average of 40 trucks/d deliver sawmill and forestry wastes. About 35%-40% of the

waste wood is bark processed by hammermills; about 35% is composed of chipped tree

limbs and tops left over from forest management practices mandated by the Michigan

Department of Natural Resources; and the remaining 25%-30% is made up of clean fuels

such as sawdust, shavings, and scraps from sawmills and maple block production mills.

AJD Forest Products, a local lumber company that is 50% owned by the Grayling Station,

acts as procurement manager for the fuel, collecting and processing wood waste from

more than a dozen sawmill sites. The City of Grayling brings its tree trimmings to AJD for

processing and inclusion in the fuel mix.

Actual figures for wood waste fuel consumption by the Grayling Station were 289,368 t

for calendar year 1997 with an average moisture content of 47.4%, and 337,486 t for

January 1 through December 21, 1998 with an average moisture content of 44.3%.

The plant recently received a permit to test burn TDF, and initiated the test burns in midDecember 1998. The fuel is delivered in the form of 2-in. chips. The initial observation

after the first tests is that more of the wire needs to be removed from the TDF. The ash is

landfilled (and no longer used as a soil amendment), so the effects of zinc and other

components in the TDF on the ash properties are not major concerns.

Operating Experience

Some equipment changes have been made since startup. The hopper under the air heater

was modified to avoid the recirculation and subsequent slagging of heavy sand. Plates were

installed to divert flow from the air heater to the ESP hopper and a sand classifier that

keeps sand out of the fly ash transport system. Original level detectors in the live-bottom

fuel feed bunkers were not sensitive enough and were replaced with ultrasonic level

detectors. Screw feeders were modified to prevent bridging that occurred during startup

caused by high levels of bark in the fuel. In 1997, the ID fan wheel was replaced; ash

buildup on the fan had caused vibration, and stress cracks had developed in the wheel.

The Grayling Station’s statistics on annual availability and CF for 1995 through 1998 are

shown below:

1995 1996 1997 1998

Availability, % on-peak 96.09 97.89 97.04 96.99

off-peak 96.56 97.61 98.35 96.48

total 96.36 97.73 97.78 96.70

CF, % on-peak 68.14 72.17 69.67 81.19

off-peak 49.40 48.51 38.78 48.81

total 57.58 58.85 52.39 62.99

The plant was dispatched more often in 1998 than in previous years, as the cap on the price

at which the plant can bid its power was reduced. (This cap is based on the operating costs

of five large coal plants, and is included in the contract for sale of electricity to Consumers

Energy.)
93

Economic Information

Questions concerning Grayling’s project cost recovery and its sales contract with the utility

were resolved in 1987 after the state passed a law requiring utilities to buy power at a fixed

rate for the duration of project financing. Total project cost, including engineering,

construction, and financing, was $68 million, or $1878/kW.

The contract stipulates that Consumers Energy will buy electricity for 6.2¢/kWh. Built into

the rate is 4.05¢/kWh for capacity, 0.4¢/kWh for O&M, and 1.75¢/kWh for the energy

(now 1.65¢/kWh), based on the price of coal. Transportation and handling contribute most

to the plant’s fuel costs.

Lessons Learned

The Grayling plant started up with no significant problems and has run with excellent

performance for more than 6 years. There have been no major equipment problems and

staff members could think of no major “lessons learned.”

The project was planned and the plant designed with a waste management role in mind,

and efforts were made to fit positively into the local economic and environmental

landscape. Some planned environmental benefits have not worked out (e.g., the ash is

landfilled instead of being used as a soil amendment), but overall the plant has clearly

created benefits for the local economy and environment.

Like several other biomass power plants, the Grayling Station is operated as a cycling

plant. It has run at about a 70%-80% CF during peak demand periods, and at about a 40%-

50% CF during off-peak periods.

Sources and Contacts

The information in this section is based on an article in the April 1993 issue of Power

Magazine ; an article in the CADDET Renewable Energy Technical Brochure No. 16 ,

1995; and information posted on the CMS Energy web site (cmsenergy.com). Philip

Lewis, plant operations and maintenance superintendent, provided additional information in

February 1997 and December 1998.

Dan Nally

plant manager

or

Philip Lewis

plant operations and maintenance superintendent

Grayling Generating Station

4400 West Four Mile Road

Grayling, MI 49738

Phone: 517-348-4575 Fax: 517-348-4679
94

WILLIAMS LAKE GENERATING STATION,

BRITISH COLUMBIA, CANADA

________________________________________________________________________

The Williams Lake Generating Station in British Columbia is located about 225 mi

north/northeast of Vancouver and is the largest single-unit biomass-fired power plant in

North America. Originally a limited partnership (two-thirds owned by Inland Pacific

Energy Corp. and one-third owned by Tondu Energy Systems, Inc.), NW Energy

(Williams Lake) Corp. is now wholly owned by B.C. Gas Inc. The plant’s rated capacity is

60 MWe net, of which 55 MW is purchased by B.C. Hydro under contract. The plant can

produce 67-69 MW net, and frequently operates at that production level when it can sell its

excess energy through Powerex, a marketing affiliate of B.C. Hydro. The plant’s annual

CF has actually exceeded 100% for several years.

Vital Statistics

Design capacity, netMWe 60

Configuration Water-cooled vibrating grate boiler

Fuels Wood wastes (mill residues)

Year 1995 1996 1997 1998*

Net generation,MWh/yr 558,000 524,000 541,000 505,000

Annual CF,% 106.1 99.7 102.9 96.1

Net heat rate, Btu/kWh ~11,700

Thermal efficiency, H HV,% 29.2

 *Projected in December1998.

History and Outlook

The Williams Lake region was often beset with layers of smoke and a generous sprinkling

of ash particles from wood waste burners at the five local sawmills. Beginning around

1988, concerted action by the provincial government, the local utility, the sawmill owners,

and the public resulted in construction of Williams Lake station.

Commercial operation started on April 2, 1993. By year’s end, all performance goals were

met or exceeded. The CF for the first 9 months was 91.6%, with a forced outage rate of

less than 5%. In each of the five following years the plant has generated more than 500

GWh/yr and consumed more than 550,000 tons/yr of mill residues.

The Williams Lake Generating Station not only has the largest wood-fired boiler in North

America and generates more electricity each year than any other wood-fired power plant; it

is also the most efficient stand-alone wood-fired power plant in North America, with a net
95

plant heat rate of about 11,700 Btu/kWh. With nearly free fuel, efficiency is not a major

priority at Williams Lake. However, the steam conditions, auxiliary power consumption,

and turbine efficiency are considerably better than those at smaller plants, and Williams

Lake runs consistently on very high-quality wood fuel, generating about 73 MW gross and

67-68 MW net, about 12% above its design capacity.

Plant Flowsheet and Design Information

Williams Lake Generating Station

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condenser

tower pumps

Deaerator Condensate

and

feed pumps

Turbine Electricity

Boiler Steam generator 60 MW

 feed 1575 psig

 water 950 deg F Flue gas

Wood

wastes Fuel Spreader Multiclones

blending and stoker & ESP

preparation boiler

 Ash Fly ash Stack

 Combustion air

Fuel System

The fuel is processed on site through a magnet to remove ferrous metal and a disk screen

to reject oversized material. The fuel yard has a 60-d storage capacity, and more than 3600

ft of conveyor belts. The fuel is piled 40 ft high on a graded stockpile area of about 400,000

ft2

. The extensive fuel handling system takes advantage of the slope of the site to minimize

the number of pits required for the conveyor system. The arrangement also takes into

account winter-related access problems for fuel trucks.

An 82-ft x 10-ft, 75-t scale weighs incoming and outgoing trucks. An 82-ft hydraulic truck

dumper (75-t capacity) and a 57 ft truck dumper (60-t capacity) dump fuel into live bottom

receiving hoppers. Drag conveyors in the bottom of each hopper convey the fuel to a single

300-t/h outfeed conveyor. A slow-turning spiked roll breaks up fuel clumps as the stream

exits each hopper.
96

An oversized-fuel infeed hopper/conveyor is provided alongside the two truck dump

hoppers to introduce oversized fuel to the processing system. This fuel is dumped onto the

pavement in the truck dump area, and loaded onto the fuel-infeed hopper/conveyor by a

front-end loader.

The outfeed conveyor has a self-cleaning magnet to remove ferrous materials. A metal

detector further down the conveyor trips the belt if it detects metal. The outfeed conveyor

delivers fuel to a 300 t/h disk screen, which removes material larger than 3 in. from the fuel

stream. Accepted fuel is deposited directly onto a troughed scalper/hog outfeed conveyor

(300 t/h). Scalper rejects are fed to a 75-t/h wood hog and then to the outfeed conveyor. An

electromechanically actuated hog bypass can divert rejects to a paved apron area; a frontend loader can return oversized fuel from there to the infeed hopper.

The scalper/hog outfeed conveyor transports sized fuel to a stackout conveyor. This is

situated 60 ft above stockpile grade level and is fitted with a plow. The plow drops fuel

adjacent to the fuel reclaim area. Both the stackout conveyor discharge, which terminates

near the center of the stockpile, and the plow discharge are fitted with extended chutes. A

bladed, tracked vehicle moves incoming fuel from the stackout conveyor drop points to

appropriate areas of the pile or to the reclaim area.

Two automatic, back-to-back, radial overpile reclaimers (140 t/h) drag fuel from the

surface of the stockpile to flight-type transfer conveyors. Each reclaimer has a total livestorage volume of at least 12 h at the plant’s maximum continuous rating. The transfer

conveyors deposit fuel on a reclaim outfeed conveyor for delivery to a disk screen. The

reclaim outfeed conveyor exits the stockpile area via a concrete tunnel. A magnet is

positioned at the conveyor head pulley. Accepted fuel smaller than 3 in. passes through the

disk screen onto a 140-t/h boiler feed conveyor. Disk screen rejects are chuted to a paved

apron area at grade for recycle by mobile equipment. A disk screen bypass chute with a

manually actuated flop gate is provided.

The boiler supply conveyor delivers fuel to a boiler cross-feed conveyor that distributes

fuel in turn to each of seven boiler fuel surge bins. It is of the flight-conveyor type arranged

for top carry and bottom feed. The excess fuel remaining after traversing the fuel surge

bins is deposited onto a stockpile return conveyor. The transfer points to and from the

cross-feed conveyor are isolated from the boiler building air space to minimize fugitive

dust in the boiler building. Knife gates provided in the outlets from the cross-feed conveyor

to each fuel bin allow maintenance activities to be isolated.

The stockpile return conveyor (140 t/h) delivers excess fuel to a transfer point. By means

of an electrically actuated flop gate, the material can either be deposited on the stackout

conveyor for return to the stockpile or chuted back to the boiler supply conveyor. Both the

boiler supply and stockpile return conveyors are equipped with belt scales wired into the

DCS.

The only area of the plant that was modified after startup was the fuel handling system.

Minor modifications were made to improve performance, such as:

• Adding the ability to reverse the dragchains on the dumper hoppers, to make

unplugging fuel jams easier.
97

• Adding three more rolls to each disk screen (12 rolls were provided originally), to

reduce the carryover of fine particles that tended to plug up the hog.

Boiler

The boiler is a two-drum, top-hung watertube design delivering 561,750 lb/h of 1575 psig,

950°F steam when burning design fuel with 33% excess air. Steam temperature is

controlled by interstage superheater attemperation.

Combustion takes place on and over three vibrating water-cooled grates inclined about 6%

from horizontal. With each grate vibrated intermittently, burning fuel and ash slide during

operation from the rear of the furnace to the front, where ash falls into a water-filled ash

hopper. Intermittent vibration also prevents ash deposits from forming and helps maintain

free fuel flow. Incoming fuel is evenly spread over the upper portion of each grate by airswept distributor spouts located on the front furnace wall. Small particles entering the

furnace are burned in suspension; larger pieces burn on the grate. About 75%-80% of the

fuel particles are smaller than 1/4 in.

The boiler furnace provides residence time longer than 3 s at guaranteed conditions to

achieve sufficient carbon burnup without reinjecting char. Balanced draft is employed with

a single FD fan supplying inlet air to the furnace, an ID fan discharging flue gas, and a fuel

distribution air fan supplying motive air to the fuel distributor spouts. A tubular air heater

heats combustion air from the FD fan before it enters the furnace.

Turbine/Generator and Auxiliaries

The turbine is designed for throttle steam conditions of 1550 psig/950°F, and 2.5-in. Hg

abs exhaust pressure at design ambient conditions. Three uncontrolled extraction points for

feedwater heating are included. The turbine/generator provides a guaranteed net electric

output of 60 MW (with capability for 67-68 MW under most conditions). The generator is

an air-to-water cooled unit rated as follows: 0.90 power factor lagging to 0.95 power factor

leading, three phase, 60 Hz, and 13.8 kV.

The condenser rating is based on a tube cleanliness factor of 0.85. Condenser tube material

is Type 304 stainless steel. Two 100%-capacity, two-stage steam-jet air ejector (SJAE) sets

are provided, each capable of taking condenser vacuum from 10-in. Hg abs to design

vacuum in 1.5 h. Condensate-cooled inter- and after-condensers are stainless steel tubed.

One single-stage hogging injector is capable of drawing condenser vacuum from

atmospheric pressure down to 10-in. Hg abs in 30 min.

Two 100%-capacity, canned, vertical, turbine-type, condensate extraction pumps move

condensate from the condenser hotwell through the SJAE condensers, the turbine-gland

steam condenser, and the low-pressure feedwater heater to the deaerator. A minimum-flow

recirculation line is provided for the condensate extraction pumps downstream of the

gland-steam condenser.

Emissions Control

Flue gas passes to the stack through a mechanical dust collector, the ID fan, and an ESP.

Fly ash is removed at three locations: the convection and air heater sections of the boiler,

the mechanical dust collector, and the ESP. The dust collector consists of a multiplecyclone-type separator with 70% minimum removal efficiency. The ESP has five fields,
98

and is sized to meet the particulate emissions limit of 0.02 gr/dscf with one field out of

service. Heated hoppers sized for 12 h of material storage are included in the ESP design.

On-line stack gas analyzers (CEMs) continuously monitor and record NOx , CO, O2 , and

opacity emissions. CEM system outputs are directed to the DCS and average emission

levels are computed. The CEM system also contains a strip-chart recorder to record output

of each analyzer.

Plant Control

The DCS provides analog and sequential (logic) control capabilities in one reliable

integrated system. The system monitors, alarms, archives, and logs instrument signals

from selected facility equipment. It also interfaces with turbine/generator controls for load

control and shutdown functions. The operator can manipulate analog control loops, using

setpoint adjustments or manual control, and can start or stop process equipment from

computer control stations on the operator’s display unit.

Key Suppliers

Turnkey contractor CRS Sirrine Engineers Inc.

Constructor TNL Construction Ltd.

Boiler island engineer The McBurney Corp.

O&M mobilization Sterling Energy Operations Inc.

Steam generator Babcock & Wilcox Canada

Steam turbine/generator General Electric Co.

Boiler feedpumps, motors KSB Inc., Westinghouse Electric Corp

Boiler feedpump turbine Dresser-Rand Co.

Boiler makeup demineralizer Glegg Water Conditioning Inc.

Fuel handling/conveying system Power Tech

Fuel reclaimers Industrial Services Inc.

Truck dumpers/hoppers Phelps Industries Inc.

Truck scale Western Scale Co.

Digital control system Bailey Controls Co.

FD and ID fans Buffalo Forge Co.

Ash handling system Ash Tech Corp.

Hydrograte Detroit Stoker Co.

ESP Environmental Elements Corp.

Dust collector Zurn Industries Inc.

Air compressors Ingersoll Rand Co.

Bridge crane Zenar Corp.

Stack Power Tech

Circulating water pumps Thermal-Dynamic Towers Inc.

Main transformer Hyundai Corp.

Voltage transformers ABB Inc.

Motor control centers General Electric Co.

Staffing

Williams Lake Generating Station has a full-time staff of 30 employees, including 15

operators.
99

Fuels

The plant consumes more than 550,000 green t/yr of wood waste from sawmills in the

Cariboo region. Five sawmills, located within 5 km, supply the fuel at no cost, and receive

value from alleviating an environmental liability of waste disposal. Because the mills are so

close to the plant, conveyor belts were considered, but short haul trucking is used to

transport the fuel. The power plant pays for the transportation, and paid approximately $2

million to install fuel preparation equipment at each sawmill. The sawmills pay the

operating expenses for the fuel preparation equipment.

The fuel mix is approximately 40%-50% bark; the rest is an assortment of sawdust, chips,

and slabs. Fuel specifications include moisture content of 35%-55%. Typical fuel moisture

content during the summer is 37%-38%; during the winter, 50%. By hogging and blending

at the mills, the plant has been able to maintain consistent fuel quality. The plant can also

use pulp-quality chips because there are no paper mills in the vicinity.

Operating Experience

The plant has run well, with more than 94% or higher average availability and production

statistics as noted earlier. From 1996 to 1997, corrosion was noted in the cold end of the air

heater. The air heater was retubed during a scheduled turnaround in 1997.

In May 1998, during a scheduled outage, a major overhaul of the steam turbine found

some water erosion in the back end, resulting in an extra week of downtime. In June, the

turbine tripped, and during an unscheduled 2-wk outage the stationary turbine components

were found to have been reinstalled slightly too high.

During the May 1998 scheduled outage, some fireside corrosion was found in the boiler

(superheater and air heater). A small amount of chloride in the fuel is believed to interact

with ash and slag deposits on the tubes to cause the corrosion. Some tubes were replaced

with 310 stainless steel. One specific source of fuel (referred to as the Ainsworth hog) at an

oriented strand board mill contains aspen bark and limbs with a relatively high potassium

content. This fuel source may be eliminated if the corrosion problems persist. Various

options, including reducing furnace exit gas temperatures, water injection, and stainless

steel inserts or tube sections in the last 5 or 6 ft of the air heater, where the flue gas reaches

its dew point, are being explored with B&W’s help.

Improvements to the fuel handling equipment made shortly after startup were noted earlier.

More recently, the seven sets of dual screw feeders were replaced because of erosion. The

pitch was changed, and the cones were extended to 8 ft over the 12-ft length of the screws.

The slopes of the bin walls were changed to alleviate bridging and compression of the fuel.

As mentioned earlier, efficiency (heat rate) is not a high priority because the fuel is almost

free. However, the relatively high steam temperature and large unit size give the Williams

Lake Generating Station a low heat rate (high conversion efficiency) compared to other

biomass power plants. The unit consumes approximately 46 dt/h of fuel while producing a

net output of 67 MW. Assuming an HHV of 8,500 Btu/lb for wood on a dry basis, the net

plant heat rate is 11,700 Btu/kWh (29.2% conversion efficiency, HHV basis). The contract

with the boiler manufacturer guaranteed a net plant heat rate of 13,753 Btu/kWh, but the

plant achieved an actual net heat rate of 11,663 Btu/kWh during the 72-h performance test.
100

Environmental Performance

Diverting wood residue from the local sawmills resulted in closure of their beehive

burners. This reduced particulate emissions by more than 95%, solving a severe and longstanding local air pollution problem. The state-of-the-art facility is equipped with

combustion and emission controls including multiclones and a five-field ESP. The plant

was designed to surpass the air emissions permit levels, that are already five times tighter

than current regulations for wood waste-fired boilers. The power from this regionally

sustainable, environmentally beneficial project enables B.C. Hydro to defer construction of

other power projects.

Economic Information

More than 275 person-years of employment were created during the 2-year construction

period; 50% of the craftspeople were hired from the Williams Lake area. The continuing

operations of the plant provide 28 direct and 15 indirect permanent jobs. More than 90% of

the operating staff were residents of B.C. when hired. The plant solved a major solid waste

disposal problem facing local sawmills, thereby improving its competitiveness and

stability.

The total capital cost was reported as $150 million (Canadian), including off-site wood

processing equipment. (At U.S.$0.80 to the Canadian dollar, this was about

U.S.$125 million, or ~$2100/kW.) Specific information on O&M and fuel costs was not

provided, but the plant design and performance figures indicate that Williams Lake is one

of the lowest-cost biomass power plants operating today. The fuel cost is almost certainly

less than 1¢/kWh, and the O&M cost is probably less than 1¢/kWh as well.

Lessons Learned

The plant engineer feels that overall, the boiler and turbine/generator systems are excellent.

The boiler is generous, the turbine/generator is robust, and the ESP is overdesigned. The

fuel handling system needed some reworking. Tramp iron removal locations needed to be

moved, dust control systems needed improvement, and the reclaimer structures needed

redesigning to more evenly distribute the stress. Staying on top of maintenance programs

at all times is essential.

As long as the mills continue to operate and provide the fuel, no major issues are on the

horizon for the Williams Lake Generating Station. With uncertainty in the forestry

industry, unknown impacts of Asian market upheaval, high provincial stumpage fees, and

closure of some coastal sawmills and pulp mills, the biggest long-term threat to the plant

appears to be fuel availability.
101

Sources and Contacts

Some of the information was obtained from an article in Power Magazine (April 1994)

written by Jim Ford of Tondu Energy Systems Inc. More recent information was provided

by Gerry Arychuk (the plant’s chief engineer, who retired in 1997) and Colin Kozak,

general manager.

Colin Kozak

General Manager

NW Energy (Williams Lake) Corp.

4455 Mackenzie Avenue North

Williams Lake, B.C. V2G 1M3

Phone: 250-392-6394

Fax: 250-392-6395
102

MULTITRADE PROJECT, HURT, VIRGINIA

________________________________________________________________________

The world’s largest stand-alone wood-fired power plant came on line in June 1994 in Hurt,

Virginia. The 85.1-MW (79.5-MW net) independent power plant was built under contract

to Virginia Power as the result of an open solicitation for additional power. The plant

provides peaking power on demand from the utility and has operated at annual CFs of

10%-20%. The capacity payment that Virginia Power pays under the 25-year contract

keeps the plant operating at these low CFs.

Vital Statistics

Design capacity, net MWe 79.5

Configuration 3 fixed grate stoker boilers

Fuels (approx. % of total) Sawmill chips and

 whole tree chips (78)

Sawdust (17)

Shavings, bark,

 and tub grindings (5)

Net heat rate, Btu/kWh 14,200-13,600

Thermal efficiency, HHV, % 24.0-25.1

1995 1996 1997

Net generation, MWh/yr 133,000 85,500 100,000

Annual CF, % 19.1 12.3 14.4

History and Outlook

Multitrade Group of Ridgeway, Virginia, received the original contract from Virginia

Power and built the plant at a total cost of $114 million. The general partner in the limited

partnership that now owns the plant is ESI Energy, a wholly owned subsidiary of FPL

Group, and an original investor in the plant. The FPL Group has other holdings, including

Florida Power & Light (FPL). Hurt is located in south central Virginia about 20 mi south

of Lynchburg and 100 miles north of Greensboro, North Carolina.

Construction on the project started in November 1992 after more than 4 years of battles

and $4 million in expenses to obtain 28 permits to construct and operate the plant. Plant

startup began in December 1993, and commercial operation began in June 1994. The plant

operates on a dispatchable basis for Virginia Power and was operated at 10% of its capacity

during the first month.
103

Originally, investors would not participate in the project without assurance of long-term

fuel supplies. Fuel suppliers either would not sign such contracts or it was deemed

impossible to enforce such contracts. Adequate fuel supplies have been developed in the

area, and continue to be developed to provide investor confidence.

The Multitrade plant’s role is to provide 79.5 MW of capacity on Virginia Power’s system.

A peaking plant, it burns 100% wood, none of which can originate from potentially

contaminated sources such as pallets or construction/demolition debris. Virginia Power

normally provides 12 h notice to Multitrade, at 6:00 p.m., that the plant needs to be

generating at 6:00 a.m. During some seasons, weeks go by without being dispatched. On

January 20, 1998, for example, the plant had not operated since December 30, 1997.

Plant Flowsheet and Design Information

Multitrade Project

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condensers

towers pumps (2)

Deaerator Condensate

and

feed pumps Turbine Electricity

generators 79.5 MW

 Boiler Steam (2)

 feed 1500 psig

 water 950 deg F Flue gas

Wood

wastes Fuel Stoker Cyclones

blending and boilers and ESPs

preparation (3) (3)

 Bottom ash Fly ash Stack

 Combustion air

Boilers

Three fixed-grate Riley Stoker boilers generate steam at 1500 psig and 950°F from the

wood waste fuel. The design steam rate for each boiler is 242,000 lbs/h, and the boilers are

rated at 250,000 lbs/h each. The design plant output of 79.5 MW (net) can be achieved with

the boilers each generating about 239,000 lbs/h of steam. Steam blowers are used to clean

the fixed grates when the boilers are operating at low load.

Turbine Generators

Two ABB steam turbine/generators generate electricity (85.1 MW gross, 79.5 MW net).
104

Water System

Cooling water for the condensers is cooled in cooling towers. Makeup cooling water and

boiler feed water come from the Staunton River. The water is held in a raw water storage

reservoir, filtered, and stored in a tank for process use. Cooling tower blowdown is

dechlorinated and returned to the Staunton River.

Ash Removal

Bottom ash from the boilers is combined with fly ash from the cyclone separators and

ESPs in an ash silo. Ash conditioner can be added as the ash is dumped from the silo into

trucks.

Fuel System

To facilitate movement of fuel supply trucks, two scales weigh trucks in and out of the

plant. Two dumpers that can tilt the whole truck are used. Truck drivers carry magnetized

cards that are scanned at the scales to track fuel purchases. This system allows the fuel

supply trucks to unload and exit the plant within 12 min after entry.

The plant is required by contract to maintain at least 15 d of fuel in storage. Fuel is stored in

an open pile with a maximum height of 30 ft, and a first-in, first-out system of storage

management is used to minimize heat buildup. The maximum amount of wood fuel stored

in the pile is about 82,000 t. Under full load the plant consumes 2900 t/d of wood.

Emissions Control

Urea is injected into the flue gas from each boiler for NOx control. Each boiler has a

cyclone collector and an ESP to remove fly ash. The flue gas from the three ESPs is

combined and exhausted through a single stack.

Staffing

Twenty-six people are employed at the plant, including the general manager, an operations

manager, an administrative manager, a maintenance manager, a fuel procurement manager,

a maintenance crew of three mechanics, and four, four-person crews to operate the plant.

Each shift works 12 h, rotating 4 days on and 4 days off.

Fuels

Fuel is purchased entirely on the spot market and averages around $12/green t. Chips from

sawmills and whole tree chippers account for about 78% of the total fuel and average about

$14/t; sawdust accounts for about 17% of the total fuel and averages about $9/t; shavings,

bark, and tub grindings account for about 5% of the total fuel and average about $11/t. The

fixed grate boilers operate very well with fine fuel sizes. The plant has used as much as

45% sawdust in the fuel blend. The maximum particle size specification is 4 in., although

smaller than 2.5 in. is preferred. The moisture content averages about 40%-45% for chips

and sawdust.

The fuel yard is kept at least half full at all times to be ready for full-capacity operation. The

plant buys from about 225 fuel vendors throughout southwest Virginia, plus 16 or 18

counties in North Carolina, and one county in Maryland. The effective fuel supply radius is

about 200 mi. Within a 30-mi radius or so, there are three large paper mills and three
105

strand board plants, all of which are in the market for large quantities of biomass fuel.

Multitrade has established cooperative relationships with several of these plants, mostly to

keep fuel suppliers in business by coordinating with each other during periods of

fluctuating wood procurement rates.

Operating Experience

The plant has been technically and financially successful. All major milestones were met

on schedule, and the plant has consistently supplied power to the grid, and profits to its

owners, on schedule. “Readiness” is the primary priority for a peaking plant.

The guaranteed heat rate was 14,447 Btu/kWh and startup tests verified this heat rate.

During commercial operation the net plant heat rate has ranged from 14,200 to 13,600

Btu/kWh (24.0%-25.1% thermal efficiency, HHV basis).

Environmental Performance

No mention was made of any difficulties in complying with the plant’s environmental

permit requirements.

Economic Information

The plant owner receives a capacity payment from Virginia Power that keeps the plant

ready to run. During operation, additional payments for fuel and O&M are received. These

are currently about 2.0¢/kWh for fuel and 0.5¢/kWh for O&M. (At a heat rate of about

14,000 Btu/kWh, 2.0¢/kWh is equivalent to $1.43/MBtu. Assuming a wood heating value

of 8,500 Btu/lb on a dry basis, this is equivalent to about $24/dry ton of wood. Assuming

an average wood moisture content of 50%, this is equivalent to about $12/t of wood.)

Lessons Learned

No mention was made of any major problems or surprises encountered during 4 years of

operation. Some minor technical problems or issues were mentioned (most of which are

typical of biomass power plants):

• Fuel feeding problems in the early days of operation, quickly corrected.

• Erosion and corrosion in the fuel splitter boxes and conveyor belt shrouds

(corrected by replacing the original 3/4-in. steel plate with 1/4-in. steel lined with

1/2 inch of a plastic material).

• Occasional heating and combustion problems in the fuel pile.

• Occasional odor problems until they learned not to let any part of the pile age longer

than a year. (The maximum fuel storage time is much shorter than 1 year now.)

There was a major turbine trip on Christmas day 1996, caused by an electrical short circuit.

ABB had to make a replacement part in Sweden, and the plant general manager personally

took it through customs in Washington, DC, and drove it to the plant in time to be back on

line as scheduled.

The Multitrade project is an interesting example of a biomass plant that was designed from

the beginning to be a peaking plant. (Many other biomass plants that now operate as

peaking plants were originally designed and contracted as baseload units.) The fuel cost for

this rural plant, about 2¢/kWh, is high compared to that for an urban wood waste plant

such as Ridge Generating Station, about 0¢/kWh. It would be interesting to see how the
106

cost of the Multitrade contract to Virginia Power would compare to the cost of an 80 MW

natural gas-fired peaking plant in the same location.

Sources and Contacts

Most of the information in this section was obtained from Tom Corlett, plant general

manager (reassigned to another office in 1998). An article in the SERBEP Update , August

1994, also provided information.

Carl Levesque

plant manager

Multitrade Project, P.O. Box 2001

Hurt, VA 24563

Phone: 804-324-8223 Fax: 804-324-8228
107

RIDGE GENERATING STATION,

AUBURNDALE, FLORIDA

________________________________________________________________________

The Ridge Generating Station Limited Partnership owns an independent power-producing

unit between Auburndale and Lakeland, Florida, that burns waste wood, waste tires, and

landfill gas. The unit has a gross capacity of 45 MW and nets about 40 MW in sales to

Florida Power Corporation. Generally, the plant operates at full capacity from 11:00 a.m. to

10:00 p.m., and reduces load at night. Wheelabrator Ridge Energy, Inc., a division of

Wheelabrator Environmental Systems, Inc., operates the plant under contract to the owner.

Vital Statistics

Design capacity, net MWe 40

Configuration 1 traveling grate stoker boiler

Operating cycle (typical): Full load 11:00 am - 10:00 pm

Reduced load 10:00 pm - 11:00 am

Fuels, % by heat input: Urban wood wastes ~66

Scrap tires ~30

Landfill gas ~4

Net heat rate, Btu/kWh ~16,000

Thermal efficiency, HHV, % ~21

Net generation, MWh/yr ~200,000

History and Outlook

Because of its low-lying geography and high water table, Florida has a stronger incentive

than most states to find alternatives to landfilling solid wastes. Landfills that begin at

ground level and rise as high as 200 ft are commonly the highest elevations in Florida

coastal counties. State legislation and incentive programs since the 1970s have caused

Florida to have the largest capacity of waste-to-energy (WTE) facilities of any state. Not

counting Ridge Generating Station, there are 12 WTE plants in Florida with a combined

capacity of 486 MW. (Four are operated by Wheelabrator.) Because of its climate, Florida

also has a relatively high per-capita generation rate of urban wood wastes.

The initial development of the Ridge Generating project by Decker Energy-Ridge Inc. and

Wheelabrator Polk Inc. (the general partners in Ridge Generating Station Limited

Partnership) involved discussions with Polk County about a WTE plant. However, Polk

County had ample landfill space available, so the project was redefined to use only selected

portions of the solid waste stream as fuel—urban wood wastes and scrap tires, along with

landfill gas from a Polk County landfill adjacent to the 31.4-acre plant site. The project
108

developers signed a Power Sales Agreement with Florida Power Corporation in March

1991; construction began in late 1992, and the plant came online in August 1994.

The contract with Florida Power Corporation was renegotiated after the plant began

operation. It now requires the plant to generate electricity during peak hours only.

Generally, the plant operates at full capacity from 11:00 a.m. to 10:00 p.m. 7 days a week

and reduces load at night.

Ridge Generating has been peripherally involved in a research project by the University of

Florida and others, to evaluate the production of sugarcane on reclaimed phosphate mine

areas south of the plant. Juice from the cane would be used to produce ethanol, and the

processed cane bagasse would be added to the fuel mix at the power plant. Based on the

feasibility studies to date, the ethanol project does not appear to be economically attractive.

Plant Flowsheet and Design Information

Ridge Generating Station

Evaporate

Cooling Cooling

water water

Cooling Cooling water Condenser

tower pumps

Deaerator Condensate

 Landfill gas and

feed pumps Turbine Electricity

generator 40 MW

 Scrap Boiler Steam

 tires Tire feed 1500 psig

shredding water 980 deg F Flue gas

and storage Lime spray

dryer

Urban wood

wastes Wood fuel Stoker

preparation boiler Fabric filter

and blending baghouse

 Bottom ash Fly ash Stack

 Combustion air

The plant processes about 250,000 t/yr of wood wastes and 35,000 t/yr of scrap tires. The

landfill gas provides about 3%-5% of the heat input to the system, which includes a Zurn

traveling grate boiler, a turbine generator, and a lime slurry spray dryer/baghouse system

plus a noncatalytic NOx reduction system to control air pollutants from the combustion

process. The facility operates with zero water discharge and uses cooling towers for its

cooling system. Fresh water makeup comes from a deep well.
109

Boiler

The Zurn traveling grate boiler generates about 345,000 lb/h of steam at about 1500 psig

and 980°F. Wood typically provides about two-thirds of the total heat input; TDF provides

about 30%; and landfill gas provides about 3%-5%. Wood is injected to the boiler about

2 ft above the grate; TDF about 2 ft above the wood; and landfill gas enters about halfway

up the furnace.

Fuel Systems

The plant has three separate fuel systems. The wood waste fuel yard takes up the most

space and has the most equipment. Vehicles of varying types and sizes enter the fuel yard

and discharge their wood wastes as directed. Two truck dumps allow large vans carrying

wood chips to be dumped into below-grade collection areas from which the wood chips are

fed into the processing and storage system. Other wood wastes trees, brush, yard waste,

pallets, industrial wood scraps, construction wood scraps, demolition wood debris, etc. are

dumped out onto the ground. The plant accepts all types of wood wastes, including treated

wood. The only type not accepted is palm trees, which are too fibrous and cause problems

during processing.

Dozers and bucket trucks feed the large-sized wood wastes into a large tub grinder, which

operates mostly at night. The tub grinding operation is run by a contractor. Wood waste

from the tub grinder and from the truck dumps is placed on a conveyor and fed to a vertical

hog. It then passes under a magnet and through a screen. Overs go to a second vertical hog

and under another magnet. From this point the fuel is conveyed to a reclaimer/stacker

which distributes the fuel onto the storage pile. The typical residence time in the storage pile

is about 3 months. The wood wastes are effectively blended and are prepared and stored.

Vehicles carrying scrap tires to the plant are directed to the tire area, which is between the

wood fuel yard and the boiler. A tire shredding machine produces approximately 3-in. tire

chips, which are conveyed onto a storage pile. Loaders place the TDF onto a conveyor that

takes it to the boiler.

The Polk County Landfill “across the fence” has a grid of gas wells, a gathering system,

and a pipeline that carries the landfill gas to the plant. The gas is piped directly into the

furnace.

Emissions Control

The combination of waste fuels used by the Ridge Generating plant requires an effective

scrubbing system to remove SO2 (tires have significant as do some types of wood waste

such as C/D) and other trace contaminants. A spray dryer lime scrubber, followed by a

fabric filter baghouse, perform this function while removing fly ash from the flue gas. An

NH3 injection system reduces NOx emissions.

Staffing

The plant is staffed by about 40 people, with about 7 operating staff per shift and the

remainder on day maintenance and office administration.
110

Fuels

The facility receives waste wood and tires from local haulers and communities within

about a 50-mi radius. (Tampa and parts of Orlando are within this radius.) About 20% of

the wood wastes and all the tires come in with tipping fees. The rest of the wood wastes are

obtained at very low cost. The waste wood includes a great deal of vegetative waste, which

has a high moisture content. Varying moisture content is one of the major control

problems, but using tires and landfill gas helps control the combustion process. The

generating station paid for the landfill gas wells, gathering system, and pipeline from the

landfill to the plant, but does not pay a fee for the gas. The station does pay to place ash

from the combustion process back into the landfill.

The total annual wood consumption at the plant is about 250,000 t/yr, of which an

estimated one-third, or about 80,000 t/yr, come from the Lakeland-Winter Haven

metropolitan area (population ~410,000). Lakeland is about midway between the much

larger metropolitan areas of Tampa and Orlando, which sprawl from about 40 to 70 mi

from the plant. Most urban wood waste fuel is tree wastes, brought to the plant by tree

service companies and land clearing companies. About 10%-15% of the total wood waste

is C/D wood debris; industrial wood wastes such as pallets and scraps account for a

smaller percentage.

Operating Experience

The plant has operated well, although it has experienced some of the typical problems with

boiler tube fouling, etc., caused by the use of waste fuels containing alkali, chlorine, sulfur,

and other contaminants. Plant personnel mentioned no major equipment problems and

seemed happy with the system’s ability to efficiently handle the three fuels.

Environmental Performance

No difficulties were reported in meeting the air quality permit requirements. A very slight

haze was visible in the plume leaving the plant’s stack, which is typical of plants that use

NH3 injection for NOx control. In July 1996 the plant obtained approval to reuse its ash in

asphalt or concrete mixtures; treatment methods to allow the ash to be marketed in this way

are being evaluated. Presently, ash is disposed of in the landfill.

Economic Information

Detailed economic information was not provided. The power sales agreement with the

utility is an arms-length transaction for peaking power. To generate a profit on the plant’s

operation, Wheelabrator Ridge Energy must obtain net revenues from the tipping fees it

charges for wood wastes and scrap tires, and must hold its O&M costs to an absolute

minimum.

Tipping fees charged by the plant for wood wastes are quite low—$5/t for wastes that

require a minimum of processing and $12.50/t for more difficult-to-process wood wastes.

For comparison, Polk County owns and operates two class 1 landfills and one C/D landfill

(which send about 41,000 t/yr of brush to the Ridge Generating plant). The Polk County

landfills charge tipping fees of $44/t for household garbage and $25/t for yard waste or

C/D debris. The BFI Cedar Trails Landfill in Polk County receives mostly C/D debris (and

sends about 10,000 t/yr of clean wood waste to the Ridge Generating plant). The BFI

landfill tipping fees are $15/t for C/D debris and $18/t for yard waste. These data indicate
111

that the Ridge Energy plant sets its tipping fees significantly lower than the landfill tipping

fees in the area to attract wood wastes. The tipping fees of $5/t and $12.50/t are probably

very close to the actual cost of grinding, screening, and blending the wood wastes in Ridge

Energy’s fuel yard. The plant purchases no wood fuel, although it does pay the transport

cost for some wood waste suppliers within a 50-mi radius.

The $60/t tipping fee charged for scrap tires probably provides the plant a significant net

revenue stream. The tire shredding system at the plant is a fairly simply one, producing

approximately 3-in. pieces, with no wire removal.

Overall, the net fuel cost must be very close to $0/MBtu as the three fuels enter the boiler.

Lessons Learned

The contractual and business arrangements used by the Ridge Generating Station provide a

good example of a likely niche for biomass power: an urban wood waste recycling

operation. The primary product is electric energy, marketed to the utility (or in the future, to

the power exchange) mostly during peak hours. Urban wood wastes constitute the

primary, but not necessarily the only fuel. Other opportunity fuels (tires and landfill gas at

Ridge; petroleum coke, waste oil, and asphalt shingles at other plants) can provide higher

tipping fees and have HHVs. Depending on regulatory definitions and market prices, the

fuel mix might be controlled so the electricity will qualify as green power and command a

premium price.

The important concept illustrated by Ridge Generating Station is that of a waste recycling

facility, versus the concept of a power plant buying biomass fuel. The fuel manager does

not buy BDT of fuel under long-term contracts and does not force suppliers to meet strict

fuel quality specifications. He works within the local and regional waste management

infrastructure to provide a low-cost recycling service to waste generators, and to provide a

free or negative-cost fuel mix to the plant for energy production.

To operate this way, a plant must be designed for maximum fuel flexibility. This includes

the plant’s fuel processing and feeding systems, combustion system, air quality permit,

and emissions control systems. The Ridge fuel yard can handle essentially any type or size

of wood waste; its only restriction is that it will not accept palm trees. The simple and

reliable traveling grate stoker boiler can burn these mixed wood wastes, including yard

wastes, and can burn crude TDF and landfill gas. This combustion system, unlike other

good candidates such as fluidized beds, does not require more expensive processing to

remove wire from TDF. The emission control system with NH3 injection for NOx control

and a lime spray dryer and baghouse can remove almost any significant pollutant in these

wastes. In the future including a selective catalytic reduction unit for really low NOx

emissions may become standard, especially in large urban areas where these types of

biomass plants will be most useful and economical.

Another key to success for an urban wood waste power plant is location. Ridge has some

pluses and minuses in this regard. Two negatives are the 40-70 mi distance from really

large metropolitan areas, and the lack of direct freeway access to the plant site. The location

next to a landfill is a positive for several reasons: the landfill gas, the relatively easy

permitting, and the fact that waste hauling trucks were already commonplace on the local

roads. Finding suitable sites and obtaining permits for similar plants in the immediate
112

Tampa or Orlando areas might be significantly more difficult. If it could be done, however,

the net revenue opportunities from waste fuels would be improved.

Sources and Contacts

Phil Tuohy, the plant’s fuel manager, provided most of the information in this section. A

brief description of the plant was contained in the SERBEP Update newsletter for August

1997. Information on Florida’s WTE industry was obtained from Solid Waste

Management in Florida, June 1998 , an annual report published by the Florida Bureau of

Solid and Hazardous Waste. Information on urban wood wastes in the Lakeland-Winter

Haven metropolitan area was collected by the author as part of a study on urban wood

wastes around the United States.

Phil Tuohy

Fuel Procurement Manager

Wheelabrator Ridge Energy Inc.

3131 K-ville Avenue

Auburndale, FL 33823

Phone: 941-665-2255, ext. 112 Fax: 941-665-0400
113

GREENIDGE STATION (COFIRING),

DRESDEN, NEW YORK

________________________________________________________________________

New York State Electric and Gas (NYSEG) began a cofiring test program at the

Greenidge Station in 1994, using a separate wood fuel feed system to size and feed wood

wastes to a PC boiler. The tests were successful and economics looked promising, so

NYSEG began cofiring wood on a sustained, commercial basis at the end of 1997. During

1998, the 108-MW coal-fired boiler (Unit 4) consumed about 11,000 t of wood wastes,

which provided about 5% of the boiler’s heat input. A new hammermill will be installed in

early 1999, to allow the level of cofiring to be maintained at 10% of boiler heat input. This

will be equivalent to about 11 MW from wood wastes. In March 1999, the plant will have

a new owner, AES Corporation, which won a bid in August 1998 to acquire all six of

NYSEG’s coal-fired plants in New York.

Vital Statistics

Configuration Tangentially fired PC boiler

Wood Coal Total

Design capacity, net MWe 10.8 97.2* 108

Fuels, % by heat input 10 90 100

Net heat rate, Btu/kWh 11,000 9,818 9,936

Thermal efficiency, HHV, % 31.0 34.8 34.3

*108 MW when not cofiring wood.

History and Outlook

NYSEG’s cofiring work at the PC unit at Greenidge Station was initiated after the

company obtained positive results at some older stoker boilers. Greenidge Station in

Dresden, New York, is on the western shore of Seneca Lake. This is in the center of New

York, surrounded by farms, forests, vineyards, and orchards. The 108 MW Unit 4 came

on line in 1953. (Units 1 and 2 are retired and Unit 3 was brought back on line from

reserve standby in July 1998.) The relatively small plant size (for a PC boiler), the

upgraded electronic boiler controls, and continuous emissions monitoring systems made

Unit 4 ideally suited for testing and research.

The wood fuel feed system was installed and ready to receive fuel by mid-October 1994.

On October 25, a test burn was started using the separate fuel feed system. On October 27,

after some mechanical and electrical changes were made, the system functioned very well.

An even and constant fuel feed was obtained and steady combustion results were observed.
114

Several more years of testing and demonstration followed. By late 1997, the wood cofiring

system was running routinely. Most of the original test equipment had been replaced with

more permanent equipment, although the hammermill was an antiquated unit, designed for

3 t/h but operating at 7-8 t/h. The plant consumed 11,120 t/yr of wood wastes in 1998, and

produced about 5-6 MW. A new 15 t/h hammermill will be installed in 1999, allowing the

plant to run with about 10% heat input from wood fuel.

As summarized by Wally Benjamin, the NYSEG engineer who supervised the test

program, “The Greenidge plant receives wood residues from a variety of wood processing

industries, including furniture manufacturers. The plant burns 600 to 1200 tons of wood

per month, which allows the plant to produce 5 to 10 MW, or 5 to 10 percent, of its power

from wood. The fuel arrives at 2 to 3 inches maximum size and is ground at the plant to

less than 1/4 inch. Moisture levels vary from 10 to 40 percent, creating Btu levels from

4500 to 8000 Btu/pound.”

Plant Flowsheet and Design Information

Greenidge Station

Cooling Cooling

water water

(Seneca Cooling water Condenser

Lake) pumps

Deaerator Condensate

and

feed pumps

Turbine Electricity

Boiler Steam generator 108 MW

 feed 1465 psig water 1005 deg F Flue gas

Coal

Wood

wastes Wood fuel Tangential Cyclone

preparation PC & ESP

and feeding boiler

 Ash Fly ash Stack Combustion air
115

Boiler

The Combustion Engineering tangentially fired boiler is rated at 665,000 lb/h of steam at

1465 psig and 1005°F.

Boiler Modifications for Cofiring

Designs for retrofitting the plant to cofire biomass were based on the boiler receiving, via a

separate fuel feed system, wood products reduced to a top size of 1/8 in. for burning in

suspension. This method was selected because other utility experience with mixing wood

with coal and then reducing its size in the pulverizers showed that, at 5% wood or more by

weight, the mills lose efficiency, which affects the coal sizing. Other advantages to using

the separate fuel feeding system are the ability to quickly change the blend of alternative

fuel being fired to match various operational needs, and that it can be designed to feed

wood at much higher rates than could be fed through a coal pulverizer.

The boiler can maintain full load with one burner out of service. Therefore, a burner port

was chosen as the best test option for installing a separate fuel feed system. Removing a

coal burner and installing the wood fuel pipe took no more than 2 h with essentially no

impact on the boiler. A slide gate shutoff valve isolated the wood fuel system from the

boiler combustion when the wood fuel system was not in operation.

Wood Fuel System

The system installed for initial testing had a capacity of 7.5 t/h of wood waste fuel. The fuel

could be fed to the first screw conveyor via loader or walking floor truck trailer. A 2-in.

screen over the No. 1 screen limited oversized material from the system. The No. 1 screw

controlled the fuel feed rate via a variable speed controller. Conveyor 1 fed the constant

speed screw conveyor 2. Screw conveyor 2 discharged to a rotary airlock feeder. The

airlock fed the fuel to the pressurized 6-in. fuel transport line. The fuel transport line

(running at 3 to 5 psig) moved the fuel to burner 2 in the northwest corner of the boiler.

The velocity in the transport system is approximately 100 ft/s; it is powered by a 50 hp

blower moving 1450 cfm.

Emissions Control

The plant has an ESP for fly ash removal.

Fuels

The fuel sources used for initial testing come from the sawmill industry. The sawdust was

delivered on walking floor trucks in loads of 15-23 t. The trucks were unloaded directly to

the fuel feed hopper. There is some competition for sawdust because dairy farms use it for

bedding and pellet fuel manufacturers use it to fuel pellet wood stoves.

The hardwood market in New York State escalated during the late 1990s, with an

increasing price structure. One local lumber company expanded the production of one of its

sawmills from 7 million to 15 million board ft/yr. This company supplied the fuel for the

initial test program at Greenidge Station, and expressed very strong interest in supplying

sawdust to the Greenidge Station at a cost of $10/t ($0.92-1.00/MBtu). A fuel survey by

NYSEG staff found 30,000-45,000 t/yr of wood wastes available in the local area from

furniture manufacturers and lumber mills. The New York State DEC forestry section
116

estimated that 632,000 t/yr of sawmill residue are generated within a 50-mi radius of

Greenidge Station.

Large lumber producers and furniture manufacturers expressed the desire for a steady

long-term outlet for their wood wastes. They are also motivated by a desire to find an

environmentally sound method of waste disposal. In early 1999, nearly all the plant’s

wood supply was coming from two furniture manufacturers.

Greenidge Station has tested small quantities of willow chips obtained from the State

University of New York College of Environmental Science and Forestry plantation in

Tully, New York.

Impact of Cofiring on Plant Efficiency

The net plant heat rate when the boiler is running on 100% coal was measured at 9818

Btu/kWh in 1994. Calculations indicated that at 10% cofiring, the plant heat rate would

increase by about 1%-1.5%. This would increase the heat rate for the wood/coal blend to

9916-9965 Btu/kWh, and would mean that the heat rate for the wood fuel alone would be

about 10,800-11,300 Btu/kWh.

Operating Experience

Initial testing proceeded with little or no difficulty. However, a test with green wood (white

oak) sawdust was terminated after only 7 t had been run because long, stringy pieces of

wood bridged the burner deflectors. This caused excess pressure buildup in the wood fuel

system. All other portions of the transport system handled this material very well. A 15-t

load of kiln dried material transported and burned so well that 9 MW of output were

produced from the test system. After the initial tests, the protocol was revised so the

system output was held at 90-92 MW by reducing coal input as wood fuel was fed to the

boiler. The objective of holding constant output was to compare SO2 and NOx readings.

Environmental Performance

During all the testing at Greenidge, readings of NOx at the boiler control room continuous

emissions monitor (CEM) indicated decreases of 0.2-0.6 t/d. The SO2 readings decreased

from 798 to 750 ppm (70 lb/h).

The coal used at Greenidge Station during the 1994 test program had 1.48%-1.64% sulfur.

The sulfur content of the wood waste burned was 0.01%-0.04%. Calculations of potential

SO2 reductions for a 10% heat input cofire indicate that 600 t of SO2 can be saved per year,

based on 200,000 t of fuel combusted at Greenidge Station with current coal quality.

Operation of the ESP was not affected by the addition of the wood fuel. Stack opacity

remained at pre-test levels of 9%-14%.

A significant environmental benefit of cofiring involves reducing CO2 emissions to

mitigate greenhouse gas. On average, displacing 1 MW of coal-fired generating capacity by

biomass feedstock offsets about 6000 t/yr of CO2 . Thus, when Greenidge Station reaches

the 10% cofiring level as planned in 1999, it will offset about 65,000 t/yr of CO2.
117

During initial testing, the fly ash analysis for loss on ignition increased during wood

cofiring to 3.1%-4.3%, from a coal-only range of 2.8%-3.8%. Samples of the fly ash were

tested for concrete strength comparison and fineness. No apparent problems were

identified; no adverse affects were seen in the fly ash that would make it unmarketable.

Economic Information

Based on the Greenidge experience, the retrofit of a PC unit will cost approximately $300-

500/kW. To justify cofiring projects on strictly economic grounds, the wood waste fuel

must provide a large enough cost saving (per Btu) compared to coal to pay off this

investment in a reasonable time.

Economic cases in the NYSERDA report (see references at end) had capital costs of

$1.5 million to $3.2 million. Coal at 13,000 Btu/lb costs $36/t, and wood at 5400 Btu/lb

(35% moisture) and 8500 Btu/lb (7% moisture) costs $10/ton. Project payback periods

were 5-11 years.

The delivered fuel prices at Greenidge Station are equivalent to $1.38/MBtu for coal, and

$0.59-$0.93/MBtu for wood, depending on moisture content. The difference between the

coal and wood prices is $0.45-$0.79/MBtu. This is a substantial difference, and indicates

the likelihood of favorable economics for cofiring at Greenidge Station. EPRI studies

indicate that for cofiring to be economical, biomass fuel must be delivered at a price $0.25-

$0.40/MBtu below the price of coal.

Lessons Learned

The cofiring experience at Greenidge Station demonstrates that a separate fuel feed system

can effectively feed wood wastes to a PC unit. The economics at this site are favorable, and

the plant has continued to cofire wood and invest in system improvements since the testing

began more than 4 years ago.

As stated by Wally Benjamin, NYSEG engineer: “The technology for wood waste size

reduction and drying is available today; however, the energy required for the process is

higher than desired. Processing and drying techniques need further economic evaluation,

research and development. Fuel can be obtained with a 2-in. nominal size from whole tree

chippers and wood processors. Grinders do not normally produce a product that has good

flow characteristics. The wood fibers are sticky, stringy, and elongated when produced

from a grinding operation. The fuel product needs to processed by equipment that produces

a chip. A stoker or cyclone boiler can burn 2-in. chips with limited or no modifications. To

burn a 2-in. chip in a pulverized coal unit is not possible without the addition of a grate

system.”

Testing at the Greenidge Station indicated that a wood product of less than 1/4-in. diameter

is desired, and that the primary particle size distribution should be 1/8 in.-1/16 in.
118

Sources and Contacts

Most of the information in this section was obtained from two reports prepared by Wallace

Benjamin, P.E., of NYSEG:

• “Building Biomass into the Utility Fuel Mix at NYSEG: System Conversion and

Testing Results for Greenidge Station,” presented at BIOENERGY ‘96, Nashville,

Tennessee, September 15-20, 1996.

• “Renewable Wood Fuel: Fuel Feed System for a Pulverized Coal Boiler,” prepared

for NYSERDA, January 1996.

Additional information was obtained from an article by Raymond Costello of the U.S.

Department of Energy entitled “Biomass Cofiring Offers Cleaner Future for Coal Plants,”

in Power Engineering , January 1999. Updated information was obtained from Wally

Benjamin and other NYSEG employees during a site visit in November 1997, and from

plant manager Doug Roll and cofiring project manager Dick Bentley in February 1999.

Dick Bentley

cofiring project manager

Greenidge Station

590 Plant Road

P.O. Box 187

Dresden, NY 14441

Phone: 315-536-2359 ext. 211 Fax: 315-536-8545
119

CAMAS COGENERATION PLANT AT FORT

JAMES CORPORATION PAPER MILL,

CAMAS, WASHINGTON

________________________________________________________________________

The Camas paper mill, on the north side of the Columbia River 15 mi east of Portland,

Oregon, has a cogeneration plant that consists of five boilers: three high-pressure recovery

boilers burning black and red liquor, one hog fuel boiler burning wood residues, and one

power boiler burning natural gas. Fort James Corporation owns the mill, provides the fuels

to the boilers, and uses the steam that is extracted or exhausted from the steam turbine at

three pressure levels. The hog fuel boiler is owned by NRG Energy, Inc., which acquired

the boiler as part of its acquisition of Pacific Generation Company from PacifiCorp. The

cogeneration plant operates at the level required to satisfy the mill’s steam requirements

(typically about 1,200,000 lb/h), and PacifiCorp takes all the electricity generated (typically

about 40-48 MW).

Vital Statistics

Configuration - 5 boilers Kraft recovery (2) 1975, 1990

Magnefite 1971

Natural gas 1963

Hog fuel/gas 1992

Steam production, lb/hr 600 psig 1,200,000

Steam to mill, lb/h 150 psig 460,000

75 psig 210,000

40 psig 370,000

Electricity to grid, MWe 1998: March July

47.5 38.5

Design capacity, net MWe 52.2

History and Outlook

The Camas mill, originally built by the Columbia River Paper Company starting in 1883,

produced the first wood pulp manufactured in the Northwest United States in 1885. In

1910 the Crown Columbia Paper Company doubled the capacity of the mill to

4 million lb/yr. In 1913 the mill changed to electric power. In 1914 Crown Columbia

merged with Willamette Paper to form Crown Willamette, the second largest papermaker

in the world. In 1928 Crown Willamette merged with Zellerbach Paper to become Crown

Zellerbach. A $425 million modernization of the mill was completed from 1981 to 1984.

In 1986 the mill became a subsidiary of James River Corporation of Richmond, Virginia.

In 1992, James River and PacifiCorp completed a 3-year, $80 million energy and recovery
120

modernization designed to increase energy efficiencies and reduce emissions. This included

the construction of the hog fuel boiler, which PacifiCorp owned. At that time, the mill did

not have electric generating capability; it was a customer of PacifiCorp, buying

approximately 70 MW of electricity to power the mill.

In January 1993, PacifiCorp and James River announced a project to cogenerate electricity

by installing a steam turbine/generator and associated equipment. Construction began in

March 1994. The $53 million plant was finished on time in 1995 and $9 million under

budget. James River managed the construction and operates the cogeneration plant. The

electricity generated is measured and PacifiCorp pays James River for it in the form of a

royalty for the steam.

In August 1997, James River Corporation merged with Fort Howard Corporation to form

Fort James Corporation, the current owner of the Camas mill. In November 1997, NRG

Energy, Inc., acquired Pacific Generation Company from PacifiCorp. This acquisition

included the hog fuel boiler in the Camas mill, along with 11 other projects with a total

capacity of 776 MW in five states and Canada. NRG identifies the hog fuel boiler as the

Camas Power facility, and describes it as a 25-MW facility that uses hog fuel and natural

gas as fuels.

The current business arrangement is that Fort James Corporation owns the 185-acre paper

mill and four of the five boilers in the mill’s cogeneration plant. NRG Energy, Inc. owns

the hog fuel boiler. The mill operates all the boilers, the turbine/generator, and the steam

distribution system throughout the mill. The Magnefite boiler and the two Kraft Recovery

boilers operate at the levels required to dispose of all the red and black liquor produced.

They generate significant amounts of steam in the process, but not enough to satisfy the

mill’s total steam demand. The hog fuel boiler and the natural gas boiler operate at the

levels required to fulfill the mill’s steam requirements. All the boilers can burn natural gas,

and all but the hog fuel boiler can burn bunker C fuel oil.

Plant Flowsheet and Design Information

The block flow diagram on page 137 shows the overall arrangement of the Camas mill

cogeneration facilities. The flow rates of steam and the electricity production vary with

process needs in the mill, and with the weather (generally higher during the winter than

during the summer). The values shown on the diagram are rounded off from those

observed during a visit to the plant on August 18, 1998.

To give an idea of the equivalent size of this facility, if all 1,200,000 lb/h of steam were

being condensed in a turbine generator to produce only electricity, it would generate about

90 MW. The hog fuel boiler, if it were operating at its rated capacity of 220,000 lb/h of

steam while firing 100% wood, would be able to generate about 17 MW. At the steam

generation rate on the diagram (140,000 lb/h), the hog fuel boiler would generate about 11

MW if it were supplying a condensing turbine/generator producing only electricity.

In the Camas mill, none of the steam is condensed in the turbine generator. All the steam

goes to process uses in the paper mill, and is condensed during or following those process

uses. Steam is extracted from the turbine at 150 and 75 psig, and the remainder is

exhausted from the backpressure turbine at 40 psig. The production of electricity, and the

revenue it provides to the mill, is strictly a side benefit. Before the turbine/generator set was
121

installed, the plant flowsheet looked nearly identical, with pressure letdown valves

controlling the amounts of steam going to the 150, 75, and 40 psig levels instead of a

backpressure turbine. Even with the low power costs in the Pacific Northwest, PacifiCorp

and James River Corporation apparently projected an attractive rate of return on the

investment in the turbine generator system when they planned the project in 1992.

Camas Cogeneration Plant

Flue gas

 Kraft

 black #3 Recovery 275,000

 liquor boiler (Kraft) lb/hr

Ash BFW Flue gas Steam

600 psig

 Kraft 750 deg F

 black #4 Recovery 375,000

 liquor boiler (Kraft) lb/hr 150 psig steam

Flue gas Ash BFW 460,000

lb/hr

Magnefite

 red Magnefite 230,000 1,160,000 Turbine Electricity

 liquor boiler lb/hr lb/hr generator 40 MW

Ash BFW Flue gas 210,000 370,000

lb/hr lb/hr

 Hog fuel

#3 Power 140,000 75 psig 40 psig

 Natural gas boiler lb/hr steam steam

Flue gas Ash BFW

 Natural

 gas #4 Power 140,000

boiler lb/hr

 BFW
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Hog Fuel Boiler

Foster Wheeler Corporation provided the hog fuel boiler, a single unit in which hog fuel is

burned on a Detroit Hydrograte water-cooled vibrating grate (“shaker grate”). This grate

spreads the fuel when it vibrates every minute or two, so small piles on the grate are

leveled out. The fuel is mechanically distributed by screw feeders and moved gradually

down the sloped grate to the rear of the furnace, where ash is discharged. The rated capacity

of the boiler on 100% hog fuel is 220,000 lb/h of steam (600 psig, 750°F). When firing a

combination of hog fuel and natural gas, the boiler can produce about 240,000 lb/h.

A water-cooled vibrating grate has some advantages over a traveling grate that is cooled by

the flow of primary combustion air through the grate:

• The grate has fewer moving parts and consequently requires less maintenance.

• Higher primary air temperatures are possible, allowing the use of higher-moisture

fuels.

• Fuel/air ratio, as well as velocity, at the grate can be maintained at the optimum

levels for control of NOx formation, carbon burnout, and particulate carryover.

Fly ash is separated from the flue gas leaving the boiler in a series of multiclone separators

followed by an ESP. Combustion controls keep the NOx emissions well within permit

levels without NH3 injection. Fly ash from the plant is used as a liming agent (soil

amendment) on fields around the area.

Fuel

The fiber supply department, which buys the pulp chips for the mill, also buys hog fuel.

The current market price for hog fuel in the Portland area is about $8/dry t. Trucks carrying

hog fuel enter the mill property and drive to the hog fuel yard, where truck dumpers

discharge the fuel. There is no screening, grinding, or other fuel preparation equipment in

the hog fuel yard. Bulldozers with large blades manage the fuel piles. A long conveyor belt

carries the hog fuel to the boiler building, where magnetic separators remove any metal

contamination before the fuel enters the feed system to the furnace. The distance from the

fuel yard to the hog fuel boiler is at least a mile.

Turbine/Generator

The steam turbine has two extraction levels (150 and 75 psig) and exhausts the remaining

steam to the mill’s 40-psig steam system. Its nominal rating for electricity production is

52.2 MW. The generator is a GE air-cooled unit that is rated higher than 52 MW as a

future consideration.

Operating Experience

The hog fuel boiler and turbine generator have run very reliably since they were started up.

As in any industrial process plant, the steam supply must be available with high reliability,

typically 330 or more d/yr. The redundancy inherent in the Camas cogeneration plant with

five boilers, each capable of burning multiple fuels, enhances the overall reliability and

flexibility of the system to meet operating demands.

Environmental Performance

No mention was made of any difficulties in controlling emissions to design limits or

complying with permit requirements.
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Economic Information

No specific economic information was provided, except that a PacifiCorp press release in

January 1996 mentioned that “the $53 million plant was finished on time and $9 million

under budget.” The press release did not state exactly what the scope of the “plant” was,

but it is presumed to include the hog fuel boiler and the turbine/generator set. If the hog fuel

boiler is considered equivalent to a 23-MW plant as discussed earlier, $53 million would

be about $2,300/kW.

In the visitor’s lobby of the paper mill, a document entitled A Capsule History of James

River’s Camas Mill is available. It mentions that in 1992 “the mill completed a three-year,

$80 million energy and recovery modernization designed to increase energy efficiencies

and reduce emissions.” This may include the $53 million referenced by PacifiCorp, but

that is not certain.

Operating and maintenance costs for the hog fuel boiler are probably similar to costs for

similarly sized stand-alone wood-fired plants, except that the paper mill can probably

spread some of its O&M, engineering, and management staff over a number of units or

functions within the mill and achieve some economies. Hog fuel cost fluctuates with the

market, but is probably now about $0.50/MBtu.

Power costs in the Pacific Northwest are very low because of the predominance of

hydroelectric generation, so the price PacifiCorp pays for the electricity from the plant

(which is actually paid in the form of a royalty for the steam) is presumably quite

low—probably about 1¢/kWh or less. Still, this represents a significant cash flow to the

paper mill. Assuming the mill generates about 300 million kWh/yr, and receives the

equivalent of about 1¢/kWh in royalty payments, the cash flow generated by the electricity

is about $3 million/yr.

Lessons Learned

The business arrangement used in this project may provide a useful model for future joint

venture cogeneration projects involving electric utilities and paper mills. Although there

have been several changes in ownership and company names because of mergers and

divestitures during the short time the Camas cogeneration plant’s business arrangement has

been in place, there are really only two primary participants: the paper mill and the electric

company. Each has its unique perspective, goals, and risk/reward scenarios.

The electric company undoubtedly regards the paper mill as a very important major

customer, one that consumes about 70 MW at a fairly steady rate year round. Assisting the

paper mill with its cogeneration project is an important customer service provided by the

utility; in return it receives a small amount of electricity (about 42 MW on average) at a

presumably low price. The greatest benefit from the cogeneration project to the utility is the

increased likelihood that the paper mill will continue as a customer and not become a selfgenerator.

The paper mill is strictly interested in making paper products profitably. It is not in the

energy business. Historically, the mill has bought electricity from the utility, and continues

to do so. As deregulation and restructuring of the electric industry continue, at some point

the mill may begin to shop around for the lowest-cost power. The mill’s primary concern
124

with its cogeneration plant is the reliable production of steam for process use. The utilityfinanced turbine/generator set provides the mill with an additional source of cash flow,

without changing the steam generation and delivery system within the mill in any

significant way.

This business arrangement appears to be sound for both parties. It is inherently stable and

simple. It may not be the lowest-cost way for the mill to obtain electricity, but the cost is

low enough and the supply is risk free. Lower-cost scenarios require the mill to go into the

energy business, where it has little expertise or clout. The utility has added about 50 MW

of reliable generating capacity to its system for a relatively small investment, and has

strengthened its relationship with a major customer.

Sources and Contacts

Gary Peterson and Todd Drenth of the Camas paper mill were very helpful in providing

information and a tour of the facilities. Additional information was obtained from a

“capsule history” of the mill, a PacifiCorp press release dated January 23, 1996, and a brief

project description on the NRG Energy, Inc. Web site (www.nrgenergy.com).

Gary Peterson

Fort James Corporation

Camas Mill

Camas, Washington

Phone: 360-834-8352

Fax: 360-834-8200
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SNOHOMISH COUNTY PUD/KIMBERLY-CLARK

CORP., EVERETT, WASHINGTON

________________________________________________________________________

Snohomish County Public Utility District (PUD) (Snohomish) and Kimberly-Clark

Corporation have a 43-MWe cogeneration facility at Kimberly-Clark’s paper mill in

Everett, Washington. The cogeneration plant consists of a new wood waste-fired boiler that

generates as much as 435,000 lb/h of steam and a recovery boiler that generates about

276,000 lb/h of steam. A new steam turbine extracts steam at the rates required to satisfy

the mill’s requirements (typically a total of about 500,000 lb/h of 300 psig and 40 psig

steam), and a condenser condenses the remaining steam. The steam turbine drives an

electric generator that generates an average of about 38.5 MW. Snohomish sells most of

the electricity to the Sacramento Municipal Utility District (SMUD) under a 10-year

contract.

Vital Statistics

Boiler Recovery boiler Existing

Wood waste boiler New (1995)

(Sloping grate)

Fuels: Mill residues

Urban wood waste

Steam production, lb/h (825 psig) 711,000

Steam to mill, lb/h (300 psig, 40 psig) 490,000-

560,000

Generation capacity, MWe 47

Electricity to grid, MWe 38.5 MW average

History and Outlook

Scott Paper used to burn some of its wood waste in five, 60-year-old, inefficient boilers to

provide process steam to its mill in Everett, Washington. Scott approached Snohomish to

determine whether there was an interest in working together to install cogeneration along

with boiler replacement. In October 1993 Snohomish and Scott agreed to install a turbinegenerator (rated capacities: extraction steam turbine, 46.9 MW; generator, 52.2 MW) and a

modern 435,000 lb/h boiler. Scott built the cogeneration plant; Snohomish financed the

capital costs ($115 million), owns the plant, and receives the electrical output. KimberlyClark acquired Scott Paper Company in December 1995 just as the new cogeneration

facility became operational. Kimberly-Clark operates and maintains the facility, pays for all

the fuel for 15 years, and receives steam for the paper mill, which produces tissue, paper

towels, and napkins. The cogeneration plant started initial operations in December 1995,

and entered full commercial operation in August 1996.
126

Snohomish contracted with SMUD to sell an average of about 33 MW through 2007. This

was done to eliminate any early-year rate impacts on Snohomish County PUD customers.

After the SMUD purchase period concludes, Snohomish intends to bring the power back

to serve local customers. Under terms of the contract, SMUD will purchase energy and

capacity at a levelized real rate of 4.1¢/kWh through September 2007. The first year rate for

energy was 3.3¢/kWh. The complicated PPA allows SMUD to purchase as much as 36

MW during summer and 26 MW at other times of the year. SMUD has the option of

storing a portion of the available winter capacity and energy and shaping it for summer

delivery. Summer scheduling is capped at 42 MW.

The Kimberly-Clark Everett mill is a retail customer of Snohomish County PUD, and

consumes nearly as much electricity as the cogeneration plant produces. On balance, there

is typically a small export of about 5 MW from the mill.

The sloping grate boiler was selected over more common stoker grate or fluidized bed

designs for two primary reasons: (1) the ability of this mass burn type boiler to handle a

wide range of fuel sizes, and thus eliminate the need for hogging and screening equipment;

and (2) the guarantee offered by Gotaverken (later Kvaerner) of very low NOx emissions.

Everett was in a nonattainment area for NOx at the time of permitting (it has since achieved

attainment). The availability of mill residues has been decreasing in the area; urban wood

wastes and land clearing debris are increasingly important components of the biomass fuel

stream. The combustion air staging that was designed into the furnace in an attempt to

reach the low NOx emissions created combustion problems that were ultimately solved by

operating the boiler at higher NOx emissions than originally permitted, and modifying the

older recovery boiler at the mill that brought the NOx emissions from the overall complex

into compliance.

Plant Flowsheet and Design Information

Boiler

The boiler is a screw-fed, sloping grate design by Gotaverken (now Kvaerner), based on a

mass burn design used in Europe and at a few locations in North America. At design

conditions, the 435,000 lb/h of 825 psig, 850°F steam from the wood-fired boiler is

combined with 276,000 lb/h of high-pressure steam from the mill’s recovery boiler

burning waste liquor. The condensing steam turbine drives the generator and produces

low-pressure steam (extracted at two pressure levels) for process use in the mill.

Steam Turbine/Generator

The GE extraction steam turbine has a rated capacity of 46.9 MW. Steam enters the turbine

at about 800 psig and is extracted at 300 and 40 psig. The generator has a rated capacity of

52.2 MW. The condenser normally condenses 150,000-220,000 lb/h of exhaust steam

from the turbine (the difference between the amount of steam generated in the two boilers

and the amount of steam used in the mill). However, the condenser can condense 350,000

lb/h of steam; this allows the wood-fired boiler to operate as a stand-alone power plant

when the mill is down. The capacity of the wood-fired power plant when operating in a

stand-alone electric generating mode is about 39 MW.
127

Fuel System

The plant has a fuel receiving and storage system that can handle wood wastes in a range of

sizes. Five groups of three screws each feed the wood wastes into the boiler.

Snohomish County PUD/Kimberly-Clark Corp.

Everett Cogeneration Plant

Flue gas

To process

 Waste #10 Recovery 276,000

 liquor boiler lb/hr

300 psig 490,000- 40 psig

Ash BFW steam 560,000 steam

lb/hr

Steam

825 psig 711,000 Turbine Electricity

850 deg F lb/hr generator 43 MW

Flue gas

BFW Condenser

 Wood #14 Wood 435,000

 wastes waste boiler lb/hr

Ash BFW Cooling tower

Emissions Control

NOx was initially controlled by staged combustion and NH3 injection. After addressing the

combustion problems in the unit and installing an NH3 injection system on the recovery

boiler, the wood-fired unit is now operated with different air staging and no NH3 injection.

Particulate control is achieved by a baghouse that was installed about 20 years earlier to

control particulate emissions from the old wood waste boilers. The baghouse was enlarged

to provide a higher air-to-cloth ratio for the flue gas from the new boiler.
128

Fuels

The fuel consists of: (1) mill residues, such as bark and hogged wood, supplied primarily

by mills located in Puget Sound, Olympic Peninsula, and British Columbia; and (2) urban

wood wastes such as pallets and land clearing debris. The urban wood waste, especially the

land clearing debris, increases during the summer. The fuel mix has been running about

40% mill residue and 60% urban wood waste during the summer, and a greater proportion

of mill residue during the winter. The long-term trend will be away from sawmill residues

as logging is reduced in the region. Generally, the land clearing operators operate tub

grinders at their sites and send the resulting fuel to the wood-fired plants in the area.

The plant has received permit authority to perform limited combustion trials on shredded

railroad ties.

Operating Experience

The plant’s electrical output was a little short of the contracted amounts during

commissioning. The boiler could not meet the guarantees on NOx emissions and carbon

carryover. Problems encountered during initial operations related primarily to the wide

variation in fuel types, sizes, and moisture content, which were addressed by improved fuel

blending in the yard, and by tinkering with the grate and with the feed systems. To comply

with the very strict NOx emission limit, excess amounts of NH3 were added to the flue gas

at times, causing a visible plume. By increasing the secondary (overfire) air injection rate to

increase turbulence, and by decreasing the NH3 injection rate, these problems were reduced.

The boiler can operate with 55% moisture fuel and generate 425,000 lb/h of steam,

compared to the design values of 60% and 435,000 lb/h. The operator keeps the fire line

backed up on the grate, and burnout occurs on the lowest part of the grate. When 60%

moisture fuel is received (during the rainy season, which typically peaks in January and

February), the auxiliary burner (natural gas) must be used.

About 2 years were spent modeling the combustion process, making changes in the boiler,

and working with the operating personnel, to adjust the systems and their controls so they

would perform as specified. Changes were made in air nozzle locations, grate design, and

other areas. The unit now performs well.

Environmental Performance

As discussed earlier, the unit could not meet the specified NOx levels, but its emissions are

still low. The permit was amended to allow higher NOx emissions than originally

specified, in return for installation of an NH3 injection system on the older recovery boiler

at the mill to reduce NOx emissions from that unit. Ammonia injection into the flue gas at

the wood-fired boiler was discontinued. The recovery boiler has a better profile than the

wood-fired boiler, so the reduction of NOx emissions by NH3 injection is much more

efficient in that boiler. All permit requirements are being met.

Economic Information

During the first 15 years of operation, the paper mill buys the fuel, operates and maintains

the facility, and uses the steam. The utility pays the capital cost (debt service) for the

original plant plus any capital improvements, supplies power to the mill, and sells the

electrical output to SMUD and its own customers. Starting in year 16, the utility will pay
129

an increasing portion of the fuel cost. Starting in year 20, the utility will also pay part of the

O&M cost.

The contract with SMUD for capacity and energy at a levelized real rate of 4.1¢/kWh

through September 2007 indicates that the cost of power from the cogeneration plant is

relatively low for a wood-fired plant. Still, after 5 years of high rainfall and with

deregulation working its way through the electric industry, wholesale rates for power in the

Pacific Northwest have been much lower than 4¢/kWh.

Lessons Learned

The plant design anticipated the trend toward declining quantities of sawmill residues, and

the increasing use of urban wood wastes in the region. Siting the plant at a paper mill

provided an excellent fit for steam use, as well as expertise in wood waste handling and

combustion. Wood-fired plants probably have to be cogeneration plants now to survive.

The design of the boiler did not live up to all its guarantees, but changes and compromises

successfully resolved the problems. Both the paper mill and the utility appear to be happy

with the project overall, and when asked, both said they would not have made different

decisions on major equipment selections if they were doing it again.

In fairness, the apparent emphasis here on the problems encountered with the combustion

system results mostly from the plants being in operation for only 2 years. Nearly all the

plants in this report had some difficult learning experiences during their first year or two of

operation. These initial difficulties usually fade into memories that seem less significant as

the years pass and other challenges to the project arise.

Sources and Contacts

Robin Cross

Cogeneration Project Manager

Snohomish County Public Utility District

P.O. Box 1107

Everett, WA 98206

Phone: 425-258-8481 Fax: 425-258-8640 rhcross@snopud.com
130

OKEELANTA COGENERATION PLANT,

SOUTH BAY, FLORIDA

________________________________________________________________________

The Okeelanta Cogeneration Plant is a 74-MW biomass cogeneration project located next

to the Flo-Sun Inc. Okeelanta Sugar Mill, 6 miles south of South Bay in Palm Beach

County, Florida. U.S. Generating Co. (USGen) and Flo-Energy Corp. (an affiliate of FloSun Inc.) joined together to construct and operate the facility. It is the largest

bagasse/biomass cogeneration plant in the United States. The plant provides process steam

and power to the Okeelanta Sugar Mill and Florida Crystals Refinery, and sells its excess

electricity to FPL. In 1997, the partnership filed bankruptcy and the plant shut down as a

result of a contract dispute with the utility; the plant resumed operation in February 1998.

Vital Statistics

Design capacity, net MWe 74.9

Process steam to sugar mill 1,320,000 lb/h

Configuration 3 water cooled vibrating grate stoker boilers

Fuels Bagasse (~6 mo/yr)

Wood wastes (urban, land clearing, construction)

Coal (boilers capable up to 40%)

History and Outlook

Flo-Sun, Inc. is a fully integrated sugar grower, producer, refiner, and marketer. In Florida,

the company farms more than 180,000 acres of land and produces about 65,000 t/yr of

sugar. Flo-Sun has a large sugar mill and refinery near South Bay, Florida, with old, small

bagasse-fired boilers. A subsidiary, Flo-Energy, joined with USGEN to construct and

operate the 74-MW Okeelanta Cogeneration Plant next to the Okeelanta Sugar Mill,

burning bagasse and wood wastes.

Bechtel Power Corporation constructed the plant under a lump-sum turnkey contract with

the Okeelanta Power Limited Partnership. USGen, through its affiliate, U.S. Operating

Services Co., was responsible for plant O&M. FPL contracted to buy the plant’s electricity

output for 30 years, and the Okeelanta Sugar Mill and Florida Crystals Refinery agreed to

take the steam output. At the same time, similar arrangements were made to build the 52-

MW Osceola Cogeneration Plant next to the Osceola Farms Sugar Mill near Pahokee,

Florida. The plants were financed, in part, through Palm Beach County Solid Waste

Industrial Development Revenue Bonds, which were originally issued in an aggregate

principal amount of $160 million for Okeelanta and $128.5 million for Osceola.
131

In 1991, FPL entered into 30-year PPAs with Okeelanta and Osceola. The contracts

provided that if the plants were not in commercial operation before January 1, 1997, FPL

had no further obligation. FPL contended that the plants did not meet this deadline, and

sued the Okeelanta and Osceola partnerships on January 8, 1997, to avoid its obligations.

On May 14, 1997, the partnerships that own the Okeelanta and Osceola plants filed for

Chapter 11 bankruptcy protection after FPL terminated an agreement that had frozen the

litigation. FPL’s general counsel said the utility acted in the best interest of its customers,

who, he said, were paying exorbitant prices to purchase electricity from the facilities. The

plants, he said, were plagued with problems; they had had breakdowns and missed a

January 1, 1997, deadline to become fully operational. He said the cost of purchasing

electricity from the plants is “80% to 100% more expensive than what we can get” from

other power sources or by generating the electricity. A spokesman for the plants’ owners

said that FPL’s description of the plants’ costs were “grossly inaccurate and misleading.”

The partnerships vigorously contested FPL’s claims.

On May 19, 1997, the Wall Street Journal reported that “several large mutual-fund

companies are bracing for what could rank as one of the largest defaults in municipal-bond

market history after two electricity generating plants filed for bankruptcy in Palm Beach

County, Florida.” According to the article, the default would be rivaled only by such

municipal bond disasters as the default of the Washington Public Power Supply System in

1983, New York City in the mid-1970s, and the 1994 bankruptcy filing by Orange

County, California.

On September 16, 1997, both plants were shut down and 96 employees laid off. FPL’s

planning documents show that Okeelanta had delivered 314,326 MWh to FPL up to that

date in 1997, and that Osceola had delivered 251,066 MWh. For Okeelanta this represented

about a 68% CF over the 8.5-mo period. In February 1998 the Okeelanta plant started up

again, under an interim agreement with its bondholders. USGen remains a member of the

partnership but chose not to continue as the plant operator. The plant is now operated by

Flo-Energy. As of February 1999, the Osceola plant is still shut down. The bankruptcy

proceedings for both plants are still ongoing.

The Okeelanta Cogeneration plant operates at the level of output required to satisfy the

sugar mill’s demands for steam and power. FPL no longer makes a capacity payment to

the plant, and pays for the electricity that enters its system based on as available energy

rates.
132

The key events in the Okeelanta cogeneration project can be summarized as follows:

PPA signed 1991

Financing completed January 1994

Construction started 1994

Construction 30% complete March 1995

Construction 70% complete May 1995

Startup August 1996

Commercial operation January 1997

FPL sues to break contract January 8, 1997

FPL terminates litigation standstill agreement May 9, 1997

Okeelanta Power LP files bankruptcy May 1997

Plant shut down September 16, 1997

U.S. Federal bankruptcy judge approves reorg.

plan allowing reopening one of the two plants

February 1998

Okeelanta plant restarts commercial operation February 1998

Plant Flowsheet and Design Information

Okeelanta Cogeneration Plant

Steam to sugar mill (1,320,000 lb/h)

 Condensate from sugar mill Deaerator

and

feed pumps Turbine Electricity

generator 74 MW

 Boiler Steam

 feed 1525 psig

 water 955 deg F Flue gas Bagasse from sugar mill

Wood

wastes Fuel Stoker

ESPs blending and boilers

preparation (3) (3)

 Bottom ash Fly ash Stacks (3) Combustion air

Construction in the Everglades

South Florida’s Everglades are noted as an endless swampland of muck, posing a serious

problem for any structure needing a stable base. The water table sometimes rises to within

inches of the surface. To stabilize the area, Bechtel excavated 6 acres of muck and replaced

it with 300,000 t of crushed limestone at the Okeelanta plant.
133

Fuel System

The sugar mill is 200 yd from the cogeneration plant. The support frame for the conveyor

that sends bagasse to the cogeneration plant also supports the steam and condensate

lines—a 36-in. low-pressure steam line, a 14-in. high-pressure steam line, and an 8-in.

condensate line. The bagasse and residue from freshly ground sugar cane are sent to the

boilers by conveyor belt. The design rate is 2740 t/d. Two 6-ft-wide

dragchains—positioned across the entire boiler building—then distribute the material to

each boiler via feeders. Because the low density fuel is fibrous, stringy, and abrasive, a

vibratory tray feeder was selected over a conventional screw feeder because:

• The screw auger would have to be replaced annually.

• Horsepower to drive the screw feeder is high.

• The operator has to make adjustments to a screw feeder each time he has to switch

from bagasse to wood, or vice versa.

• The screw feeder precludes the potential of burning both fuels simultaneously.

The material handling system overfeeds the boilers; the excess fuel is stacked in the yard

and reclaimed as needed. Wood waste is received and processed in a typical fuel yard. Like

the bagasse, wood waste is also unloaded and stacked by the conveyor.

Boilers

The plant has three ABB Combustion Engineering stoker-fired boilers with staged air and

urea injection control NOx emissions. Each generator is designed to deliver 440,000 lb/h

of steam at 1525 psig and 955°F at the boiler outlet. In addition to burning bagasse and

wood chips, the boilers can burn coal as high as 40% of heat input at maximum continuous

rating. The stoker boilers have water-cooled vibrating grates. Strategically located overfire

air jets provide turbulence and thoroughly mix the fine fuel particles and air to ensure

complete combustion and NOx control.

Each furnace provides continuous ash discharge via an advanced design spreader stoker

that burns coal, biomass, and other solid waste fuels—specifically, low-Btu, high-moisture

waste fuels. The water-cooled ash discharge grates combine water cooling protection of the

grate surface with intermittent grate vibration to move the fuel bed forward through the

furnace; ash is automatically discharged off the forward end of the grates. Higher

combustion air temperatures needed to completely burn out the high moisture fuel can be

maintained without concern for damaging the grates. Nine under-grate air plenums

optimize air flow distribution to various areas of the furnace.

Biomass enters the furnace through pneumatic fuel distributors located on the furnace’s

front wall. They disperse the fuel uniformly into the furnace. Fine particles of fuel entering

the furnace are burned in suspension. Strategically located high-pressure overfire air jets

provide turbulence and thoroughly mix the fine fuel and air to ensure complete combustion

and NOx control. The coarser, heavier fuel particles are spread evenly on the grate, forming

a thin, fast-burning fuel bed. The fuel is rapidly consumed by the combination of

suspension and thin fuel bed burning, which makes this method of firing responsive to

load demand.

Emissions Control

To meet the stringent NOx emissions requirements of 0.15 lb/MBtu while firing bagasse,

wood waste, or a combination of both, each boiler incorporates a tangential overfire air

system with undergrate air and a selective noncatalytic reduction (urea injection) system.
134

The overfire air system comprises five elevations of tangential air registers and one

elevation of nozzles located above the grate on the rear wall of the unit. A boost fan

increases air pressure, thus providing proper penetration of air flow into the furnace and

turbulent mixing of overfire air with combustion gases coming up off the grate.

Introduction of overfire air at five elevations reduces NOx and CO production by staging

combustion, increasing residence time, and thoroughly mixing the flue gas. When firing at

reduced loads, separate elevations of overfire air can be shut off to maintain the velocities

required to ensure complete mixing of the flue gas. The selective non-catalytic reduction

(SNCR) system trims NOx emissions. The urea-based system includes two levels of

injection, each of which consists of six injectors located on all four walls to accommodate

temperature and mixing profiles in the flue gas.

Three ABB Environmental ESPs, one per boiler, remove PM from the stack gas. Each

ESP has three fields in series and is designed for outlet emissions of 0.03 lb/MBtu when

the boiler is firing 100% bagasse, 100% wood waste, or a combination of the two fuels.

The ESPs’ spiral electrodes are hung in a rigid frame with nominal 16-in. collecting plate

spacing. This wide plate spacing is an economical design and is particularly well suited to

biomass applications.

Because of the relatively high content of carbon in the ash, the risk of fire damage to the

ESPs is a common problem with boilers firing biomass. As a result, the ESPs were

designed with three specific features to reduce the risk of fire damage:

• Induced draft fans located upstream of the ESPs, to ensure the units operate at

positive pressure, reducing the risk of ambient air in-leakage that could support

combustion.

• Trough-type hoppers equipped with screw conveyors to remove fly ash

continuously.

• High intensity tumbling hammer rappers to keep the collecting plates free of

potentially combustible material.

Each ESP has its own 225-ft-high, 10-ft-diameter stack mounted directly over the outlet

plenum. Given the upstream ID fan location and that the ESP roof elevation is nearly 90 ft

above grade, the ESP-mounted stacks represent significant cost and space savings over a

conventional free-standing stack arrangement at grade.

Staffing

At peak construction, approximately 350 jobs were created. The Okeelanta Cogeneration

plant was planned to have 34 full-time employees. Another 80-90 workers process and

transport the fuels.
135

Fuels

Each year, about two-thirds of the total fuel requirements are met by bagasse, and the

remainder by wood waste. The sugarcane harvesting and grinding season lasts about

6 months, from October through late March or early April. Bagasse cannot be stored for

long times without deterioration of its fuel value, so many bagasse-fired cogeneration

plants rely on a supplemental fuel such as wood waste or coal during the off-season when

bagasse is not being produced as a by-product of the sugar mill. The fuel at the Okeelanta

Cogeneration plant is not dried before combustion.

Wood wastes used as fuel at the plant include urban wood wastes, land clearing wood

wastes, and some construction debris. One type of wood waste is melaleuca, a pest tree

that threatens to overwhelm the everglades. Melaleuca trees, which soak up about 50 gal of

water a day, were imported decades ago from Australia to dry out land in the Everglades to

make it buildable. The gnarly trees have successfully taken root and smothered native

vegetation. They have no native predators. When cut down, they grow back. When burned,

their seedlings spread, giving birth to yet more trees. They burn well in the Okeelanta

boiler, and the plant now receives as many as 10 truckloads a day from land clearing

activities in the Everglades. Since 1990, the South Florida Water Management District has

cleared more than 6 million melaleuca trees and 22 million seedlings from Everglades

National Park and from water conservation and wildlife management areas. Until the

Okeelanta Cogeneration plant started operating, the district had no options other than to

haul melaleuca to the landfill or burn it on site.

Operating Experience

Early operations (late 1996 into summer 1997) at Okeelanta were described by a former

employee as “up and down,” mostly because the contractor “did not build the plant well.”

Fuel quality problems were experienced with some wood wastes. It was difficult to find

enough good-quality wood wastes in the area.

From February 1998 to February 1999 the Okeelanta plant has run at a steady rate as

required to meet the sugar mill’s energy demands. The Okeelanta sugar mill and refinery

have no off season. They run year round except for scheduled maintenance shutdowns,

processing extract from cane and processing sugar. No details on the Okeelanta

Cogeneration Plant’s steam or electricity production levels during 1998 were made

available.

Environmental Performance

Annual aggregate emissions levels are about 75% less than previous levels produced by the

sugar mill’s 50-year-old boilers, even though the new plant produces 74 MW of electricity

and meets all steam and power requirements that were previously handled by the mill’s

boilers. The cogeneration plant’s air quality permits link the two facilities. After the

cogeneration plant has operated long enough to establish its reliability, the sugar mill will

be required to dismantle the old boilers.

The design emission rates for the Okeelanta plant, in pounds per million Btu, are 0.1 for

SO2 , 0.15 for NOx , and 0.03 for PM. All environmental monitoring and testing to date

indicate that the plant is operating within its permit requirements. However, a brief news

item in Waste News , August 11, 1997, stated that ash produced by the Okeelanta and

Osceola plants contains elevated levels of arsenic and chromium.
136

Economic Information

The reported total capital cost for the Okeelanta plant was $194.5 million; based on 74

MW, this is equivalent to about $2800/kW in 1998 dollars. The Osceola plant’s total

capital cost was reported as $162 million; based on 52 MW, this is equivalent to about

$3300/kW in 1998 dollars.

Lessons Learned

The Okeelanta Cogeneration Plant provides many environmental benefits, and should serve

as a reliable energy source for the sugar mill and the electric utility. Unfortunately, the

partnership and the utility could not resolve their differences amicably. The lawsuits,

bankruptcy, shutdown, and layoffs significantly reduced the project’s value to all its

stakeholders. Hopefully, the project is now on a track where it can operate steadily.

Sources and Contacts

Nearly all the information in this section was obtained from a series of magazine and

newspaper articles, including Power , August 1995, and ENR , December 12, 1994.

Additional information was obtained in discussions with James Meriweather,

environmental manager at the Okeelanta Cogeneration Plant, in February 1999.

James Meriweather

Environmental Manager

Okeelanta Cogeneration Plant

P.O. Box 9

South Bay, FL 33493

Phone: 561-993-1010
137

LAHTI GASIFICATION COFIRING PROJECT,

LAHTI, FINLAND

________________________________________________________________________

The goal of the Lahden Lampovoima Oy’s Kymijarvi power plant gasification project is to

demonstrate the direct gasification of wet biofuel and the use of hot, raw and very low-Btu

gas directly its coal boiler. Lahden Lampovoima Oy (LLO) operates the Kymijarvi power

plant near the city of Lahti in southern Finland. The Kymijarvi power plant is a PC-fired

steam plant that generates as much as 167 MWe of electricity and as much as 240 MWth of

district heat production. Starting in January 1998, a CFB gasifier began operation on a

recycled fuel mixture consisting of mostly wood, paper, cardboard, and a small amount of

plastic. The gasifier capacity is about 45 MWth , which is about 15% of the boiler’s average

heat input. The gasifier has run from January 1998 through January 1999 with an

availability of about 98%.

Vital Statistics

Configuration CFB gasifier feeding raw low-Btu

gas to burners in coal-fired boiler

Design capacity Boiler 167 MWe

240 MWth

Gasifier 45 MWth

Fuels Coal 1200

(GWh/yr thermal) Natural gas 800

Biomass ~300

History and Outlook

In Europe, typically about 30-150 MW of biofuel energy is available within 50 km from

the power plant. This amount can be gasified and used directly in mid- or large- sized coal

fired boilers. Thus, a power plant concept consisting of a gasifier connected to a large

conventional boiler with a high efficiency steam cycle offers an attractive and efficient way

to use local biomass sources in energy production.

Foster Wheeler Energia Oy developed the CFB gasification process in the early 1980s. The

first commercial gasifier was installed in 1983, and is still operating, replacing fuel oil in a

lime kiln at Wisaforest Oy, Jacobstad, Finland. Similar gasification plants having the same

basic technology were installed at two pulp mills in Sweden (1985, 1986) and one mill in

Portugal (1986). These gasifiers convert bark and waste wood to low-Btu gas (17-35

MWth ), which is used as fuel in lime kilns and drying plants.

LLO produces power and district heat for the city of Lahti. The company is 50% owned by

the city of Lahti and 50% owned by Imatran Voima Oy (IVO), which is the largest electric

utility company in Finland. The Kymijarvi power plant started up in 1976, and produces

electric power for the owners and district heat for Lahti city. The maximum power capacity

is 167 MWe and the maximum district heat production is 240 MWth . Originally the plant

was heavy oil fired, but in 1982 was modified for coal firing. In 1986, a gas turbine
138

generator set, from which exhaust heat was used for preheating the boiler feed water, was

installed at the plant. The maximum electrical output of the gas turbine is 49 MWe when

the outside temperature is -13°F.

The boiler operates about 7000 h/yr. During the summer, when the heat demand is low, the

boiler is shut down. During the spring and autumn, the boiler is operated at low capacity

with natural gas as the main fuel.

Based on evaluations of local biomass and waste resources, the plant owners decided to

add a CFB gasifier to the facility and to cofire the low-Btu gas in the boiler, displacing

some of the coal used. Funding was provided from the EU Thermie program. The gasifier

started up in January 1998; the first switchover to gasification mode took place on January

14. After some initial testing, the gasifier moved into commercial operation and has had an

availability factor of about 98% through January 1999.

CFB Gasification

The Foster Wheeler Energia Oy atmospheric CFB gasification system is very simple. It

consists of a reactor in which the air-blown fluidized gasification takes place, a “uniflow”

cyclone to separate the circulating bed material from the gas, and a return pipe for returning

the circulating material to the bottom part of the gasifier. All these are entirely refractory

lined. Typically, after the uniflow cyclone, hot product gas flows into the air preheater,

which is located below the cyclone.

The gasification air, blown with the high-pressure air fan, is fed to the bottom of the reactor

via an air distribution grid. When the gasification air enters the gasifier below the solid bed,

the gas velocity is high enough to fluidize the particles in the bed. At this stage, the bed

expands and all particles are in rapid movement. The gas velocity is so high that many

particles are conveyed from the reactor into the cyclone. The fuel is fed into the lower part

of the gasifier above the air distribution grid.

The operating temperature in the reactor is typically 1470°-1830°F, depending on the fuel

and the application. When entering the reactor, the biofuel particles start to dry rapidly and a

first stage of reaction, namely pyrolysis, occurs. During this reaction stage, fuel converts to

gases, charcoal, and tars. Part of the charcoal goes to the bottom of the bed and is oxidized

to CO and CO2 , generating heat. These products then flow upward in the reactor, and a

secondary stage of reactions takes place, which can be divided into heterogeneous

reactions, where char is one ingredient in the reactions, and homogeneous reactions, where

all the reacting components are in the gas phase. A combustible gas is produced which

enters the uniflow cyclone and exhausts from the system together with some of the fine

dust.

Most solids in the system are separated in the cyclone and returned to the lower part of the

gasification reactor. These solids contain char, which is combusted with the air that is

introduced through the grid nozzles to fluidize the bed. This combustion process generates

the heat required for the pyrolysis process and subsequent mostly endothermic reactions.

The circulating bed material serves as heat carrier and stabilizes the temperatures.
139

The heat energy in the gas is in three forms: chemical heat (combustion); sensible heat (hot

gas); and carbon dust (combustion). In normal operation, the fuel feed rate will define the

capacity of the gasifier and the air feed rate will control the temperature in the gasifier.

Coarse ash accumulates in the gasifier and is removed from the bottom of the gasifier with

a water-cooled bottom ash screw.

Plant Flowsheet and Design Information

Kymijarvi Power Plant, Lahti, Finland

Deaerator District heat

Makeup water and Steam 240 MWth

feed pumps

Turbine Electricity

 Boiler Steam generator 167 MW

 feed 2500 psig

 water 1004 deg F Flue gas

 Coal or natural gas

Biomass

wastes CFB Benson type

gasifier PC Electrostatic

and cyclone boiler precipitator

 Ash Fly ash Stack

 Combustion air

Gasifier

The Lahti CFB gasifier is a refractory-lined steel vessel and cyclone as described earlier. In

the gasifier, biofuels and RDF are converted to combustible gas at atmospheric pressure at

a temperature of about 1560°F. The hot gas flowing through the uniflow cyclone is cooled

in the air preheater before it is fed into the main boiler. The gasification air is heated in the

air preheater before it is fed to the gasifier.

The major difference from the gasifiers Foster Wheeler supplied in the mid-1980s is that

fuel is not dried in this application, and the moisture content of the fuel can be up to 60%.

No considerable changes have been made to the design of the gasifier, air preheater, or gas

line. Some mechanical changes compared to the standard atmospheric biomass gasifiers

were made to accommodate the special nature of the fuel components to be used in the

gasifier. For fuels such as RDF, some wood wastes, and shredded tires, which may

contain different types of solid impurities (nails, screws, metal wires, concrete), the air

distribution grid and the bottom ash extraction system were modified.

Boiler

The Benson once-through boiler generates 992,000 lb/h of steam at 2500 psig and 1004°F,

and at 588 psig and 1004°F. The boiler is not equipped with a sulfur removal system.

However, the coal contains only 0.3 to 0.5% sulfur. The burners are provided with flue gas

circulation and staged combustion to reduce NOx emissions.
140

The low-Btu gas from the gasifier is led directly from the cyclone through the air preheater

to two burners located below the coal burners in the boiler. The gas is burned in the main

boiler where it replaces part of the coal consumption. When the fuel is wet, the heating

value of the gas is very low. Typically, when the fuel moisture is about 50% the heat value

of the gas is only about 59 Btu/scf. The design of the low-Btu gas burners is unique and is

based on pilot-scale combustion tests and CFD modeling work.

Fuel System

Fuel preparation systems grind and screen the biomass and waste fuels and remove tramp

metal. The sized fuel is conveyed to a feed bin, and from there is metered into the gasifier.

An exceptional level of effort was invested in getting the feedstock handling system to

operate efficiently and reliably. All the biomass is received onsite in trucks, either selfunloading for sawdust or tipping for some of the RDF fuels. The REF fuel arrives in an

unloading hall. Although all feed suppliers have signed contracts to ensure that there are

few or no noncombustible or hazardous materials (e.g., treated wood, plastics), the hall is

under continuous video surveillance for verification. Noncomplying truckers or suppliers

are quickly removed from the list of approved vendors.

After tipping and inspection the material goes into a slowly rotating crusher, which also

handles the oversized biomass materials. There is a second receiving station for peat,

sawdust, and chipped wood. The self-unloading trucks discharge in a heated and controlled

ventilation hall (meeting two objectives: winter unloading and fugitive dust elimination),

onto a screen to separate oversized materials, which go to the RDF crusher. Underground

conveyors take the material under magnetic separators and over a disk screen before

discharge in a large covered A-frame storage facility.

This storage silo is the key to the smooth operation of the facility. The biomass is

discharged onto the top of a linear pile (150 m long) and the discharge is arranged so a thin

layer of the current load is deposited on the top of the pile and along its length as this layer

is swept backward and forward along the length of the pile. Mixing is effected by the use

of a horizontal screw that travels transversely along the base of the pile. This screw

discharges onto the feed conveyor to the gasifier. It is an effective mixing device, since in

cross section the pile looks like a triangular layer cake.

There is only a small amount of surge capacity in the gasifier building. The feed flows

through two sets of rotary valves that isolate the gasifier at slightly above atmospheric

pressure. Nuclear gauges are used to measure silo and bin levels. The gasifier’s air grid has

been modified to ensure that the larger contaminants from the RDF fuel can be withdrawn

from the bottom of the unit. Tire fuels have proved to be difficult in this respect because of

the wires in radial tires causing blockages in the sand withdrawal screw.

Emissions Control

An ESP moves fly ash from the boiler flue gas.
141

Fuels

The boiler uses about 200,000 t/yr of coal and about 2.73 billion scf/yr of natural gas.

These are equivalent to thermal energy inputs of 1200 GWh/yr of coal and 800 GWh/yr of

natural gas, or about 60% coal and 40% gas. The coal has a low sulfur content, about

0.3%-0.5%. About 1.0 x 1012 Btu/yr (300 GWh/yr) of various types of biofuels and refuse

fuels are available in the Lahti area, as follows:

Fuel Weight % of Total Weight % Moisture

Sawdust 10 45-55

Wood residues (bark, wood chips, etc.) 30 45-55

Dry wood wastes from the wood working

 industry (plywood, particle board, etc.)

30 10-20

Recycled fuel (RF) 30 10-30

The RF is produced from refuse of various origins, which comes from households,

offices, shops, and construction sites in the area. Waste is separated at the source in

Finland, so the REF contains primarily clean paper and plastic. The processing of REF

was started by the municipally owned waste management company Paijat-Hameen

Jatehuolto Oy in 1997. The REF fuel composition is estimated as follows:

Component Weight % 

Plastics 5-15

Paper 20-40

Cardboard 10-30

Wood 30-60

The amount of biofuels and refuse fuels available each year is enough to substitute for

about 15% of the fuels burned in the Lahti plant’s boiler, or to substitute for 30% of the

coal burned. Assuming 7000 h/yr of plant operation, 300 GWh/yr is equivalent to about 43

MW of thermal energy available from local biofuels. In addition to the REF fuel

components, peat, demolition wood waste, and shredded tires are used as fuels in the

gasification plant.

Operating Experience

During the first week of operation in January 1998, the gasifier startup and shutdown

cycles were tested, and the stabilities of the boiler and gasifier were monitored in various

cases. These tests were successful. The gasifier has been in continuous operation since

January 21, 1998 (except during periods of low energy demand in the summer, when the

boiler does not run). The operation of the gasifier as well as the operation of the gas

burners has been stable despite the low heating value of the gas. The measured gas quality

has matched well with the design calculations. The load of the gasifier has been varied

between 30 and 45 MWth and most of the time the gasifier has been run at full load.

The first operating period of the gasifier took place from January 9, 1998, to June 2, 1998.

The gasifier was connected to the main boiler on December 7, 1997 and after warming up

the refractory lining the first combustion tests with solid fuel (biomass) were performed on

January 9, 1998. The first gasification tests were carried out on January 14, 1998 and the

unit has been in continuous operation since week 4, 1998. During the first heating season

approximately 2700 h of operation were achieved.
142

The experience during initial operations was successful, with very few problems and high

plant availability. Temperatures, pressures, flow rates, and gas composition were very

close to design values. The stability of the boiler steam cycle has been good. The large

openings that were made for the low-Btu gas burners caused no disturbances in the water

circulation. The operation of the burners has been good. Combustion of the low-Btu gas

has been stable despite the high moisture content of the fuel (45%-58%) and the very low

heating value of the gas.

Because of shortages of fuel and problems in the fuel preparation plant at times, the gasifier

was occasionally operated in the combustion mode during the first operating season. This

keeps the fuel consumption at a low level while maintaining normal temperatures in the

gasifier. The capacity of the gasifier in the combustion mode has typically been 5-7 MWth.

The gasifier and the boiler performance have been extensively monitored. No fouling or

corrosion has been found on probes placed in the boiler. The gas produced has about 6-8

g/Nm3

 dust and tar contents on a wet gas basis. There is less than 0.1 ppv of alkali. Fuelbound nitrogen contributed about 1 g/Nm3

 of NH3 and 25-45 mg/Nm3 HCN on a dry gas

basis. At the boiler there has been a reduction of 10 mg/MJ in NOx production, and similar

reductions in dust loading. The coals used are essentially chloride free. Tests for dioxins,

furans, and chlorinated phenols/benzenes and PAH in both the boiler flue gas and the ash

streams demonstrated very low values.

Environmental Performance

The gasification of biofuels and cocombustion of gases in the coal-fired boiler offers many

advantages, such as recycling of CO2 , decreased SO2 and NOx emissions, and an efficient

way to use biofuels and recycled REF. Measurements indicated the following changes in

emission levels when the boiler was cofiring biomass-derived gas:

NOx Decrease by 10 mg/MJ (5 to 10%)

SO2 Decrease by 20-25 mg/MJ

HCl Increase by 5 mg/MJ

CO No change

Particulates Decrease by 15 mg/Nm3

Heavy metals Slight increase in some elements, base level low

Dioxins, furans, PAH,

benzenes, phenols

No change

Economic Information

Specific information on the capital investment in the gasification/cofiring system at Lahti is

not available. As a general case, that the capital cost of such a system is estimated at $400-

650/kW. Only small modifications are required to the boiler, and possible disturbances in

the gasifier do not shut down the power plant.
143

Lessons Learned

No significant problems have been reported during the 1 year that the Lahti biomass

gasifier has been operating. Technically, the operation is successful so far. This unit is the

fifth CFB biomass gasifier Foster Wheeler has installed in European plants since 1983,

and all have been reliable, according to Foster Wheeler. This technology gives utilities in

the United States another option to consider when examining the feasibility of cofiring

biomass and waste fuels in coal-fired boilers.

Sources and Contacts

Nearly all the information in this section is from the following three documents:

• An article in the February 1998 issue of Modern Power Systems , entitled “Thermie

demonstrates biomass CFB gasifier at Lahti.” The authors were Juha Palonen and

Jorma Nieminen of Foster Wheeler Energia Oy and Eero Berg of Foster Wheeler

Service Oy, Varkaus, Finland.

• A foreign travel trip report by Ralph Overend of NREL, following his attendance at

the Seminar on Power Production from Biomass III; Gasification and Pyrolysis

RD&D for Industry, Espoo, Finland, September 14-15, 1998. A tour of the Lahti

gasification plant was included.

• A technical paper from August or September 1998 by Juha Palonen and Jorma

Nieminen of Foster Wheeler Energia Oy, entitled “Biomass CFB Gasifier

Connected to a 350 MWth Steam Boiler Fired with Coal and Natural Gas --

Thermie Demonstration Project in Lahti in Finland.”

Additional information was obtained from a presentation (no written paper) by Neil Raskin

of Foster Wheeler Development Corporation at the BIOENERGY ‘98 Conference,

October 4-8, 1998, and from discussions with David Tillman of Foster Wheeler

Development Corporation in January 1999. No direct contact has been made with

personnel at the Kymijarvi power plant in Lahti. Contacts at Foster Wheeler in the United

States are:

Neil R. Raskin

Director, Global New Products

or

David A. Tillman, Ph.D.

Project Manager, Global New Products

Foster Wheeler Development Corporation

Perryville Corporate Park

Clinton, NJ 08809-4000

Telephone: Raskin 908-713-3190 Tillman: 908-713-3181

Fax: 908-713-3195
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1. AGENCY USE ONLY (Leave blank) 2. REPORT DATE

 January 2000

3. REPORT TYPE AND DATES COVERED

 Subcontract Report

4. TITLE AND SUBTITLE

Lessons Learned from Existing Biomass Power Plants

6. AUTHOR(S)

G. Wiltsee

5. FUNDING NUMBERS

 

C: AXE-8-18008

TA: BP911010

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

Appel Consultants, Inc.

23904 Plaza Gavilan

Valencia, CA 91355

805.253.3492

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9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory

1617 Cole Boulevard

Golden, CO 80401-3393

10. SPONSORING/MONITORING

 AGENCY REPORT NUMBER

 NREL/SR-570-26946

11. SUPPLEMENTARY NOTES

NREL Technical Monitor: Richard Bain

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National Technical Information Service

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12b. DISTRIBUTION CODE

 

13. ABSTRACT (Maximum 200 words) This report includes summary information on 20 biomass power plants, which represent some of the leaders in the industry. In

each category an effort is made to identify plants that illustrate particular points. The project experiences described capture some important lessons learned that lead in

the direction of an improved biomass power industry.

14. SUBJECT TERMS 15. NUMBER OF PAGES

biomass, power plant, electricity

16. PRICE CODE

 

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National Renewable Energy Laboratory

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NREL is a U.S. Department of Energy Laboratory

Operated by Midwest Research Institute•Battelle•Bechtel

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NREL/SR-570-26946

January 2000