EPA340/1 -77-026
Stationary Source Enforcement Series
CONTROL OF
PARTICULATE EMISSIONS
FROM
WOOD-FIRED BOILERS
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Enforcement
Office of General Enforcement
Washington, D.C. 20460
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CONTROL OF PARTICULATE EMISSIONS
FROM
WOOD-FIRED BOILERS
Prepared by
PEDCo Environmental, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45244
Contract No. 68-01-3150, Task Order No. 11
Principal Author: Richard W. Boubel, Ph.D,
PEDCo Project Manager: Donald J. Henz, P.E.
EPA Project Officer: James Herlihy
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Division of Stationary Source Enforcement
Technical Support Branch
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EPA REVIEW NOTICE
This report has been reviewed by the Environmental Protection
Agency and approved for publication with some modification.
Approval does not signify that the contents necessarily reflect
the views and policies of the Agency, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use.
The Stationary Source Enforcement series of reports is issued
by the Office of Enforcement, Environmental Protection Agency,
to assist the Regional Offices in activities related to
enforcement of implementation plans, new source emission
standards, and hazardous emission standards to be developed
under the Clean Air Act. Copies of Stationary Source
Enforcement reports are available-as supplies permit-from
Air Pollution Technical Information Center, Environmental
Protection Agency, Research Triangle Park, North Carolina 27711,
or may be obtained, for a nominal cost, from the National
Technical Information Service, 5285 Port Royal Road,
Springfield, Virginia 22161.
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ACKNOWLEDGEMENT
This report was prepared for the U.S. Environmental
Protection Agency by PEDCo Environmental, Inc., Cincinnati,
Ohio. Mr. Donald J. Henz was the PEDCo Project Manager.
Richard W. Boubel, Ph.D. was the principal author of the
report.
Mr. James Herlihy was the Project Officer for the U.S.
Environmental Protection Agency.
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TABLE OF CONTENTS
Page
1.0 INTRODUCTION 1-1
Purpose of this Report 1-1
Scope of Work 1-2
History of Wood as Fuel 1-3
Present Use of Wood as Fuel 1-4
Worldwide Use of Wood Fuel 1-5
Use of Wood as Fuel in the United States 1-6
Important Properties of Wood Fuel 1-11
Users of Wood-Fired Boilers 1-17
Distribution of Wood-Fired Boilers 1-21
in the United States
2.0 COMBUSTION OF WOOD 2-1
Properties of Wood as Fuel 2-1
Theory of Wood Combustion 2-12
Practical Aspects of Wood Combustion 2-13
Combustion of Wood with Auxiliary Fuels 2-21
3.0 PROCESS DESCRIPTIONS 3-1
Wood Handling and Storage Systems 3-1
Wood-Burning Furnaces 3-16
111
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TABLE OF CONTENTS (continued)
Page
Boilers 3-34
Instrumentation 3-38
Controls 3-45
4.0 OPERATING VARIABLES 4-1
Fuel Variables 4-1
Combustion Air Variables 4-13
Operator Variables 4-32
5.0 PARTICULATE EMISSIONS 5-1
Regulations for Particulate Emissions 5-1
Particulate Measurement Methods 5-9
Theoretical Emissions 5-16
Measured Emissions 5-20
6.0 CONTROL TECHNOLOGY 6-1
Control Devices 6-1
Operator Training 6-29
Instrumentation 6-32
Maintenance and Operation 6-35
Ash Cleaning Schedule 6-39
Regulatory Aspects of Wood-Fired Boiler 6-41
Operation
APPENDIX A NUMBER OF WOOD-FIRED BOILERS BY STATE A-l
APPENDIX B CHARACTERISTICS OF BARK FUEL B-l
IV
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TABLE OF CONTENTS (continued)
APPENDIX C NATIONAL COUNCIL OF THE PAPER C-l
INDUSTRY FOR AIR AND STEAM IMPROVE-
MENT AIR QUALITY IMPROVEMENT TECHNICAL
BULLETIN NO. 70
v
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LIST OF FIGURES
No. Page
1 Flow diagram proposed for EWEB expansion 1-19
2 Some methods of energy conversion using 1-22
direct combustion of residue materials
3 Number of boilers and (10 tons of wood burned 1-24
per year) blank indicates no boilers
4 Cross-section of a typical hogging machine 2-4
5 Relation of excess air to percentage of 2-15
oxygen and carbon dioxide in flue gases
6 Relation of heat loss to moisture content 2-15
of Douglas-fir bark
7 The effect of fuel moisture on steam production 2-17
as reported by Johnson
8 Hogged wood-waste fuel system 3-3
9 System for preparing hogged fuel 3-4
10 System to limit fuel-storage time by insuring 3-4
that fuel first into storage will be first
out to be burned
11 Typical hot-hog dryer system 3-13
12 Typical rotary dryer 3-13
13 Typical vibratory hot-conveyor dryer 3-15
14 Dutch oven furnace and boiler 3-15
15 Pile burning: "Dietrich" cell 3-23
yi
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LIST OF FIGURES (continued)
No._ Page
16 Spreader stoker fired steam generator 3-25
EWEB - Number 3
17 Small spreader-stoker furnace 3-26
18 Pneumatic stoker - No. 2 boiler 3-27
19 The Energex cyclonic burner 3-30
20 An Energex-fired package boiler 3-30
21 Large suspension burning system 3-32
22 A common arrangement of instruments to 3-46
monitor opacity of exit flue gases
23 A flue-gas analyzer used to control dampers 4-18
for induced-draft (I.D.) and forced-draft
(F.D.) fan systems
24 Flow path of 100 pounds of cinders high in 4-29
inorganic ash, screened and reinjected, with
good combustion
25 Method 5 sampling system 5-11
26 Relation of opacity to optical density 5-17
27 135 EPA Method 5 tests in Oregon and Washington 5-24
28 Cyclone collector for particles in flue gases 6-4
29 Relation of particle size to collection 6-6
efficiency of cyclones
29a Simplified diagram of a multiple cyclone 6-6
30 A cascading shower scrubber for increasing the 6-11
efficiency of removing small particles from
gases
31 A venturi scrubber system in which turbulence 6-11
downstream from throat increases the contact of
particles and liquid droplets
Vll
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LIST OF FIGURES (continued)
No. Page
32 Process weight charts 6-45
33 135 Oregon and Washington boiler tests on 6-46
two process weight charts
34 30 and, 90 million Btu/hour allowable emissions 6-48
Vlli
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LIST OF TABLES
No. Page
1 Use of Roundwood and Bark for Fuel in 1-7
Selected Countries in 1972
2 U. S. Fuel Consumption by Conventional 1-9
Stationary Combustion Systems (10-^ Btu/year)
3 Electric-Generating Utility Boilers, 1972 1-10
4 Flue Gas Emissions from Industrial Boilers 1-12
5 Flue Gas Emissions from Commercial/ 1-13
Institutional Boilers
6 Uses of Process Steam in Forest Product 1-23
Manufacturing Plants
7 Approximate Size Range of Typical Components 2-3
of Wood Fuel
8 Typical Ultimate Analyses of Moisture-Free 2-7
Samples of Hogged Fuel Bark
9 Typical Proximate Analyses of Moisture-Free 2-8
Wood Fuels
10 Typical Heating Values of Moisture-Free 2-10
Bark and Wood
11 Analyses of Some Selected Wood Refuse Burned 2-11
as Fuel
12 Analysis of Ash from Hogged Wood-Waste Fuel 2-19
13 Factors Affecting the Combustion Reaction in 4-2
Boiler Installations Fired by Hogged Fuel
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LIST OF TABLES (continued)
No. Page
14 EPA Method 5 Data as Reported by Morford 5-22
15 EPA Method 5 Tests on Hog Fuel Boiler 5-23
Installations in Oregon and Washington
16 High-Volume Tests of Wood-Fired Boilers 5-26
at Steady Loading
17 High-Volume Tests of a Wood-Fired Boiler 5-27
at Variable Loads and Excess Air Settings
CBoiler 5)
18 Results of Efficiency Test of Centrifugal 5-28
Collector on Wood-Fired Boiler (Boiler K)
19 Particulate Emissions of Three Boilers at 5-29
Various Loads
20 Particulate Emissions from a Small Spreader 5-29
Stoker with and without Cinder Reinjection
CBoiler 6)
21 Particle Sizes from High-Volume Tests of Wood- 5-31
Fired Boilers
22 Ash Analysis of Particulate from Several 5-33
Wood-Fired Boilers
23 Particulate Emission Analysis and Calculated 5-33
Ash Values (Boiler 5)
24 Comparison of Visual Opacity with Optical 5-35
Transmissometer for a Wood-Fired Boiler
25 Comparison of EPA Method 5 and High-Volume 5-36
Particulate Sampling Values
26 Efficiency Tests of a Centrifugal Collector 6-9
27 Emissions from Boiler Equipped with Low 6-15
Energy Scrubber
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LIST OF TABLES (continued)
No. Page
28 Efficiency of Dry Scrubber on Hogged 6-17
Fuel Boiler
29 Efficiency of Dry Scrubber on Boiler Burning 6-18
Hogged Fuel with High Salt Content
30 Efficiency of Dry Scrubber on Boiler Burning 6-19
Bark/Coal Fuel
31 Efficiency of Dry Scrubber on Boiler Burning 6-20
Bark/Oil Fuel
32 Emission Data from Power Boilers Fired with 6-23
Bark/Wood Plus Other Fuels
33 Tests of a Hogged Fuel Boiler Equipped with 6-27
Nomex Filters
34 Properties of Particulate Collectors on Wood- 6-30
Fired Boilers
35 Summary of Regulations for Wood-Fired Boilers 6-43
36 Allowable Particulate Emissions from 6-49
Boilers in Vermont and Missouri
XI
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1.0 INTRODUCTION
PURPOSE OF THIS REPORT
This report is intended primarily as a guide for con-
trol agency personnel and engineers who are not familiar
with wood-fired boilers. The presentation is thorough and
detailed; trade jargon has been avoided, and technical terms
are defined. A secondary purpose of this report is to
compile in a single document the latest available informa-
tion on air pollution control technology as it concerns
wood-fired boilers. This information includes descriptions
of control systems, emission sampling procedures, applicable
regulations, and costs of control.
The discussions of control technology concern particu-
late emissions only. Although wood-fired boilers also
produce gaseous pollutants such as carbon monoxide, oxides
of nitrogen, and unburned hydrocarbons, little accurate
information is currently available about either the quality
or quantity of these emissions. This report therefore
considers gaseous emissions only with respect to their
possible effects on firing practices, particulate control
equipment, or safety.
1-1
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Many of the figures and much of the text of certain
sections are taken from a publication titled "Boilers Fired
with Wood and Bark Residues" by Dr. David C. Junge of Oregon
Q
State University. This bulletin is intended as a guide for
boiler operators and fireman and is recommended as a general
reference.
SCOPE OF WORK
Wood-fired boilers are theoretically of any size or
configuration, ranging from a simple oil drum with a copper
coil, as used by the makers of "white lightening," to very
large, high-pressure high-temperature power boilers fully
computer-controlled. This report is concerned with wood-
fired boilers, regardless of size, that meet the following
criteria:
1. The boilers are fired mechanically. This criter-
ion eliminates the moonshiner's boiler and also a
great number of other small, hand-stoked boilers.
Most of these are designed for intermittent opera-
tion and they should each be considered on an
individual basis.
2. The boilers are designed primarily for wood fuel.
Some paper mills operate large "bark-burning"
boilers that produce 85 percent of their output
from combustion of natural gas and only 15 percent
from combustion of wood bark. These boilers are
designed and operated according to the principal
fuel and cannot be classed with wood-fired boilers
for comparison.
3. The boilers are furnace-boiler units, rather than
incinerators. Furnaces used as incinerators,
either separately or ahead of other incineration
chambers, are usually governed by incineration
1-2
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regulations and practices. This criteria also
eliminates wigwam-type burners, fireplaces, wood
stoves, and open fires.
HISTORY OF WOOD AS FUEL
Wood was undoubtedly man's first fuel. In prehistoric
times it was used for heat, light, cooking, and manufactur-
ing. The use of wood as a fuel continued to increase through
recorded history as man's needs for energy increased. Use
of coal was introduced with the steam engine during the
industrial revolution. Even in industrialized nations the
use of wood continued for firing of both stationary and
mobile boilers. The early steamships and many early loco-
motives were operated on wood-fired boilers.
Logging was conducted exclusively with steam donkey
engines, using one-pass fire tube boilers. The sawmill was
steam-powered, with both the carriage and the saws driven by
steam generated in a stationary, wood-fired boiler.
As electric power came into wider use, electric motors
became more economical than individual steam engines.
Central utility stations were constructed to generate elec-
tricity from steam engines or turbines. These stations
usually burned coal, although oil and then natural gas
became important fuels early in the twentieth century.
Gas and oil offered advantages over coal in that they
were cleaner, easier to automate, easier to fire, and not
1-3
-------
much more expensive. The continuing demand for coal for
making steel kept its price well above those of natural gas
and residual oil, which were considered almost as "waste
fuels."
With these developments the use of wood as fuel de-
clined. To generate the same amount of energy from wood as
from coal, the user must burn about twice the wood by weight
and about 5 times by volume. With oil, the comparison is
even less favorable. One must burn about 4 pounds of wood
to provide the same energy as 1 pound of oil and, in terms
of volume, about 11 cubic feet of wood for the same energy
release as 1 cubic foot of oil. For these reasons, the
operators of steamships and locomotives eventually switched
to coal and oil as their fuels of choice over wood.
PRESENT USE OF WOOD AS FUEL
Today, the domestic use of wood as a fuel is vastly
different from that 100 years ago. Wood is still burned as
fuel where it occurs as a by-product of a manufacturing
operation.
1. Lumber and plywood manufacturing facilities can
use bark and other residues to fire a boiler for
energy. In some areas, the mill may generate an
excess of wood residue fuel and sell it to another
energy user, such as a utility or institution, or
possibly to another mill that does not produce
enough fuel.
1-4
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2. Paper mills use only the white wood for paper and
must dispose of the undesirable bark. This bark
can be burned in a power boiler to generate plant
steam. If not enough bark is readily available it
may be advantageous to purchase additional bark or
wood residue from a nearby lumber mill.
3. Particle board and hardboard manufacturing plants
must dispose of trim, surface material, or other
combustible wood waste. Most plants can convert
this dry, combustible fuel to energy much more
economically than they can burn oil or gas. The
steam generated by burning wood is needed to
produce the board product.
4. Furniture manufacturing facilities may generate
enough dry, waste wood that it can be used economi-
cally for process steam generation or sold to
another user for central station generation.
WORLDWIDE USE OF WOOD FUEL
The efficiency of converting solar energy, through
wood, to thermal energy from a boiler is approximately one-
half of one percent. Although this is poor efficiency, the
process is still more efficient than some other suggested
methods of converting solar energy, such as in solar cells
and batteries.
Whereas we in the United States tend to think of wood
as a product source, many people of the world consider it as
an energy source. Worldwide, energy production is by far
the greatest single use for bark and wood. Even as recently
as 1972, nearly half of the wood harvested was used directly
2
for fuel. More people are warmed by wood and bark than by
any other fuel. In some countries the demand for wood and
1-5
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bark is so great that wood is not even considered as a
building material. Table 1 gives information on the world-
wide use of wood and bark for fuel in 1972; the countries
listed are those with the greatest forest production, as
2
reported by the United Nations. The values are based on an
average factor of 0.13 as the ratio of bark to solid wood.
Although this factor may not be exact worldwide, it does
represent a reasonable estimate for bark production.
Table 1 uses the term "unit" as a measure of quantities of
wood. A unit is defined as 200 cubic feet of wood measured
in the containing vehicle of transportation, without pack-
ing, at either the mill or delivery point, whichever is
specified in the fuel contract. Wood residue and bark are
usually sold on a volume basis because they are bulky, low
4
in calorific value, and high in moisture content.
USE OF WOOD AS FUEL IN THE UNITED STATES
As shown in Table 1, the domestic use of wood as fuel
can be estimated at 2295 x 10 units of roundwood and 8122
units of bark per year, if all the bark is used as fuel.
Figures for the State of Oregon (1972) indicate that 62
percent of the bark produced was used as fuel. Applying
this factor to the data of Table 1 indicates an annual fuel
3 5
use of 7331 x 10 units of wood and bark. A recent report
estimates the annual use of wood for boiler fuel at indus-
4
trial and commercial/institutional facilities as 2782 x 10
1-6
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Table 1. USE OF ROUNDWOOD AND BARK FOR FUEL IN SELECTED
COUNTRIES IN 19722
Country
World
USSR
USA
China
Brazil
Indonesia
Canada
India
Nigeria
Sweden
Japan
Finland
Total
roundwood,
103 unitsa
433,311
67,628
62,860
31,607
28,958
21,189
21,189
20,659
10,594
10,241
8,122
7,593
Roundwood
for fuelb
103
unitsa
201,294
15,009
2,295
23,661
24,720
18,364
706
18,717
10,065
530
353
1,236
Percent
of total
roundwood
46.4
22.2
3.6
74.9
85.4
86.7
3.3
90.6
95.0
5.2
4.4
16.3
Estimated total
bark for
additional fuel,
103 unitsc
56,327
8,829
8,122
4,061
3,708
2,825
2,825
2,649
1,413
1,413
1,059
1,059
a One unit of wood or bark equals 200 ft .
Includes roundwood used for charcoal.
Bark estimated by multiplying roundwood production by a
factor of 0.13.
1-7
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tons. At an average density of 2 tons per unit this would
be 14,391 x 10 units per year, or double the amount calcu-
lated earlier. Obviously it is difficult to estimate the
exact consumption of wood and bark as fuel in the several
thousand wood-fired boilers in the United States.
On an energy-use basis, it is estimated that wood and
bark contribute less than 1 percent of the total energy
developed by boilers in the United States. Table 2 indi-
cates the domestic consumption of various fuels burned in
boilers, as reported to the EPA. Boilers fired with wood
and bark are not a major concern because of their relative
importance based upon total energy generated. The concern
with wood-fired boilers is because of the numbers of boilers
rather than their average production. Most of these boilers
are small as compared with coal-fired boilers.
Table 3 lists the size and distribution of utility
boilers in the United States. Although the table shows no
wood-fired utility boilers, some utilities are considering
wood-fired units and one utility is currently burning wood
and bark. The Eugene (Oregon) Water and Electric Board
(EWEB), a relatively small public utility, has three boilers
with capacities under 500 x 10 Btu/hr. These boilers
generate electricity from wood residue, which is primarily
bark. The average yearly fuel consumption of this facility
1-8
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-------
is approximately 320 x 10 Btu/hr. This plant produces
about 33.8 megawatts of electricity (about 10 percent of all
the electricity consumed in the EWEB area) and 450,000
pounds of heating steam per hour. It consumes 240,050 tons
of wood and bark per year.
Table 4 indicates the magnitude of emissions of particu-
late matter from domestic industrial boilers. Note that
wood-fired boilers are credited with emitting over 10 per-
cent of the particulate matter generated by industrial
boilers.
Table 5 gives information on particulate emissions from
commercial/institutional boilers in the United States.
Wood-fired boilers are charged with about 1.4 percent of the
total particulate emissions, a value more consistent with
the energy production figures previously cited.
IMPORTANT PROPERTIES OF WOOD FUEL
Wood and bark are of particular interest because they
are "renewable" fuels. The production of a growing forest
can be optimized, for each species of tree, for harvest as
raw material for paper mills, lumber or plywood manufacture,
particle or fiber materials, or fuel. If, for example, fuel
is to be the ultimate use, a forest should be harvested
before the incremental growth rate declines to below the
incremental growth rate of the young trees.
1-11
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Table 4. FLUE GAS EMISSIONS FROM INDUSTRIAL BOILERS'
Boiler fuel
Bituminous coal
Anthracite coal
Lignite
Petroleum
Gas
Baggase
Wood/bark
Total
Emission factor
(calculated) ,
Ib/ton of fuel or
as indicated
13 (wt % ash)
2 (wt % ash)
6.5 (wt % ash)
23 lb/1000 gal.
10 lb/106 ft3
22
15
Particulate,
10 3 tons/year
Total
1600.0
6.3
35.0
120.0
25.0
42.0
210.0
2038.3
<3 u
65.0
0.1
0.7
110.0
23.0
U
u
198.8
Particulate,
percent of total
Total
78.5
0.3
1.7
5.9
1.2
2.1
10.3
<3 y
32.7
0.1
0.4
55.3
11.5
U
U
H
I
M
to
U = Unknown
-------
Table 5. FLUE GAS EMISSIONS FROM COMMERCIAL/INSTITUTIONAL BOILERS
Boiler fuel
Bituminous coal
Anthracite coal
Lignite
Petroleum
Gas
Wood/bark
Total
Emission factor
(calculated) ,
Ib/ton of fuel
or as indicated
13 (wt % ash)
2 (wt % ash)
6.5 (wt % ash)
23 lb/1000 gal.
10 lb/106 ft3
15
Particulate,
10 3 tons/year
Total
50.0
21.0
0
150.0
9.1
1.4
231.5
<3 y
1.0
0.4
0
140.0
8.2
U
149.6
Particulate,
percent of total
Total
21.6
9.1
0
64.8
3.9
0.6
<3 y
0.6
0.3
0
93.6
5.5
U
I
M
U)
U = Unknown.
-------
Current estimates indicate that reserves of readily
collectable and usable wood residue and bark, near present
utilization facilities but not now used, are approximately 5
million tons per year in the United States. The total
domestic resource generated by all logging and wood usage is
estimated at 55 million tons for 1971 and is predicted to be
59 million tons by 1980. These statistics indicate that
much potential energy is not being utilized. A large amount
is left at the site of harvesting.
Another estimate predicts that the growth of wood-
fired energy sources during the period 1973 to 1985 will be
on the order of 60 percent while the overall energy increase
for the entire nation will be 27 percent. A 60 percent
increase over the current estimated usage of 28.3 million
tons per year would yield a 1985 usage of 46 million tons
per year, an indication that not uvach unused wood or bark is
expected by 1985.
Certain properties of wood and bark as fuel must be
considered by the user. The mix of wood residue and bark
that is currently fired in boilers is difficult to store,
handle, and fire. The following properties are undesirable:
1. It is bulky, requiring large storage areas.
2. It lacks uniformity in particle size, in portions
of bark and wood, and in species.
1-14
-------
3. Its moisture content is high; some woods cannot
support combustion.
4. It deteriorates rapidly.
5. It can undergo spontaneous ignition.
6. Steep flow angle (60 to 70°).
7. It packs and mats in storage.
8. It generates dust when dry.
The advantages offered by wood and bark fuel should be
considered also:
1. It is often available near the utilization facility,
2. It is relatively inexpensive.
3. Its sulfur content is low, and its ash content is
low relative to that of coal and residual oils.
4. It is a clean fuel in terms of pollutant emissions
and is relatively clean to handle and process.
The wood residue fuel currently used in the Pacific
Northwest is markedly different from that burned earlier in
this century. It is less uniform, and probably wetter. The
Eugene Water and Electric Board lists the following proper-
ties of an average unit (200 ft ) of fuel delivered to the
EWEB outdoor storage pile:
1. Weight: 3600 pounds (1.8 tons), 18 Ib/ft .
2. Species: primarily Douglas fir, some hemlock and
cedar.
3. Composition: 70 percent bark and 30 percent wood
residue, by weight including moisture.
4. Moisture content: 40 percent by weight.
1-15
-------
5. Dry weight: 2160 pounds.
The average analysis by dry weight is as follows:
1. Heating value (higher): 9840 Btu/lb or 21,524,400
Btu per unit.
2. Ash content: 1.88 percent.
3. Sulfur content: 0.080 percent.
Because of their relatively small usage compared with
that of coal, gas, and oil, wood and bark as fuels have been
largely ignored nationwide, as the following items indicate:
1. Even though wood is found in more states than
coal, no "wood fuel" lobby is operative in Washing-
ton, D.C.
2. The ASTM methods developed for testing of solid
fuels were developed for coal rather than wood.
When these methods are adopted for testing of wood
and bark fuels, results may be unreliable. (Some
of the problems are discussed later.)
3. Most published literature dealing with solid fuel
mentions only coal. Design of furnaces and boilers
for wood fuel combustion is not included in solid
fuel technology.
4. Many boilers that have been sold for combustion of
wood and bark fuels are not designed for wood fuel
firing. Rather, they are designs for coal firing
with a few minor modifications in the fuel-feeding
systems. As one example, consider a wood-fired
boiler installed at Oregon State University in
about 1950. The system included an ash pit sized
for coal with 15 percent ash, even though the wood
residue being burned at the time contained less
than 1 percent ash, most of which was emitted
through the stack. After a few years, the ash pit
was covered because no ashes had ever been removed
from the furnace to the ash pit.
1-16
-------
5. Methods for testing of stationary combustion
sources, such as boilers, are designed for units
firing the fossil fuels, oil and coal. As dis-
cussed more fully later, some of the character-
istics of wood-fired boilers are not amenable to
these source testing methods.
USERS OF WOOD-FIRED BOILERS
Utilities burning wood and bark as a fuel are nearly
nonexistent today. Until about 10 years ago, several wood-
fired boilers in the Pacific Northwest generated electricity
and steam for district heating. One large central station
in Portland, Oregon operated several different sized steam-
generating units, the largest of which could generate 360,000
4
pounds of steam per hour with Douglas fir as fuel. This
station supplied heating steam to a large section of down-
town Portland, Oregon. In the mid-1960's this boiler con-
verted to oil as the primary fuel and has not burned wood
since. The current escalating costs of oil have led to
discussions regarding the feasibility of reconverting this
plant to wood residue fuel.
The EWEB operates a public utility steam plant in
Eugene, Oregon, described as follows in the abstract from
reference 6:
"Using a solid waste as an energy source is not new to
the Eugene Water and Electric Board. The primary fuel
used in our steam-electric generation plant is wood-
waste from lumber mills in the surrounding area. The
plant provides steam for a growing steam heat utility
and electric power generation. By using the waste, the
municipal utility has contributed significantly to the
reduction of local air pollution and solid waste dis-
posal problems..."
1-17
-------
In 1972-73 EWEB paid an average cost of $2.46 per unit
for wood-waste fuel, equivalent to $0.12 per million Btu.
After storage, handling, and some water removal the cost at
the boiler was $0.23 per million Btu. The net steam pro-
duction costs averaged $0.56 per 1000 pounds of steam, and
net cost of electrical power generation was 6.8 mills per
kWh. With oil as fuel, the costs would have been approxi-
mately 5 times greater and with coal, about 3 times greater.
Today, all of these costs have approximately doubled.
In 1973, EWEB conducted an extensive engineering and
economic survey regarding the feasibility of a new, larger
plant that could use both wood residue and municipal waste
as fuels. The schematic flow diagram of the proposed plant
is shown in Figure 1. The proposed plant would operate four
boilers each rated at 405,500 pounds of steam per hour and
would consume 1700 units per day of wood waste along with
approximately 1000 tons per day of combustible municipal
refuse. Because of uncertainties regarding costs and fuel
supplies, the plant has not yet been constructed.
Commercial and institutional use of wood and bark as
fuels is limited. An example of a practical application is
the University of Oregon at Eugene, which operates a wood-
fired steam plant that generates much of the campus elec-
trical load and all of the campus heating load through back-
1-18
-------
J-1
I
I-1
ELECTRICAL
I SWITCH-
| YARD
I OUT
ll
u
Figure 1. Flow diagram proposed for EWEB expansion'
-------
pressure steam turbines. This facility, in operation for
several years, is currently heating the Unitersity of Oregon
for a net fuel cost that is much lower than that at Oregon
State University, 40 miles away and of similar size. In the
1960's Oregon State converted their heating system from
firing of wood with oil standby to firing of interrupted
natural gas with oil standby.
By far the greatest fuel use of wood residue and bark
is by the industries that generate the fuels: lumber and
plywood mills, paper mills, and particle board and hardboard
mills. These industries originally burned wood residue as a
fuel out of necessity. Today they are in an advantageous
position as the country works toward the goal of energy
independence. These industries can use a relatively low-
cost fuel to generate electricity and process steam. In
some cases, they can generate a surplus of electricity for
sale to an electric utility or for use in the electric
system of the "company town." In the Pacific Northwest and
other areas the forest products industry has been rapidly
installing new wood-burning boilers to replace those that
burn oil and gas. In the few years since the fuel "crisis"
of 1974 oil prices have tripled, and wood fuel has become so
desirable that these wood products industries are saving it
for their own use rather than selling it on the open market.
1-20
-------
One of the reasons that EWEB had to forego the utility
expansion is that local wood product industries, in a period
of about a year, completely reevaluated the wood fuel situa-
tion and chose to use this fuel themselves rather than sell
it.
Figure 2 summarizes the basic ways of using wood fuels
directly for energy generation in the form of electricity,
process steam, or hot gases. The uses for process steam are
summarized in Table 6.
Hot flue gases can be used directly for drying of wood,
veneer, or particles. The hot gas may be generated directly
by a wood-fired furnace without a boiler, or the boiler flue
gas can be used instead of exhausting it through a stack.
DISTRIBUTION OF WOOD-FIRED BOILERS IN THE UNITED STATES
Because wood-fired boilers are traditionally located
near the fuel source, most are in the states with large
forest products industries. Figure 3 indicates the number
of boilers and weight of wood residue consumed in those
boilers in each state. The data for Figure 3 were obtained
in a mail survey of State air pollution control agencies.
For States not replying, the number of boilers was estimated
by a linear regression equation based on replies received
and on wood usage as reported by Supernant. The data are
given as Appendix A. In spite of discrepancies in the data,
1-21
-------
I
to
RESIDUE
MATERIAL
HOT GASES TO HEAT
LOAD
A. HEAT UTILIZATION WITH COMBUSTION GASES
RESIDUE
MATERIAL
FURNACE
HOT GASES
BOILER
STEAM _
TO HEAT
LOAD
B. HEAT UTILIZATION WITH STEAM
RESIDUE
MATERIAL
niRMArc
HOT GASES
BOILER
STEAM _
STEAM
TURBINE
ELECTRIC
GENERATOR
ELECTRICITY TO ELECTRIC
LOAD
\ STEAM _TO HEAT
LOAD
C. ELECTRICITY PRODUCTION WITH STEAM
RESIDUE
MATERIAL
CIIDMApC
HOT GASES
GAS
TURBINE
ELECTRIC
GENERATOR
ELECTRICITY ^JC
\ HOT EXHAUST
ELECTRIC
LOAD
Rflll FR
STEAM TO HEAT
D. ELECTRICITY PRODUCTION WITH A GAS TURBINE
Figure 2. Some methods of energy conversion using direct combustion
of residue materials.
-------
Table 6. USES OF PROCESS STEAM IN FOREST PRODUCT
MANUFACTURING PLANTS3
Type of plant
or operation
Use of steam from wood-fired boilers
Dimension lumber
Plywood mill
Particle board
and hardboard
Paper mill
Furniture
manufacture
Kilns for drying lumber
"Shotgun Carriage" (old but still used)
Veneer dryers and hot press
Steam-heated particle dryers
Hot press
Digesters and paper machine dryers
Hot presses and wood steaming systems
Heating and hot water for plant and office use assumed
for all facilities.
1-23
-------
98 /
(3771) /
44
<632)
•NOHTH DAKOTA "T~" '•„..
I (MINNESOTA '
i \
/ °'° ( ' h:
/ (4400) > 61 "v..^ .^-~ js
KW-W 1 I
69 / 1 / i--^.-_ |
V(J359)V (0) / /COLORADO—-1-
_
RKANSAS
--
Figure 3. Number of boilers and (103 tons of wood burned per year)
blank indicates no boilers.
-------
they are probably as reliable as any that can be obtained.
For example, although reference 5 states that no wood is
burned industrially or commercially in Arizona or Michigan,
Arizona reports 14 wood-fired boilers and Michigan lists 27,
If the predicted trend occurs and conversion of wood
residue to energy increases by 60 percent by 1985, most of
the growth probably will occur in a few states. These are
states having wood resources that are not utilized today,
such as Oregon, Washington, Idaho, and northern California.
Some of the other states may increase the use of wood for
fuel but they do not have enough unused resources to show a
doubling in 10 years.
1-25
-------
2.0 COMBUSTION OF WOOD
PROPERTIES OF WOOD AS FUEL
The various types of coal and oil have been classified
and graded by government agencies, trade organizations, and
technical societies. The wood fuels, however, have not been
so classified, even though they also exhibit a wide range of
combustion properties. For example, stringy cedar bark in
large chunks differs greatly from dry, resinous pine sand-
*
erdust in the size range of 20 to 40 microns. To assume
that the same fuel handling and burning system can be used
for both of these fuels is as unrealistic as assuming that
the same systems could efficiently burn both lignite and
anthracite coal.
Wood is essentially cellulose and hemicellulose bound
with lignen. The cellulose is a natural polymer composed of
49.4 percent carbon, 6.2 percent hydrogen, and 44.4 percent
oxygen. In addition to the cellulose and lignen, the wood
residue and bark fuels contain resins, inorganics, traces of
*
One micron, or micrometer, u, is a standard metric unit of
size. It is 10~6 meter and is equivalent to 0.039 x 10~3
inch.
2-1
-------
sulfur, and bound and free water. To evaluate the use of
wood as fuel, it is helpful to understand some important
properties.
Species
Although most species of wood can be used as fuel, some
species are poor fuels because of problems with handling and
poor combustion efficiency. An example is wet cedar bark,
which is stringy and difficult to reduce in size. By com-
parison, dry Douglas fir bark is considered a very desirable
fuel. The variability among species is pronounced, even
though many species, such as the cedar and Douglas fir, grow
together in a naturally mixed forest.
Fuel Size
The size of the individual pieces of wood residue and
bark often cannot be controlled by the user. Fuel purchased
on the open market can be a mixture of many sizes of bark,
coarse wood residues (slabs, trimmings, and endpieces),
planer shavings, sawdust, and sanderdust. If all of the
fuel is from a single facility or process, it will be rela-
tively more uniform. Table 7 indicates the size ranges of
several wood fuels.
2-2
-------
Table 7. APPROXIMATE SIZE RANGE OF TYPICAL
COMPONENTS OF WOOD FUEL
Component
Bark
Coarse wood residues
Planer shavings
Sawdust
Sanderdust
Reject "mat finish"
Size range, in.
1/32-4
1/32-4
1/32-1/2
1/32-3/8
10ya-l/4
Small end of the range is measured in microns.
If the delivered wood or bark is too large for effec-
tive firing, the size must be reduced. The usual way to
reduce the size of wood and large chunks of bark is with a
"hog," a machine designed to reduce large pieces of wood to
a fairly uniform size. Originally all wood fuel for mechani-
cal firing was run through the hog; the terms "hogged wood,"
"hog wood," and "hog fuel" denote material delivered to the
boiler. Figure 4 shows a cross section of a typical hogging
machine.
If the material must be reduced to a size smaller than
the hog provides, it is usually hammermilled for size reduc-
tion. Hammermills are often used for treating dry residue
(such as plywood trim) or bark directly after the barker.
Moisture Content
The moisture content of fuel is commonly considered on
the wet or "as is" basis, and the dry basis, the moisture
2-3
-------
DOUBLE
BREAKING
PLATE
r
COVER DIVIDES HERE
METAL TRAP
Figure 4. Cross-section of a typical hogging machine,
-------
content on a dry basis is usually expressed as a percentage.
The calculation formula is:
_. . . . . . ,-, ^ (weight of moisture x 100)
Percent moisture content (dry) = 3—=—r-r £—5 2—= -
•* weight of dry fuel
The wet basis is the more common measure of moisture con-
tent. For wet-basis determinations, the weight of the
moisture in fuel is divided by the total weight of fuel plus
moisture, and is expressed as a percentage. Therefore,
percent moisture content (wet basis) is equal to (weight of
moisture x 100)/(weight of dry fuel plus weight of mois-
ture) .
The relation between moisture contents (MC) expressed
on a wet and a dry basis is shown in the following equations:
MC (wet) = 100 x MC (dry)/[100 + MC (dry)] (1)
MC (dry) = 100 x MC (wet)/[100 - MC (wet)] (2)
where moisture content is expressed as a percentage on
either a wet or dry basis. The wet basis is used in this
report.
Moisture content is significant in combustion for two
reasons. First, because it varies over a wide range of
values, making control of the combustion process difficult.
For example, consider MC of the different components of
hogged fuel. The MC values of bark, coarse wood residue,
and sawdust normally range from 30 to 65 percent, averaging
about 45 percent. The MC depends, however, on time of year,
2-5
-------
type of wood (species), and milling process. In contrast,
the MC values of kiln-dried planer shavings, sanderdust, and
some rejected particle board materials usually range from 4
to 16 percent.
The second significant feature of moisture content is
its negative heating value; that is, heat must be consumed
to evaporate moisture within the furnace. In some modern
combustion systems the fuel is dried outside the furnace to
gain greater heat release in the furnace.
Ultimate Analysis
Ultimate analyses determine the chemical composition of
fuels. An analysis of the primary components of hogged fuel
is shown in Table 8. Ultimate analyses point out three
significant features of hogged fuel. First, the constitu-
ents vary only slightly from sample to sample. This is
important in calculating and controlling excess air for
combustion.
Second, the oxygen content of hogged fuel is high.
This is significant because the combustion process thus
requires little supplemental oxygen from air.
Third, the sulfur content of hogged fuel is so low that
combustion of hogged fuel generates relatively little sulfur
dioxide, whereas combustion of sulfur-bearing coal or oil
causes significant emissions of sulfur dioxide.
2-6
-------
Table 8. TYPICAL ULTIMATE ANALYSES OF MOISTURE-FREE
SAMPLES OF HOGGED FUEL BARK8
(Values in Percent)
Component
Hydrogen
Carbon
Oxygen
Nitrogen
Ash (inorganics)
Douglas
fir
6.2
53.0
39.3
0.0
1.5
Western
hemlock
5.8
51.2
39.2
0.1
3.7
Avg. of 22
samples
6.1
51.6
41.6
0.1
0.6
Proximate Analysis
The proximate analysis (ASTM Test D-271) gives weight
percentages of moisture, volatile matter, fixed carbon, and
ash. Because the ASTM D-271 test was originally intended
for analysis of coal, certain deviations in test procedure
are in order when the method is applied to the more volatile
9
organic materials. Mingle and Boubel have recommended
deviations from ASTM procedures in sample preparation and in
the times for conducting the individual operations.
Table 9 gives typical values for proximate analysis of
different materials. Note the consistently lower volatile
content of bark as compared with that of sawdust, regardless
of species except for cedar. In general, the volatile
content of bark is 10 percent lower.
2-7
-------
Table 9. TYPICAL PROXIMATE ANALYSES OF MOISTURE-FREE
WOOD FUELS 8
(Values in Percent)
Species
Bark
Hemlock
Douglas fir, old growth
Douglas fir, young growth
Grand fir
White fir
Ponderosa pine
Alder
Redwood
Cedar bark
Sawdust
Hemlock
Douglas fir
White fir
Ponderosa pine
Redwood
Cedar
Volatile
matter
74.3
74.3
70.6
73.0
74.9
73.4
73.4
74.3
71.3
86.7
84.8
86.2
84.4
87.0
83.5
77.0
Charcoal
24.0
24.0
27.2
25.8
22.6
24.0
25.9
23.3
27.9
13.1
15.0
13.7
15.1
12.8
16.1
21.0
Ash
1.7
1.7
2.2
1.2
2.5
2.6
0.7
2.4
0.8
0.2
0.2
0.1
0.5
0.2
0.4
2.0
The ash content of wood residues is generally low, but
still is significant when large quantities are burned. The
ash content of bark usually is greater than that of wood
because handling and harvesting of logs frequently causes
dirt and sand to cling to the bark. Saltwater storage and
transport of logs also can add to the ash content by deposi-
tion of sea salt in the wood or bark.
Heating Value
The heating value of a solid fuel is expressed in Btu
per pound of fuel on as-received, dry, or moisture- and ash-
2-8
-------
free basis. The ASTM D-240 test is used to determine the
heating value by a bomb calorimeter. As stated previously,
the standard solid fuel tests are designed for coal. This
test is no exception in that it calls for about 1 gram of
fuel. The calorimeter is designed for 1 gram of coal; a
gram of wood, even though it is bulkier than a gram of coal,
will yield only about half the energy upon combustion. Wood
may be blown from the fuel pan because of the bulk and
lightness of the sample and the increase in water tempera-
ture may be only about half of that produced by coal.
Heating values as determined in calorimeters are termed
higher or gross heating values. They include the latent
heat of the water vapor in the products of combustion. In
actual operation of boilers, however, the water vapor in the
waste gas is not cooled below its dewpoint and this latent
heat is not available for making steam. The value of latent
heat is sometimes subtracted from the higher, or gross,
heating value to give the lower, or net, heating value.
Lower heating values are standard in European practice, and
higher heating values are standard in American practice.
The heating value of hogged fuel depends on two compo-
3
nents, fiber and resin. The heat value of wood fiber is
about 8,300 Btu per pound, and of resin, about 16,900 Btu
per pound. The heating value of woods with more resin,
2-9
-------
therefore, is higher than that of those with low resin
contents.
Bark generally contains more resin than wood, and
softwood bark contains more than hardwood bark. Some typi-
cal heating values are shown in Table 10.
Table 10. TYPICAL HEATING VALUES OF
MOISTURE-FREE BARK AND WOOD9
(Values in Btu per pound)
Species
Douglas fir
Douglas fir
Western hemlock
Ponderosa pine
Western red cedar
Red alder
Heating value
Wood
9,200
8,800
8,500
9,100
9,700
8,000
Bark
10,100
10,100
9,800
8,700
8,410
The properties of wood residues and bark fuels can vary
so greatly that a standard specification is not possible.
The differences should be recognized and accounted for in
the engineering and operation of wood-fueled systems. Table
11 summarizes the analyses for several properties of selected
wood species. Appendix B gives detailed information on
ultimate analyses, proximate analyses, and heating values
for most bark species used as fuels.
2-10
-------
Table 11. ANALYSES OF SOME SELECTED WOOD REFUSE BURNED AS FUELa'9
Item
Proximate analysis, percent
Ash
Volatile
Fixed carbon
Ultimate analysis, percent
Carbon
Hydrogen
Sulfur
Nitrogen
Ash
Oxygen (by difference)
Heat value, Btu/lb (bone dry)
Ash analysis, ppm
Si02
Fe2°3
CaO
CaC03
MgO
MnO
P2°5
K20
Ti02
so3
Fusion point of ash, F
Initial
Softening
Fluid
Weight, lb/ft3 (bone dry)
Jack pine
2.1
74.3
23.6
53.4
5.9
0
0.1
2.0
38.6
8930
16.0
6.3
5.0
51.6
4.9
5.5
1.6
2.8
4.1
3.1
0.2
2.6
2450
2750
2760
29
Birch
2.0
78.5
19.2
57.4
6.7
0
0.3
1.8
33.8
8870
3.0
0
2.9
58.2
13.0
4.2
4.6
2.9
6.6
1.3
Trace
3.2
2710
2720
2730
37-44
Maple
4.3
76.1
19.6
50.4
5.9
0
0.5
4.1
39.1
8190
9.9
3.8
1.7
55.5
1.4
19.4
1.0
1.1
5.8
2.2
Trace
1.4
2650
2820
2830
31-42
Western
hemlock
2.5
72.0
25.5
53.6
5.8
0
0.2
2.5
37.9
8885
10.0
2.1
1.3
53.6
9.7
13.1
1.2
2.1
4.6
1.1
Trace
1.4
2760
2770
2780
26-29
a Average moisture of about 50 percent as received at firing equipment.
Adapted from information compiled by the Steam Power Committee of the
Canadian Pulp and Paper Association.
2-11
-------
THEORY OF WOOD COMBUSTION
In simplified terms, combustion is a process in which
the components of a fuel containing hydrogen and carbon are
chemically combined with oxygen in air to form combustion
products and release heat energy. If combustion is complete,
hydrogen combines with oxygen to form water vapor and carbon
combines with oxygen to form carbon dioxide. In practice,
small amounts of carbon monoxide, hydrocarbons, and other
gases are usually formed. The noncombustibles form an ash,
which must be removed from the combustion chamber and some-
times from the product gases.
The combustion of all solid fuels is a three-step
process. First, the free water is evaporated, a process
that requires heat (endothermic process).
Next, the volatile component of the fuel is vaporized,
or destructively distilled; this process also requires heat
(endothermic) and as these vaporized gases combine with
oxygen heat is released (exothermic). The term "vaporized"
does not accurately describe what occurs during this process.
The atoms and radicals are separated from the carbon rings,
then the atoms and radicals are reformed to stable elements
and compounds. These cracked and reformed elements and
compounds undergo complete or partial oxidation in space
above the original material, if oxygen and sufficient igni-
tion energy are present.
2-12
-------
In the third combustion step, the remaining carbon -
called fixed carbon, charcoal, or char - undergoes partial
or complete oxidation at high temperatures, forming carbon
monoxide or carbon dioxide when oxygen is supplied under
proper conditions. The carbon oxidizes directly from the
solid state rather than changing to a vapor and then oxidiz-
ing, as in the second step. The third step is exothermic,
since heat is released in the process.
The principal characteristics of wood fuels are high
contents of moisture (usually), volatile matter, and oxygen.
About four-fifths of the fuel on dry basis comes off as
volatile matter and must be burned in the furnace space
above the grates. Only one-fifth is fixed carbon, which
must be burned on the grate.
The material remaining after combustion is ash, a
noncombustible material that must be disposed of. Some of
it collects in the furnace, while the remainder leaves, as
solid particulate, with the flue gas.
PRACTICAL ASPECTS OF WOOD COMBUSTION
Combustion theory is extremely complex; moreover, the
combustion of wood in a furnace does not always follow
theory. Practical usage requires the addition of some
empirical constant to the theoretical equations. Much
practical information concerning operation of wood-fired
2-13
-------
furnace-boiler systems can be obtained from firemen who may
not know the theory of wood combustion.
An example of this is the use of excess air as an aid
to combustion. Excess air is defined as that air exceeding
the theoretical amount necessary. Unless about 50 percent
excess air is provided for combustion of wood or bark fuels,
the boiler may emit black smoke, an indication of unburned
carbon from incomplete combustion. Provision of too much
excess air causes the furnace to cool and perhaps to emit
smoke. Thus, the proper amount of excess air is important.
Although a manufacturer may suggest a level of excess air
for operation of a new boiler, the operator should experi-
ment at levels around the suggested value to obtain optimum
combustion.
The amount of excess air is usually determined by
analyzing the flue gases with an Orsat flue gas analyzer or
similar device. A graph, as shown in Figure 5, is then used
to determine the percentage of excess air.
Another value that must be considered in operation of a
wood-fired boiler system is the "turndown," which is defined
as the ratio of the rated capacity of the boiler to the
minimum load that can be carried without losing the fire.
If, for example, the maximum rating of a boiler if 60,000
pounds of steam per hour and the minimum load that can be
2-14
-------
to
I
Ul
300 -
6 8 10 12 14 16
C02 OR 02 IN FLUE GAS, PERCENT
0 20 40 60
MOISTURE, PERCENT (WET BASIS)
Figure 5. Relation of excess air
to percentage of oxygen and
o
carbon dioxide in flue gases
Figure 6. Relation of heat loss to moisture
g
content of Douglas-fir bark
-------
maintained is 15,000 pounds of steam per hour, the turndown
is 4/1. A variety of factors such as fuel type, fuel mois-
ture, and altitude can affect the turndown ratio.
Moisture
Addition of an overly moist fuel will extinguish a
fire. Lesser amounts of moisture may still allow combustion
but at reduced boiler efficiency. Figure 6 illustrates the
loss of heat energy with increasing fuel moisture.
Figure 7 illustrates a drop in steam production with
increased moisture until the fire is extinguished at about
68 percent moisture (about 2 pounds of water per pound of
dry fuel).
The water-vapor content measured in flue gases from
hogged fuel boilers ranges from about 6 to 32 percent by
volume. In burning of hogged fuel with an average moisture
content of 45 to 50 percent by weight, the water-vapor
content of the flue gas in the stack will be about 20 per-
cent by volume. This value varies with moisture content in
the fuel, relative humidity of the air, and percentage
excess air. If these variables can be measured, the per-
centage of moisture in the flue gas can be calculated rather
than measured (obtaining values for relative or specific
humidity is difficult at 400°F).
2-16
-------
TO3 X 120
100
o:
Z3
o
1C
UJ
D-
O
D-
O
O
O
80
60
40
FURNACE BLACKS OUT
~68% MOISTURE —
LIMITS OF COMBUSTION
20 40
FUEL MOISTURE, % (WET BASIS)
60
I-
r
Figure 7. The effect of fuel moisture on steam production
as reported by Johnson
2-17
-------
Water is not measured by an Orsat gas analyses, even
though it is a normal component of flue gas. The Orsat
instrument passes the gas through a water bottle at ambient
temperature, and the moisture in the flue gas is condensed.
Ash Composition
Table 11, listing the ash compositions of jack pine,
birch, maple, and eastern hemlock as reported by the Canadian
Pulp and Paper Association, shows ash concentrations ranging
from 2.0 to 4.3 percent. Table 9, reporting ash concentra-
tions of western woods and bark, shows ash in sawdust rang-
ing from 0.1 percent to 2.0 percent and ash in bark ranging
from 0.2 percent to 2.5 percent. Apparently the western
fuels contain less ash than the Canadian fuels.
Brown reports the ash concentration of the average
fuel burned in the EWEB boilers as 1.88 percent. Table 12
lists the analysis of the EWEB ash. The composition of the
ash shown in Table 12 is all inorganic materials, although
in practice, it is usual to find 10 percent to 50 percent
organic, combustible material in fly ash and in ash removed
from the grates. The disposition of these combustibles in
the ash is discussed in Section 4.
Table 12 shows that the ash contains calcium, sodium,
magnesium, and potassium. These metals may be combined with
chlorine in the form of the salts or they may occur in their
2-18
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Table 12. ANALYSIS OF ASH FROM HOGGED WOOD-WASTE FUEL
Spectrographic analysis
Concentration, ppm
Silicon (Si)
Aluminum (Al)
Calcium (Ca)
Sodium (Na)
Magnesium (Mg)
Potassium (K)
Titanium (Ti)
Manganese (Mn)
Zirconium (Zn)
Lead (Pb)
Barium (Ba)
Strontium (Sr)
Boron (B)
Chromium (Cr)
Vanadium (V)
Copper (Cu)
Nickel (Ni)
Mercury (Hg)
Radioactivity
19.6
3.6
2.9
2.1
0.8
0.3
0.1
0.016
0.006
0.003
0.010
0.002
0.003
Less than 0.001
Less than 0.001
Less than 0.001
Less than 0.001
Nil
Nil
2-19
-------
oxidized form. The salt content of the fuel, and hence of
the ash, is primarily a function of whether the fuel is from
logs stored in salt water. Combustion Engineering reports
4
problems associated with storage of salt water.
In some instances, water-borne logs are formed into
large ocean-going rafts and towed to mills located
along the coast. En route they pick up considerable
quantities of salt, barnacles, and other marine growths.
The character of the foreign matter, and the extent to
which it is present in the wood-fuel will have consider-
able bearing on the design of furnace, as well as on
the arrangement of heat-absorbing surfaces. Thus, it
is of utmost importance to know whether the fuel comes
from salt-water or fresh-water logs because plants
burning the former are limited in the capacity at which
the boilers can be operated, owing to:
a. Salt that is contained with salt-water logs.
b. Shells that are calcined to calcium oxide and act
as a flux on the boiler brickwork.
c. Low-fusion-point and cementing properties of ash
that plugs gas passages, particularly when tubes
are closely spaced.
Burning of salt-water logs generates emissions of
highly visible particulate with the flue gas. The salt
particles do not burn and are small enough (0.5 to 1.0 y) to
escape the boiler and form a high-opacity plume.
Among the other inorganic materials in the boiler ash
reported in Tables 11 and 12 only lead, at less than 0.003
ppm would be considered toxic. This is in sharp contrast to
coal ash, which contains several toxic components.
2-20
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COMBUSTION OF WOOD WITH AUXILIARY FUELS
Approximatley half of the wood-fired boilers in the
United States incorporate no provision for auxiliary fuels.
These boilers are totally dependent on wood for maintaining
steam output. If the flow of wood is interrupted or the
fuel is too wet to sustain combustion, the fire will cease
and the system must be shut down. Most of these systems
operate satisfactorily under these constraints.
The other half of the wood-fired boilers depend on one
or more auxiliary fuels for continued operation. Auxiliary
fuels are used for four principal reasons.
1. The furnace-boiler system may be unable to produce
the required energy on wood alone. In these cases
auxiliary fuel may be used to support combustion.
2. The supply of wood may be limited or may be inter-
rupted; for example, a failure of the conveying or
firing system may require us of an auxiliary fuel
while repairs are completed. (Repair of a broken
conveyor belt in a bucket elevator may require as
long as 24 hours.) Burning an auxiliary fuel
permits continuous steam generation during repairs.
3. Occasionally wood fuel may be so wet that an
auxiliary fuel is required to support combustion
and maintain boiler pressure. A furnace such as
that in Figure 7 would need an auxiliary fuel if
the fuel moisture reached 68 percent. At 50
percent moisture it would need an auxiliary fuel
to produce more than 80 percent of its rated
capacity of 120,000 pounds of steam per hour.
4. A large boiler may have steam-driven turbines for
the forced draft and induced draft fans. The
boiler can reach pressure from a cold start by
using gas or oil as an auxiliary fuel with small,
electrically driven fans.
2-21
-------
Wood/Oil
Many of the larger wood-fired boilers in operation
today were built in the first 10 years after World War II.
During this period the wood products industry expanded
rapidly and many mill operators recognized the need for
boiler capacity. At that time residual or bunker oil was
very inexpensive and was considered an ideal auxiliary fuel.
At many mills gas lines were not extended to the property
line and the mills were not situated near supplies of coal.
The only choice of auxiliary fuel was oil.
The heavy oil is fired into the boiler through mechani-
cal atomizing burners or steam-atomizing nozzles. The oil
must be kept heated so that it does not congeal in the tank,
lines, and burners. In a well-designed system, the change-
over from wood fuel to oil can be accomplished in a few
minutes. The oil flame has about the same characteristics
as the wood flame, and the system adapts itself to control
with only minor adjustments.
Use of oil as an auxiliary fuel entails some disadvan-
tages:
1. The rapid increase in the price of oil is an
inducement to use as little oil as possible.
Today it may be more economical to spend addi-
tional capital for fuel-drying facilities than to
rely on oil to help dry the fuel within the furnace,
2-22
-------
Burners of oil in combination with wood may cause
fluxing of any refractory surfaces in the furnace
and thus increase maintenance requirements. It is
advisable to burn either oil or wood, and not to
burn them concurrently.
Some residual oils contain high percentages of
ash. Combustion of oil with an ash content greater
than that of the wood for which the boiler was
designed will tend to overload the air pollution
control equipment. Many boilers produce no plume
when wood is fired but show a highly visible plume
when oil if fired.
Residual oils may contain a high percentage of
sulfur, as high as 4 percent. When this oil is
fired, a boiler may emit more SC>2 than regulations
allow. Most states now limit the amount of sulfur
permitted in residual oil to 2 percent or less
(Oregon will not allow sale of residual oils with
sulfur content exceeding 1 3/4 percent).
Wood/Gas
In some areas natural gas is used as auxiliary fuel
with wood-fired boilers. The natural gas requires no trans-
portation, storage, or handling. A gas burner is a simple
device, and a boiler can be switched rapidly to the auxili-
ary fuel. Some problems occur because the luminosity of the
gas flame is different from that of the wood fuel flame.
Several, properly placed gas burners are required for proper
firing. Also, many additional controls are required for
"safe handling" of natural gas.
Some boilers use propane or other liquified gas for
auxiliary fuel. Such fuels are clean and readily available.
The prices of liquified petroleum gases and natural gas
have risen repidly in the past few years. If natural gas is
2-23
-------
sold on an interruptible basis, it may be in short supply
and at a high cost when needed most.
A recent innovation at wood-fired power plants is to
use the boiler as an afterburner for gaseous contaminants
from other operations in the facility. Both veneer dryers
and particle dryers may be vented to the boiler through
heated lines to prevent condensation of the organics.
Although the heating value of these hydrocarbons is probably
minimal, such arrangements should be considered in view of
the need for pollution control.
Wood/Coal
Using coal as an auxiliary fuel is advantageous in that
the coal is a solid fuel, such as the wood, and it may be
cheaper than other auxiliary fuels. Many other factors
indicate that coal is an undesirable auxiliary fuel:
1. Ash or sulfur contents may be high compared with
those of the wood or bark fuel. Combustion and
flame properties of a low-ash, low-sulfur coal
(such as anthracite) will be greatly different
from those of the wood fuel.
2. The coal will probably be delivered to the boiler
by the same conveyor-feeding system as the wood
fuel. If the conveyor or feeding system fails, no
fuel will be supplied to the boiler.
3. Even though coal and wood are both solid fuels,
the density differs greatly. A system designed to
handle wood can fail if subjected to heavier loads
because of more dense fuel.
2-24
-------
4. Many areas where wood is plentiful are remote from
coal fields. The cost of shipping large tonnages
of coal 1000 miles or more may increase the total
cost of this fuel above that of oil or gas.
5. The ash content of subbituminous coal may be as
high as 30 percent. This can cause serious prob-
lems unless the ash removal and handling systems
are designed for fuels of high ash content.
6. The coal may be wet, nearly as wet as the wood.
Moisture is not a problem with gas or oil auxili-
ary fuels.
7. Coal requires cleaning, sizing, and screening
equipment that is not suitable for wood fuels.
8. Coal tends to form clinkers in the furnace.
9. Rail cars for coal shipment may be in short supply.
10. The environmental impact of mining the coal may be
serious.
Wood/Solid Wastes
Some wood-fired boilers are being fired with relatively
small amounts (10 to 20 percent) of classified solid refuse.
The Georgia Pacific paper mill at Toledo, Oregon, recently
considered a contract to buy the combustible portion of air-
classified municipal refuse from Lincoln County, Oregon.
The paper mill would fire the combustible refuse in their
power boilers, along with wood residue and bark fuel, for
process steam generation. The EWEB is considering similar
use of classified municipal refuse in their boilers.
Combined Systems Using Multiple Fuels
Some mills are operating new furnaces that allow com-
bustion of multiple fuels. Consider a refractory chamber
2-25
-------
connected to a boiler. The chamber can handle wood fuel,
pulverized coal, gas, or oil or any combination of these.
This type of combustion chamber is called an "energy cell."
The major problem seems to be that such "energy cells"
require a compromise and do not fire any one fuel in a way
that maximizes efficiency or minimizes pollution. A wood-
fired furnace designed to fire a certain species, of a
certain size, at a certain moisture content is much more
efficient than an all-purpose "energy cell."
2-26
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3.0 PROCESS DESCRIPTIONS
To release the heat energy of wood residues and baik in
a boiler it is desirable to maximize the efficiency and
utilization of fuel while minimizing pollution, complexity,
and maintenance costs. A specific combustion system may
very well represent a compromise among these desired objec-
tives. It is critical that all components of the system
(fuel handling, firing, ash removal, pollution control) be
suited to the available fuel, or alternatively, that the
fuel be selected to suit the available system. Johnson
states that more than 40 types of burner systems alone could
be used for firing wood or bark. Complete boiler systems
range from "off-the-shelf" units, to package systems, to
units that are custom engineered and constructed, costing
many millions of dollars. This section describes some of
the major components of wood-fired combustion systems:
handling and storage facilities, furnace and boiler units,
instrumentation, and process controls.
WOOD HANDLING AND STORAGE SYSTEMS
Because of the diversity of the wood fuels available
today, the fuel handling systems must be designed for a
3-1
-------
specific fuel or combination of fuels. Provisions must be
made for receiving or handling, storing, drying or cleaning,
sizing, and eventually delivering the fuel to the furnace at
the proper rate. Ideally, these operations are geared for
the handling and treatment of specific types of wood fuels.
Hogged Fuel
Hogging of wood residue and bark usually is done at the
point of generation because it is easier to handle and
transport the hogged fuel than the large chunks of wood or
bark. The fuel delivered to the power plant may need addi-
tional classification and sizing before it is fired. Figure
8 depicts the system used at the EWEB power plant. The
fuel is originally stored outside because of the small
capacity of the covered storage. Fuel is drawn from the
covered storage by remotely controlled conveyor systems to
fill each boiler's overhead bin as needed. These controls
are mounted on the boiler console for operation by the
boiler operator. Each wood-waste-fired boiler is equipped
with a set of feed controls with monitoring TV cameras and
meters.
Figure 9 shows a more general system for handling of
Q
hogged fuel as described by Junge. In practice, final
storage in a fuel house or covered bin would be desirable.
Experience has shown that Btu content of hogged fuel
can be reduced substantially during storage for long periods
3-2
-------
DELIVERY ON PILE
BY SELF-UNLOADING
TRUCKS
OUTDOOR
STORAGE
40,000 UNIT
MAX. CAP
CHAIN
FLIGHT CONV.
SHAKER
SCREEN
11/2X3 1/2
MESH
•HUNITS/HFI
REHOGG
3 TON
HAMMERMILL
COVERED
HO UNIT CAP.
REMOTE
VARIABLE SPEED
REMOVAL
200 FT.J AVERAGES 360O
70% FIR BARK 30% WOOD
40% MOISTURE BY WEIGHT
BELT CONVEYOR
< ' CHUTE
BELT SPREADER CONV.
T Y
FUEL BIN #2 BOILER
10 UNIT CAP
FUEL BIN # J BOILER
16 UNIT CAP.
CHUTE
CHUTE
JT
AUTO CONTROLLED FUEL FEEDERS
EA. W/CHUTE TO A BLR.
AIR - SPREADER - STOKER
TT1 TUT
AUTO CONTROLLED FUEL FEEDERS
EA. W/CHUTE TO A BLR.
AIR-SPREADER-STOKER
HOGGED WOOD-WASTE FUEL SYSTEM
STEAM POWER PLANT
EUGENE WATCH 8 ELECTRIC BOARD
CuOfNf . OWfGON
Figure 8. Hogged wood-waste fuel system.
3-3
-------
Figure 9. System for preparing hogged fuel.
1. Pile of rough fuel.
2. Metal detector.
3. Separating screen.
4. Hog for pieces too large to pass through the
separating screen, with conveyor to recirculate
hogged pieces.
5. Conveyor for material that passes through the
separator screen.
6. Storage for hogged fuel.
TRUCK DUMP
CONVEYOR TO
STORAGE
Figure 10. System to limit fuel-storage time by insuring
that fuel first into storage will be first out to be burned,
(Rader Pneumatics Company, Portland, Oregon.)
3-4
-------
at high moisture levels. According to one study, hogged
Douglas fir lost 7 percent of its initial heating value over
10 months. As a rule of thumb, hogged fuel should not
remain in a pile more than 3 or 4 months.
A first-in, first-out system for fuel storage is effec-
tive in limiting storage time. For most plant sites, this
would require addition of, or modification of conveyor
systems. Figure 10 illustrates one such scheme for fuel
storage.
Sawdust
Sawdust is the wood fiber removed by saws during cut-
ting. The ash content is low because it is mostly white
wood, not bark. Size of particles ranges from 1/32 to 3/8
inch depending on the saw, the wood species, the direction
of cut, and other factors. Moisture content is the same as
that of the original wood, 25 to 50 percent on a wet basis,
but sawdust can be dried more readily because of its rela-
tively high surface-to-volume ratio. Sawdust may be trans-
ported by mechanical conveyor systems or pneumatic systems.
Although it can be fired separately, it usually is blended
with the hogged fuel either in the storage system of in the
fuel feed system just ahead of the furnace. Because it is
smaller than the hogged wood, the sawdust settles toward the
bottom rather than remaining uniformly distributed through-
out the fuel pile.
3-5
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Shavings
Shavings are generated during the manufacture of dimen-
sion lumber when rough-sawed wood is planed to its final
size. Since the wood is dried or seasoned before it is
planed, the moisture content of shavings is low, 10 to 20
percent on a wet basis. The shavings are flat (like corn-
flakes) with dimensions of about 1/32 by 1/2 by 1/2 inch.
Thus these particles also have a high surface-to-volume
ratio. Shavings are transported almost exclusively by
pneumatic systems, usually terminating in a cyclone that
drops the shavings into a bin or directly into the furnace
feed system. Shavings are desirable as raw materials for
particle board and hardboard and are used for fuel only in
areas where their use for board products is not economical
because of long transportation distances.
Chips
Wood chips are seldom used as fuel unless supplies of
hogged wood and bark are not available. A paper mill chip
is about 1/2 to 1 inch on a side and about 1/8 inch thick.
Except for size, their properties are similar to those of
hogged wood. Chips are an excellent fuel, and even though
priced at 5 to 10 times the price of hogged wood they may be
less expensive than an energy-equivalent amount of oil.
Chips are nearly always transported by a pneumatic system
with a cyclone as the terminal separation device.
3-6
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Sanderdust
Sanderdust is generated by high-speed sanding of ply-
wood or particle board. Some is also generated by a rela-
tively new abrasive planer that is used to finish dimension
lumber. Sanderdust is extremely dry, and the particles are
very small (less than 1/32 inch). Moisture content ranges
from 2 to 8 percent on a wet basis. Because this material
may be explosive, it should be handled and transported with
utmost care. Sanderdust is transported pneumatically. The
terminal cyclone may require a baghouse downstream to comply
with air pollution control regulations. If sanderdust is to
be used as fuel in either a boiler or a dryer, it is stored
in a bin before firing. In operations that attempt to burn
the sanderdust directly from the process, without a surge
bin, problems may occur with "puffs" and "flame-outs" or
even explosions.
Particle Board and Hardboard Residue and Trim
Particle board and hardboard are made of wood fibers,
usually mixed with resinous materials and pressed into the
product form. Trim, sawdust, sanderdust, and reject fiber
from these processes provide an excellent, dry fuel for
wood-fired boilers. This material may be finely divided and
should be handled with the same care as sanderdust. Since
it may contain various quantities of resin, this should be
3-7
-------
evaluated in terms of fuel characteristics and possible
effects on furnace and boiler. Particle board and hardboard
residues are usually handled by pneumatic systems with surge
bins ahead of the boiler feeding system.
Mixtures of Wood Residue
As mentioned earlier, an ideal system is designed to
operate with one type of fuel. A furnace designed for
hogged wood will not burn sanderdust efficiently. In some
systems, "energy cells" are used to burn various types of
fuel to generate hot gas, which then passes to and through a
boiler. Such systems require careful control to achieve
satisfactory, pollution-free combustion.
Different types of wood residue fuel are sometimes
mixed before feeding to the furnace. An example is the
mixing of dry sanderdust with wet hogged fuel or bark. The
sanderdust absorbs water, which makes it less explosive, and
the hogged fuel is dewatered, which makes it more combustible,
Predrying Systems for Fuel
Systems for predrying wood residue and bark fuel are
relatively new. They were developed to overcome two serious
shortcomings of wood fuel. The first problem is the extreme
variability in moisture content of hogged wood, sawdust,
bark, and even other "dry" fuels. The moisture content is
affected by species, handling, storage conditions, and
3-8
-------
similar factors. Drying the fuel outside the furnace allows
both manufacturers and operators to deal with a more uniform
fuel.
The second reason for predrying of the fuel is to put
the fuel into the furnace with a minimum of water present.
This increases both the thermal efficiency and steam-generat-
ing capacity of the boiler. The fuel can be ignited more
readily, since the energy needed to evaporate water can now
go to volatilization of combustibles. The boiler responds
more rapidly with drier fuel. The elimination of gaseous
water from the flue gas reduces both the gas volume and the
corresponding gas velocities. Thus, smaller fans can be
used, and particulate carryover is reduced.
Q
Fuel moisture may be controlled by several methods:
1. Vibrate "loose" water off the fuel on a shaker
screen.
2. Press out water mechanically.
3. Drive off moisture by heating the fuel in dryers.
4. Cover the fuel storage pile to exclude rain water.
5. Control the processes that generate the fuel to
limit water addition.
6. Mix the fuel to provide a fuel of uniform moisture
content.
Each of these moisture-control methods has limitations.
Removal of water by vibration may be effective when the
moisture content exceeds 55 percent. If the process that
3-9
-------
generates the wood adds large quantities of moisture (for
example, hydraulic barking), vibration can be an inexpensive
and low-maintenance approach to control of surface moisture.
Presses can remove only limited amounts of moisture.
For most hogged fuel, pressing can reduce moisture levels to
50 to 55 percent. Heating the fuel can reduce moisture
content. Moisture levels in a range from 25 to 35 percent
are usually adequate for good combustion. At levels below
20 percent, significant dust problems can occur with "fines."
Heating-type dryers have the potential for generating
pollutants of three types: if the wood fuel is overheated
(above 300°F) the volatile organic material will evaporate-
and leave the dryer with the exhaust gas stream, which may
condense in the atmosphere to form a visible plume; dry
"fines" may create a dust problem; and, if the dryer is
fired by a separate combustion system, products from the
combustion 'process may become pollutant emissions.
Covering the fuel storage will keep rain off the fuel,
a significant benefit in wet climates. The disadvantages
lie in cost of the structure and restriction of access to
the fuel pile in event of a fire. If fuel is put through a
drying system, particularly one that reduces moisture levels
to less than 45 percent, covered storage of the dried fuel
may be desirable.
3-10
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Control of water additions to fuel in production pro-
cesses is usually difficult. For example, most plants
cannot replace hydraulic barkers with mechanical barkers. A
trend toward dry-deck log storage and sorting rather than
ponding of logs can reduce moisture levels in wood residues.
Careful inspection of the processes that generate wood
residues may indicate other sources of water addition that
can be controlled.
Adequate fuel mixing can be accomplished by spreading
fuel across the face of a pile and removing the fuel from a
central pick-up point. As noted earlier, mixing brings
about uniformity in both size and moisture content and thus
enhances the stability of the combustion process.
Three systems are currently being considered for drying
fuel outside the furnace-boiler system. These systems can
be operated with separate burner systems (fired with sander-
dust or other fines) or by directing boiler flue gases from
the stack to the fuel dryer. Use of stack gases puts the
drying system in series with the boiler; thus a fuel dryer
breakdown interrupts the feeding of dry fuel to the boiler
and a boiler breakdown shuts down the fuel dryer. These and
many other factors must be considered with respect to exter-
nal fuel drying. A competent consultant should be engaged
in early stages of process planning. Following are descrip-
tions of the three major external drying systems.
3-11
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1. "Hot-Hog" System
In the hot-hog system (Figure 11), wet material is fed
at an even rate to a grinder or hog that also can accept
high-temperature gas. Breaking up the material exposes
large amounts of surface area and makes it easy to drive off
moisture. The power of the hogging and the tremendous
turbulence facilitate drying of the fuel material. Within
seconds, it becomes a fine, dry material, ready for storage.
A word of caution is that white wood is more difficult to
process than bark.
A classifying system above the hog returns oversize
material to the hog for regrinding. The vent from the low-
efficiency (first) cyclone should contain the fines and
dirt. A high-efficiency (second) cyclone receives the dirty
gas stream. Fines are separated and returned to the heater
system for reburning. Moisture and combustion gases are
vented after the second cyclone. Recirculation of part of
the gas stream provides fuel savings and reduces emissions
of gas to the atmosphere.
The dry fuel is also fuel for the heater. The air
heater incorporates a skimmer system, which removes any
large particles of unburned material. Hot gas goes back to
the hog to complete the cycle.
3-12
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VENT
(TO BAG-
HOUSE IF
NECESSARY)
Figure 11. Typical hot-hog dryer system.
WET WASTE WOOD
CYCLONE
SEPARATOR
DIRT a FINES
DIRT V COARSE FUEL
B TO STORAGE
FINES
FINE FUEL TO BURNER
Figure 12. Typical rotary dryer.
3-13
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2. Rotary Dryer System
A rotary dryer system (Figure 12) is best used for
drying a large quantity of wood waste with high moisture
content. This system can accommodate high inlet tempera-
tures (up to 1800) if the moisture content of the fuel is
high enough to absorb the available heat energy without
overheating the wood surface. Overheating the wood would
cause some distillation of volatiles, which contribute to
the "blue-haze" problem.
Wet fuel should be screened and the oversize pieces
rehogged. Long residence time (10 to 20 minutes) permits
drying of 2- to 4-inch pieces without difficulty.
A particular advantage of the rotary dryer is the
opportunity to effect a three-way internal separation of
fine, medium, and coarse particles. Double receiving hop-
pers beneath the dryer receive medium and coarse sizes, and
airborne fines go to the cyclones.
3. Hot-Conveyor Dryer
In the hot-conveyor system (Figure 13), the vibratory-
type conveyor is fully enclosed with a hood. Hot gas from a
boiler stack or from an air heater is pushed into a plenum
underneath. The bed of the conveyor is a type of orifice
system that fluidizes the material and provides good gas
contact with the wood. The moisture and flue gas are vented
3-14
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WET WASTE WOOD
50-70% M.C.
VENT
220° F
DIRT a FINES
TO DUMP OR
SPECIAL BURNER
TO FUEL BIN
~40% M.C.
HOT GAS FROM BOILER STACK (500°)
OR
FROM DUST-FIRED AIR HEATER (600'F)
Figure 13. Typical vibratory hot-conveyor dryer,
F U t L IN
TO CINDER
COLLECTORS,
AIR HEATER
8 STACK
AUX. FUEL
BURNER
(IF USED)
UNDERFIRE
' AIR IN
Figure 14. Dutch oven furnace and boiler,
3-15
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from the hood through a fan to a cyclone or to a cleanup
system.
WOOD-BURNING FURNACES
Because of the variable properties of wood residue and
bark, the combustion engineer is faced with a difficult task
in designing a furnace that will properly consume fuel to
generate heat for the boiler. The design must be flexible
enough that the furnace can handle the anticipated fuel,
with nonuniform moisture content, and still follow the steam
load demand on the boiler. The furnace may be separate from
the boiler or integral with it. If it is separate, the
firing is external to the boiler and the hot gases (which
are probably still burning) are directed from the furnace to
the boiler. If the furnace is integral with the boiler, the
fuel is burned in the boiler, which is surrounded by heat
transfer surface. Both types are in use in the United
States today.
Designing or selecting a furnace or furnace-boiler
system requires consideration of several subsystems:
1. The fuel system by which fuel is introduced to the
furnace must be capable of delivering the fuel at
variable rates. It must be reliable and easily
maintained. Both cost and energy requirements
must be considered in fuel system design.
2. The air system supplies air for combustion and
possibly for cooling of grates or refractories.
The air system must follow variations in fuel flow
and maintain efficient combustion within the
3-16
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furnace. If the system operates by natural draft,
the stack must be properly designed. Most modern
plants do not use natural draft systems but in-
stead rely on fans to maintain air flow. The fans
may be driven by electric motors or steam turbines.
The total air system includes grates, ductwork,
dampers, and controls and may also incorporate an
air heater.
3. The ash handling system must be sized for the
dirtiest possible fuel, that is, for fuel with the
maximum expected ash content. Not all of the ash
contained in the fuel drops through the grate to
the ash pit. Some is carried through the boiler
with the combustion gases where it may accumulate
in "dead spaces." If it does not remain in the
boiler, it enters the stack as fly ash. This fly
ash is either removed from the flue gases by
pollution control devices or emitted from the
stack with the gas. If it is removed, final
disposal of the fly ash must be considered.
4. Instrumentation and control systems enable the
operator to fire the furnace for maximum effi-
ciency while minimizing pollution. The pollutant
of concern, particulate matter, is generated in
the furnace and carried through the boiler.
Although the monitoring and control systems are
expensive, they are needed to ensure that the
plant operates in compliance with the applicable
regulations.
5. An auxiliary fuel system that carries the load
when wood fuel is not available must be designed
to come on line rapidly and efficiently. The air
supply system and the instruments and controls
must function well with the auxiliary fuel system.
Dutch Ovens
The Dutch oven was the standard design used for wood
firing before World War II. Because these are relatively
small units, steam plants that use them often operate several
in parallel to provide the desired capacity. Figure 14 is a
3-17
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cross-section of a Dutch oven, which is primarily a large,
rectangular box, lined on the sides and top with fireback
(refractory). Heat is stored in the refractory and radiates
to a conical fuel pit in the center of the furnace. The
heat aids in driving moisture from the fuel and evaporating
the organic materials. The refractory may be water-cooled
to minimize damage of the furnace by high temperatures.
The fuel pile rests on a grate through which underfire
air is fed. Overfire air is introduced around the sides of
the fuel pile. By design, combustion in a Dutch oven or
primary furnace is incomplete. Combustion products pass
between the bridge wall and the drop-nose arch into a second-
ary furnace chamber, where combustion is completed before
gases enter the heat exchange section.
This furnace design incorporates a large mass of refrac-
tory, which helps to maintain uniform temperatures in the
furnace region. This tends to stabilize combustion rates,
but also causes a slow response to fluctuating demands for
steam. The Dutch oven system works well if it is not fired
at high combustion rates and if the steam load is fairly
constant. With this design, however, the underfire airflow
rate is dependent upon height and density of the fuel pile
on the grates. When the fuel pile is wet and deep, the
underfire airflow is low and the fire may be deficient in
oxygen. As the fuel dries and the pile burns down, the flow
3-18
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rate increases as the pressure drop through the fuel pile
decreases. In this manner an excess of air develops in the
furnace. With fluctuating steam loads, the result is a
continuous change from insufficient air to excess air.
Because of this feature, together with slow response, high
cost of construction, and high costs of refractory main-
tenance, the Dutch oven designs are being phased out.
In a well-designed Dutch oven a grate approximately 9
feet on each side is close to the economical limit of area
that can be supplied with fuel from one feed opening. The
feed opening is located so that the conical pile thins to a
feathered edge at the furnace front and reaches a depth of
12 inches at the bridgewall. With empirical factors, toget-
her with the known slope of the pile and the clearance
between apex and arch, it is possible to determine required
height of arch above the grate. The maximum size of the
furnace unit or cell are thus well-defined and standardized.
The dimensions most frequently used for Dutch oven grates
are 8 feet wide by 9 1/2 feet long and 9 feet wide by 11
feet long.
Dutch ovens are usually designed with gravity systems
that feed fuel from an overhead conveyor. Airflow may rely
on natural draft or fans. Heated forced-draft air is some-
times used, but most designs rely entirely on the mass of
the refractory to dry the fuel.
3-19
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Ash removal is a major problem because not all the ash
drops through the grates to the ash pit. Provision must be
made for shutting down the furnace periodically to rake the
ash from the grates. When several Dutch ovens are operating
in parallel, one may be inoperative for cleaning.
Auxiliary fuel usually is not fired into the Dutch oven
but rather into the secondary chamber below the boiler.
4
Combustion Engineering reports high maintenance costs
because of the tendency of the refractory surfaces to flux
when oil is burned in combination with wood; continuous use
of auxiliary fuel is not recommended for Dutch ovens.
Most Dutch ovens at lumber mills are of the flat-grate
type shown in Figure 14. A sloping-grate furnace is used at
some paper mills that burn wet bark. The fuel enters the
front end of the furnace across its full width and travels
down the sloping grate as it moves through the furnace. The
upper front section of the grate, which forms the primary
drying zone, consists of a refractory hearth set at an angle
of approximately 50 degrees. A regulating gate controls
fuel-bed thickness at the point of entrance.
The middle section is composed of stationary grate bars
set at an angle of 45 degrees and provided with horizontal
spaces to admit air. The lower section of the grate is set
at slightly less than 45 degrees and may be provided with
3-20
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fuel-pushers that can be operated as required. Horizontal
dump plates extend from the end of the grate to the bridge
wall. Progressive feeding of the fuel from point of entrance
to the dump is secured by grate slope. As the fuel dries,
it slips more readily and the lesser slope in the second
section serves as a retardant. The slope of the third
section prevents the formation of an excessively thick fuel
bed at the bridge wall end of the furnace. A portion of the
combustion air is supplied through the two lower grate
sections, and the remainder through tuyere openings in the
front of the bridge wall. The face of the bridge wall is
sloped to cause gas from the lower end of the fuel bed to
sweep over and mix with gases coming from the drying section
of the furnace.
The fuel bed of the sloping-grate furnace is compari-
tively thin so that, with relatively low undergrate pres-
sures, air can be distributed through the bed to provide
uniform combustion throughout. For good operation, however,
the fuel should be quite uniform in size; otherwise streaks
or pockets of greater density than adjacent areas may lead
to formation of blowholes in the thin portions of the bed.
The rate of combustion can be increased more rapidly, in
relation to the draft, than in flat-grate furnaces, although
the latter can carry much higher overloads. By carefully
3-21
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controlling the rate of feed and using zoned air supply, the
operation can obtain complete combustion with lower draft
velocities and less excess air than in operation of flat-
grate furnaces. Because of this responsiveness, the in-
clined grate lends itself to the use of automatic combustion
controls.
Another type of furnace that operates on the same
principle as the Dutch oven is the Dietrich cell. Figure 15
shows a single Dietrich cell under a small, horizontal-
return-tube boiler. The cell acts to gasify the fuel, and
the burning gases then enter the boiler. The operational
constraints on the Dietrich cell are the same as those on a
Dutch oven. For both, the maximum turndown is 3/1. Control
is difficult with rapidly varying steam loads. Refractory
maintenance is expensive and time consuming. The ashes must
be raked by hand, and disposal is usually by means of a
wheelbarrow to an open outside pile.
Spreader Stokers
Since World War II nearly all of the wood-fired boilers
constructed in the United States have been spreader stokers.
The design earlier proved satisfactory for coal firing, and
many of the early units were only slightly modified to fire
wood residue or bark. Some of the more recent units have
been specifically designed for wood firing. The spreader
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STACK
*- STEAM TO KILN
FUEL
SCREW CONVEYER
ASH DOOR
AIR PLENUM
Figure 15. Pile burning: "Dietrich" cell.
3-23
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stoker is an example of an integral furnace-boiler system.
The fuel is burned in the base of a water-wall boiler unit
rather than in a refractory chamber. Figure 16 illustrates
a spreader stoker at the EWEB power plant. Figure 17 shows
a typical small package spreader stoker, which can be sent
to a plant in modules and rapidly erected. Several unique
features distinguish the spreader stoker from the Dutch
oven.
1. The fuel is dried by hot forced-draft air rather
than by radiant energy from a large mass of refrac-
tory. This is accomplished by passing the flue
gases through a gas-to-gas heat exchanger before
exhausting them to the stack. The forced-draft
fan takes in ambient air and blows it through the
heat exchanger, where it is heated to approxi-
matley 400°F before going to the furnace. This
hot air is forced through the thin bed of fuel on
the grates to dry the fuel.
2. Fuel is fed to a spreader stoker from an overhead
conveyor, usually through a variable-speed auger
metering system, to the spreader located at the
front of the boiler. The spreader may be a mechani-
cal "paddle wheel" type, which knocks the hogged
fuel into the furnace, or a pneumatic type, which
uses air pressure to blow the fuel across the
grates.
Figure 18 shows the pneumatic stoker installed at the
EWEB plant.
The spreader-stoker system may use a traveling grate, a
dump grate, or a fixed grate. The traveling grate moves
from the rear of the furnace toward the front. The larger
pieces of fuel are thrown to the rear of the furnace and
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BOILER
SMOKE r
INDICATOR^
(Jl
MECHANICAL
OUST
COLLECTOR
D
VARIABLE
SPEED FEED
DRIVE
Figure 16. Spreader stoker fired stean generator
EWEB - Number 3 6
-------
STEAM OUT £
STACK
OVERFIRE
AIR
SPREADER
STEAM DRUM
AIR HEATER
MULTIPLE
CYCLONE
COLLECTOR
WATER WALL FURNACE
Figure 17. Small spreader-stoker furnace.
3-26
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DEFLECTOR PLATE
PNEUMATIC STOKER
NO. 2 BOILER
EUGENE WATER a ELECTRIC BOARD
EUGENE,OREGON
Figure 18. Pneumatic stoker - No. 2 boiler
3-27
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therefore remain on the grate longer to burn. The ashes on
a traveling grate system are dumped at the front of the
furnace.
3. Because the spreader stoker is an integral furnace-
boiler system it is substantially smaller than a
Dutch oven of the same output. Because of the
smaller size and lighter weight (no refractory),
small units can be transported by truck or rail.
4. Spreader stokers respond rapidly to load changes.
The thin fuel bed and lack of refractory contri-
bute to a low "thermal inertia." This rapid
response can be detrimental, however, because only
a brief failure of the fuel system causes the fire
to be extinguished. Turndown ratios of 4/1 are
quoted for spreader stokers.
Extremely large spreader stokers are currently being
constructed to provide steam power from wood residue. A
recent proposal for EWEB calls for four spreader stoker
boilers with capacities of 400,000 pounds per hour generat-
ing steam at 950°F and 1450 psi. This steam would power two
62.5-MW turbines. The estimated cost of the entire project,
including fuel storage, power plant, and cooling tower is
$53 million (1976 dollars).
Fuel Cells
Fuel cells are suspension burning systems that burn
small-size, dry fuel supported by air rather than by grates.
The fuel particles, mixed with combustion air, completely
fill the combustion chamber. This feature is in contrast to
fluidized bed combustion, where in fuel particles remain in
3-28
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the "bed" even though supported by air. Sanderdust usually
is burned in this manner. With adequate size reduction,
wood and bark residues also can be burned in suspension.
The advantages of suspension burning include low capital
costs for combustion equipment because no grates are re-
quired and ease of operation, as grate cleaning is eliminated.
The ash goes into suspension as particulate matter in the
exhaust stream or falls to the furnace bottom for removal.
Rapid changes in rate of combustion are possible.
Figure 19 is a fuel cell of this type. Figure 20 shows
the same fuel cell installed to supply heat to a boiler.
Suspension burning has disadvantages, however. Because
most of the ash escapes with the exhaust gases, control of
fly ash may be difficult. For this reason some suspension
units are designed to "slag" or melt the ash in the combus-
tion chamber and thus reduce the amount of ash entrained in
the exhaust-gas stream. Temperature control in the combus-
tion chamber is critical. If the ash-fusion temperature is
exceeded, the ash may form large pieces, which can plug or
damage the system. Fuel preparation must be thorough to
provide sizes small enough for suspension burning. Moisture
content also must be controlled within reasonable limits, a
requirement that can be costly for systems burning wood and
bark. With sanderdust fuel, no further processing is needed.
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INSULATION
AIR PLENUM
FUEL FEED INLET
AUXILIARY BURl
BUTTER
COMBUSTION Al
MANIFOLD
Figure 19. The Energex cyclonic burner.
WOOD FUEL FROM
ENERGEX METERING BIN
Figure 20. An Energex-fired package boiler,
3-30
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Residence time is critical (as in any combustion system).
Suspension burning inherently provides short residence. At
high combustion rates, the residence time may be insufficient
for the process to go to completion.
The capacity of fuel cells is limited; therefore, as
more energy is needed, more fuel cells are added. As fuel-
drying systems are perfected, it is probable that more fuel
cells will be used, even on larger boilers. Figure 21 shows
the complete system requirement for use of wet wood residue
and bark as a fuel for a large suspension burning system.
Fuel cells are particularly hard on refractory because of
the high temperatures involved.
Fluidized-Bed Combustion. One of the newer systems
developed to burn solid fuels is the fluidized-bed combus-
tion furnace. The system can burn high-moisture fuels and
can react to changes in steam demand more rapidly than some
of the other systems. Fluidized-bed combustion of cellulose
materials was originally developed to incinerate wastes from
pulp and paper mills having moisture contents up to 67
percent.
The fluidized-bed system incorporates a large mass of
finely ground inert material (like sand), which provides a
very large exposed surface area. The inert material is
contained in a vessel, through which air is passed upward so
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COARSE
FUEL
STORAGE
= 35%M.C.
PRIMARY
AIR FAN
250 Ft
J
FLUE GAS
CLEANING
FINE, DRY WOOD
105! M.C.
)SUSPENSION BURNERS
10IL/GAS STAND BY
Figure 21. Large suspension burning system.
3-32
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that the bed becomes "fluidized"; it resembles a boiling
liquid that keeps the particles in a state of constant
agitation. The bed is preheated to about 1400°F. When a
finely divided solid fuel is introduced, the hot inert mass
provides sufficient energy capacity and radiating surface to
"flash" evaporate the fuel moisture and gasify the volatile
component of the fuel. The remaining fixed carbon in the
fuel is oxidized as it. moves through the f luidized bed. The
process generates little or no flame but rather a glowing
bed. Combustion is rapid, and the fluidized bed proper
contains no unburned organic material. Particulate emis-
sions are therefore minimal.
The fluidized bed may be used as a hot gas generator
for a separate boiler, or heat may be transferred directly
from the bed to the steam by placing bundles of tubes in
contact with the inert material of the bed.
In a 1975 presentation, Keller described application
of the fluidized-bed system to steam plants using wood
residue fuels and indicated plans by Energy Products of
Idaho to have ten fluidized bed units in operation by September
of that year. This development has not proceeded on schedule.
Direct Firing Applications
Within the past 5 years, installations have been made
in the United States in which the hot gases from burning
3-33
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bark (and wood) are used directly for heat. Applications
involving direct firing of wood and bark include veneer
dryers, drying kilns for lumber, and dryers for wood and
bark particles.
12
Deardorff describes a pile-burning, hogged-fuel-fired
furnace that supplies heat directly to a veneer dryer.
Jasper and Kock report on a suspension burning system in
which undried bark is pulverized and burned in a cylindrical,
annular combustion chamber. The system has been tested in
the laboratory, and the authors propose construction of a
production model to be used with a lumber dry kiln.
Although direct-firing systems are not "wood waste
boilers," they are included in this report for two reasons:
1) because the furnaces are similar to the others discussed,
the problems involving fuel, control, and air pollution
emissions problems are similar to those of furnaces used in
conjunction with steam-producing boilers, and (2) direct-
fired units may replace the current wood waste boilers,
since developmental work on direct firing is progressing
rapidly.
BOILERS
The term "boiler" is sometimes interpreted as denoting
the entire steam plant, just as "boiler house" denotes the
structure that houses the "boiler." For this discussion,
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the boiler is considered the device or system that allows
the heat energy released in combustion of the fuel to flow
into the water, or steam, by radiation, convection, and
conduction. The amount of heat energy transferred by radia-
tion is proportional to the difference between the fourth
powers of the absolute temperature of the transmitting hot
body and the receiving cold body. The radiant absorption in
a boiler is a function of the amount of surface that "sees"
the furnace. The amount of energy transferred by convection
and conduction is a function of the mass flow of gas over
the heat absorbing surfaces and the mean temperature differ-
ence between the gas and water, or steam, in the boiler.
A boiler may be rated by its Btu input, square feet of
heating surface, pounds of steam produced per hour, at a
certain temperature and pressure, or boiler horsepower. By
definition, 1 boiler horsepower is the equivalent of work
required for evaporating 34.5 pounds of water from the
liquid to the gaseous phase and 212°F in a period of 1 hour.
It is also equal to 33,472 Btu per hour. There is no rela-
tion between boiler horsepower and the mechanical horsepower
of the prime movers using the steam produced.
In further classification of boilers, two designations
are now standard: firetube and watertube boilers. In
Oregon about 30 percent of the boilers are firetube and 70
8
percent are watertube.
3-35
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Firetube Boilers
In a firetube boiler the hot gas passes through the
inside of the tubes, with water on the outside. Firetube
boilers were once the standard of the wood products industry.
The donkey boiler used for yarding in the woods was a single-
pass, firetube boiler. At the mill, the steam was probably
generated by a horizontal return tube boiler (HRT). These
are relatively low-pressure boilers that can accommodate
only a small amount of superheat. They are relatively
inexpensive, the chief reason that some are still in use
today. Because of the low pressure, under 15 psi, these
boilers can be fired unattended. Another advantange of the
firetube boiler is that the large water storage capacity
allows the boiler to meet sudden demands on steam with only
slight fluctuations in pressure.
Because of the large water capacity, however, bringing
the boiler to operating pressure is a slow process. Other
disadvantages of the fire tube boiler are that the overload
capacity is limited and the temperature of the exit flue gas
rises rapidly with increased output.
Watertube Boilers
Watertube boilers are used on systems with pressures
above 150 psi and capacities over 15,000 pounds of steam per
hour. These boilers are particularly suitable to operations
3-36
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in the current forest products industry. The early water-
tube boilers required four drums to provide enough steaming
capacity with the steel and fabricating techniques then
available. Today, large units may have two upper drums
(steam drums) and one lower drum (mud drum). For small and
medium-sized boilers a single upper drum is sufficient.
With furnacewall cooling (waterwalls) nearly all water-
tube boilers manufacturered today are bent-tube rather than
straight-tube boilers. Improvements in feedwater condition-
ing have minimized scale deposits, and the boilers no longer
require straight-tubes with handhole fittings for cleaning.
General Boiler Considerations
Critical factors in boiler design and operation include
pressures, temperatures, feedwater treatment, and water
level. Firing of boilers with wood residue and bark in-
volves some additional problems that must be considered.
1. Wood fuels tend to produce soot. These fuels
produce both unburned carbon and some unburned
hydrocarbons, which collect on the heat exchange
surfaces and inhibit heat transfer. To prevent
excessive buildup of soot, wood-fired boilers are
equipped with soot blowers to remove soot periodi-
cally. Both intermittent and continuous blowers
are in use. Intermittent soot removal is usually
scheduled daily, during early morning hours when
the heavy emissions of smoke and soot cannot be
seen. Continuous soot blowers remove the soot
before it can accumulate in large quantities. The
most commonly used soot blower is basically a
steam jet, directed so that the steam impinges on
the boiler tubes and blasts the soot from the tube
surfaces.
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2. The various types of ash that are introduced with
the wood or bark that are introduced with the wood
or bark fuel can cause slagging in the furnace or
boiler section. Slagging is particularly harmful
in the superheater section or in the boiler tubes
between the furnace and the superheater inlet. In
these sections it can cause localized overheating
and subsequent failure of the superheater element.
Cleaning with an air lance may be necessary to
prevent slag buildup within the boiler.
3. Large quantities of ash can cause erosion. A
boiler operator may habitually allow too much
excess air, causing high velocity through the
tubes and superheater. Sudden introduction of a
load of dirty bark can literally sandblast the
tubes. Several cases are reported in which
"...the superheater tubes suddenly started getting
shiny and the next thing that occurred was a
failure."
4. Corrosion may be caused by burning of logs that
were stored in saltwater. This can affect the
boiler setting, fans, control elements, and any
point at which gas temperatures are allowed to
fall below the dew point. Localized condensation
can lead to rapid deterioration of unprotected
parts, a major problem in air heaters.
INSTRUMENTATION
To achieve the highest possible efficiency and continuity
of operation in a steam generating plant, the operators must
4
maintain reliable performance records. These records
should include temperatures of steam, feedwater, air and
exit gas, and data on gas analyses, draft losses, steam flow
rates, and amount of fuel consumed. If these data are
continuously available to the operator, he can quickly
adjust the fuel and air supplies to correct any deviation
from normal. Furthermore, examination of records may indi-
3-38
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cate possible changes in operating procedure that would
improve performance or reduce pollution.
Proper instrumentation is not the most expensive por-
tion of a steam plant but it may be one of the most impor-
tant. Many old Dutch ovens are still being fired (poorly)
with only a pressure gauge and water level gauge to indicate
over-all boiler conditions. The boiler, however, is a
series of systems, each with appropriate instrumentation to
indicate the current operating point. The subsections that
follow describe the instrumentation available for monitoring
and operation of the fuel, air flow, and flue gas systems of
a wood-fired boiler.
Fuel System Instrumentation
Most wood-fired boilers are not equipped with instru-
ments to measure variables of hogged fuel such as moisture
content and size. Some available instruments, however, can
o
provide useful information for boiler operators.
Metal detectors offer the obvious advantage of limiting
damage to equipment by tramp metal in the fuel system. They
can be used to sound alarms, shut off conveyors, or perform
similar functions.
A fuel weighing system that provides data concerning
fuel flow rates is helpful in accounting for total fuel
usage and also can be used to signal the operator when the
3-39
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conveyor system is carrying no fuel. The value of weight
data is limited in that the weight of fuel varies directly
with moisture content, which can vary over a wide range.
The most common fuel weighing system in use today consists
of a load cell under the fuel conveyor. The output signal
from the load cell is electronically converted to display
pounds of fuel per hour.
Television scanners can monitor most fuel handling
systems, including conveyors, hogs, storage bins or piles,
feed systems, and screens. Each component of the system can
become plugged or fail to function, with the result that the
fuel supply to the boiler stops. When closed-circuit tele-
vision scanners are located at critical points in the system,
the operator can quickly spot any disruption and take cor-
rective action to minimize changes in fuel flow to the
boiler. A scanner system can be installed with several
cameras and only one video screen. Using a selector switch,
the operator can check the system at any of the several
points being monitored.
Fuel feed monitors are helpful in the common situation
where fuel is fed to a hogged fuel boiler at more than one
point. The operator can readily determine whether fuel is
flowing freely through each feeder. Feed monitors are
available in a variety of designs, including glass panels in
3-40
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the system and mechanical linkages that move as long as fuel
is being fed. The rate of feed is seldom measured.
Fuel moisture meters can facilitate occasional spot
checks of moisture content. Few plants do this regularly,
however, and the data are not used to control the combustion
process. Efforts are under way to develop reliable systems
for continuously measuring fuel moisture. This type of
information is useful in determining when to use auxiliary
fuel, but it is not requisite for boiler operation. In
plants where fuel drying and sizing are part of the opera-
tion, moisture measurement can be a valuable control monitor
for the fuel preparation system.
Air System Instrumentation
The discussion of air monitoring equipment is limited
to the combustion air input system and the induced-draft
system. The exhaust gas system is discussed separately.
Even though temperatures and flow rates of combustion
air are critical in the combustion process, few boilers are
instrumented to measure and indicate gas temperatures or air
o
flow rates, for several reasons:
1. Knowledge of air temperatures is seldom needed.
If the boiler is equipped with an air preheater,
it is used to maximum capacity. If it has no air
heater, knowing the air temperature does not
assist the operator in his duties. An air tempera-
ture that is not within the normal range can
indicate a possible trouble source that may need
correction.
3-41
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2. Total airflows directly affect the percentage of
excess air. But because the excess air level can
be determined accurately from analyses of the
exhaust gases, measurements of input airflows are
redundant.
3. The cost of installing equipment for continuous
monitoring of airflow has been prohibitive.
Continuous measurements of gas flows to underfire
and overfire air systems could signal the operator
to correct the flows for optimum combustion. The
economic returns from installation of such equip-
ment, however, are difficult to identify.
Air pressure instruments are common. Draft gauges on
control panels indicate positive and negative pressures at
various points in the combustion and heat exchange systems.
The operator uses data from these instruments to determine
when plugging occurs because of ash buildup. The data are
also useful in setting airflows to maintain proper pressures
in the furnace.
Fliie Gas System
Flue gases can be monitored continuously to determine
such parameters as temperature, percent carbon dioxide or
oxygen, and opacity or optical density.
Temperature - Temperature is dependent upon so many vari-
ables that fluctuations are difficult to relate to a speci-
fic cause. Changes in air heater performance, steam genera-
tion rate, fuel moisture content, fuel heating value, and
percent excess air all affect exhaust gas temperatures. A
marked change in temperature, however, can signal the opera-
tor to investigate.
3-42
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Percent Carbon Dioxide or Oxygen - Of all continuous moni-
tors available to the boiler operator, those that analyze
flue gas for carbon dioxide or oxygen content are the most
valuable indicators of combustion conditions. As noted
earlier, the balance between fuel and air supply is critical
to proper combustion. Continuous measurement of combustion
products can inform the operator of any upsets in this
balance. He can then adjust conditions to maximize boiler
efficiency and minimize air pollutant emissions. Without
data from flue gas analyses, the operator can only guess at
the percentage of excess air being used in the system.
Continuous gas analyzers are costly ($2000 to $5000 per
installation), and they also require maintenance and calibra-
tion for proper functioning. The expense can be justified,
however, by fuel savings and reduction of air pollutant
emissions.
One difficulty should be noted. Most continuous flue
gas monitors are fairly delicate instruments. The output
signal is based upon a small voltage generated by the instru-
ment in response to the concentration of the gas being
analyzed. If the instrument is not grounded properly, a
false reading may be caused by an electrochemical reaction
within the instrument. This is a common problem, but also
one that is easy to correct.
3-43
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The best alternative to continuous analysis of flue gas
is analysis of grab samples. Two common grab-sample analyzers
are the Orsat and the Fyrite gas analyzers. Each provides
measurements that are accurate to within about 0.2 percent.
The cost is moderate, and the instruments are well suited
for field use. Orsat analyzers require more skill to oper-
ate than do the Fyrite units, and may offer a slight advan-
tage in accuracy. Both units require regular replacement of
chemicals. Sample time from start to finish may be 10 to 15
minutes. Therefore, if combustion conditions vary substan-
tially over short intervals, this type of analysis may not
be suitable.
The importance of flue gas analyses cannot be over-
stressed. Every boiler operator should have these data at
his disposal at all times. Without them, he cannot properly
control the combustion process.
Opacity - Most regulatory agencies have implemented stan-
dards regarding opacity limitations. The standards specify
that emissions may not exceed an opacity limit (usually 20
or 40 percent) for more than 3 minutes in any hour. Com-
mercial opacity monitors are available and are in common
use. Their use, however, is limited to providing informa-
tion to the operators, since most agencies do not accept
charts from opacity monitors as proof that emissions are in
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compliance. An opacity monitor is a warning device to
signal an operator of a combustion upset that may cause
heavy particulate emissions. It does not respond to gaseous
pollutants.
Opacity monitors are installed in the exit-gas duct
system, usually downstream from devices for emission control
(for example, multiple cyclones). This location may be in
the breeching or in an exhaust stack. The systems commonly
incorporate a light source, a photoelectric cell, an ampli-
fier, and a recorder (Figure 22). Light from the source
travels through the exhaust gas stream. Particles in the
gas stream absorb or scatter the light and reduce the signal
at the photoelectric cell.
CONTROLS
Control of the boiler may be manual, with the operator
making all adjustments to all systems, or automatic, with
the operator adjusting only the control set points as re-
quired. A further refinement is a computerized boiler
control system, in which all adjustments are made according
to a programmed scenario.
Manual Control
Manual control is the usual system on older Dutch ovens
with smaller boilers. The operator controls boiler pressure
by adjusting the fuel flow. Height of the fuel pile is
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PHOTO ELECTRIC
CELL
PATH LENGTH
OF LIGHT BEAM
RECORDER
Figure 22. A common arrangement of instruments
to monitor opacity of exit flue gases.
3-46
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judged by visual observation, and fuel flow is controlled by
a splitter or gate in the gravity feed portion of the fuel
system.
Air flow is controlled by adjusting the stack draft
damper and opening or closing the furnace draft doors or
louvers.
Water level is adjusted by means of a valve in the
bypass line of the boiler feed pump. An alarm signalling a
low water level and a safety valve that lifts at an exces-
sive pressure are the only controls not manually operated.
The operator is responsible for maintaining steam
pressure and flow by applying his knowledge and skill. Many
times this same operator is responsible for shoving fuel
into the conveyor and making sure that fuel placed in the
conveyor reaches the furnace.
Automatic Control
A relatively larger boiler is usually also more compli-
cated. The operator of this complex system is required to
maintain steam flow and pressure, ensure efficient opera-
tion, and comply with air pollution control regulations. It
is usually necessary, therefore, to provide controls that
will permit adjustment of remote systems from a central
position at or near the boiler instrument panel.
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The devices that permit remote operation are power-
operated by compressed air, by oil or water under pressure,
or by electric motors or solenoids. They enable the opera-
tor to quickly adjust the position of valves, dampers, and
similar devices to compensate for fluctuations in boiler
conditions. Frequent and repetitive manual operations,
often tiring to the operator, can be performed more effi-
ciently by automatic controllers. More uniform furnace
operation will result, and boiler performance can be main-
tained close to optimum levels. The additional cost of an
automatic control system over a simple instrumentation
system is not excessive and usually is soon repaid in fuel
savings.
As an example, consider the control of fuel flow to the
boiler to maintain the steam output for maximum efficiency.
If the fuel flow is controlled manually, the following
events are possible:
If the steam pressure gauge indicates the specified
pressure and is steady, the fuel adjustment is adequate.
If the steam pressure gauge indicates a dropping steam
pressure, the fuel flow must be increased, the amount
to be determined by the operator's experience.
If the steam pressure gauge indicates a rising steam
pressure, the fuel flow must be decreased, again in
accordance with the operator's judgement.
If the steam pressure drops excessively, the operator
will be notified by another person that the steam
supply is inadequate.
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If the steam pressure increases excessively, the safety
valve will lift and steam will be exhausted to the
atmosphere.
It is difficult for even an experienced operator to
analyze which of the possible events is occurring by glanc-
ing occasionally at the pressure gauge. A steam pressure
sensor continually monitors the pressure and sends a signal
to an automatic controller. The controller can be programmed
to accept the pressure sensor signal, compare it to the
steam pressure set point, determine whether it deviates from
the set point, and indicate the proportional action to be
applied to the fuel feed system to return the steam pressure
to the set point.
Similar automatic control systems can be used to adjust
draft systems, water levels, and furnace temperatures. In
all cases the automatic control system can provide more
continuous surveillance than can the boiler operator. The
result is steadier firing of the boiler at a higher overall
efficiency with a greater degree of air pollution control.
Computerized Control Systems
Boiler control by computer offers the ultimate in
automation. The computer can be programmed to anticipate
load changes through time controlled inputs, to indicate
that designated limits are going to be exceeded before this"
occurs, to print out all important data should a failure or
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upset occur, to print out routine control settings at pre-
determined time intervals, and to adjust the control systems
to accommodate daily, weekly, or monthly variations such as
changes in weather or seasonal loads.
New boilers being installed in plants having computer
equipment may be able to utilize that equipment through time
sharing. If the company already employs a computer program-
mer, he should be consulted about potential computerized
control of a new boiler.
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4.0 OPERATING VARIABLES
Having described the distinctive properties of wood as
fuel and the processes by which combustion occurs in the
several types of wood-burning furnaces, we consider now the
principal aspects of furnace operation. The operating
variables are classified as fuel-related, air-related, and
operator-related factors, as listed in Table 13; all of
these factors contribute to the over-all efficiency of the
system. The fundamentals outlined in this section can be
regarded as a 'primer' of wood-burning boiler operation,
FUEL VARIABLES
Control of Fuel Size
Four methods are used to control fuel size: screening
fuel to separate the oversize pieces; hogging the large
pieces; mixing the fuel in storage and transport facilities;
and maintaining separate facilities for storage, transport,
and feeding of sanderdust.
Method of Feeding Fuel
The method of feeding fuel to a boiler furnace is
dependent on the furnace design. In firing of a Dutch oven,
the fuel is dropped through a chute on top of a pile.
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Table 13. FACTORS AFFECTING THE COMBUSTION REACTION IN
BOILER INSTALLATIONS FIRED BY HOGGED FUEL8
FUEL-RELATED FACTORS
Species
Size
Moisture content
Ultimate analyses
Proximate analyses
Heating value
Method of feeding fuel
Distribution of fuel in furnace
Variations in fuel feed rates
Depth of fuel pile in furnace
Separate firing practices
Auxiliary fuel usage
AIR-RELATED FACTORS
Percent excess air
Air temperature
Ratio of overfire air to underfire air
Turbulence of air
Flow relation between forced-draft and induced-draft
systems
OTHER FACTORS
Cleanliness of the combustion system
Basic furnace design
Maintenance of components
Steam generation rate
Steam drum water level
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Several piles may be used for one boiler. In a spreader-
stoker furnace, a mechanical or pneumatic spreader distri-
butes the fuel across a grate. The desired result is to lay
a thin, uniform mat of hogged fuel across the entire grate
area.
These two systems differ substantially. In the Dutch
oven, the fuel reaches the top of the pile in a stream and
cascades down the sides. Little combustion of the fuel
occurs until it has settled on the sides of the pile, where
it receives radiant heat from the refractory lining of the
oven. This heat input, coupled with convectional heat
transfer from the hot gases around the pile, provides energy
to evaporate the water in the fuel and raise the tempera-
ture. Gases evolved from the pile are rich in carbon mono-
xide. As these pass between the drop-nose arch and the
bridge wall, the overfire air supplies sufficient oxygen to
complete the combustion of carbon monoxide to carbon dioxide.
In a spreader stoker, the fuel spread across the grate
must fall through the flames of the burning material on the
grates. Small, dry particles of fuel, such as sanderdust
and planer shavings, will heat quickly and burn in suspen-
sion before they arrive at the grate. Larger, moist fuel
particles such as bark and coarse white wood, will fall to
the grate and burn there until they become small enough and
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light enough that the air from under the grates carries them
into suspension. Combustion is completed in suspension
(provided that time, temperature, and turbulence are ade-
quate) . The spreader-stoker design does not require large
amounts of refractory to radiate heat back to the burning
fuel pile. Heat is radiated from the flame zone above the
grates back to the fuel on the grates, aiding the initial
combustion. Heat also is transmitted to the fuel through
turbulent flow of hot combustion gases within the furnace
and heated underfire air. Combustion must be completed in
the furnace chamber.
Because the method of fuel feed is tied closely to the
furnace design, the feeding methods are not easily inter-
changeable. The furnace design and the associated methods
of fuel feed do influence the combustion process.
Distribution of Fuel in the Furnace
Furnaces are designed for uniform combustion of fuel
across the furnace area. Fuel on one side of the furnace
should be subject to the same conditions of available air,
temperature, turbulence, and gas velocity as fuel on the
other side. If the feeding system allows for uneven distri-
bution of the fuel, the entire combustion system is unbal-
anced. Thus the need for uniformity applies to fore and aft
distribution as well as side to side distribution. The
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primary concern for all types of furnaces is that fuel be
placed evenly in the combustion zone.
Control of Fuel Distribution
The methods of controlling fuel distribution depend, of
course, on the basic furnace design. In Dutch ovens with
center feed chutes, little can be done to alter the place-
ment of fuel over the grates. Ideally, the pile should be
set squarely in the center of the refractory and symmetri-
cally about the underfire air feed system. If the fuel
chute is off center and piles fuel in a corner or to one
side of the oven, combustion will not proceed uniformly in
the pile. Improvement of distribution of fuel in a Dutch
oven is usually expensive and must be done when the furnace
is cold.
In most spreader-stoker systems, the fuel distribution
may be adjusted manually. The speed of mechanical spreaders
can be reduced or increased. Baffle plates often are pro-
vided to control the angle at which fuel is injected into
the furnace. Other mechanisms are sometimes available to
adjust the width of the fuel path. These same options are
often available on pneumatic spreader systems. The most
important control, however, is the operator. By inspecting
the fuel pile through inspection and cleanout ports, he can
determine the uniformity of fuel distribution in the furnace
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and can make any required adjustments. Such inspections
should be made regularly, since no automatic systems are
available to replace operator skills.
Variations in Fuel Feed Rates
In almost all boilers, changes in steam demand occur
during normal operation, sometimes ranging from 40 to 125
percent of the boiler rating over a few minutes, although
most load changes are not so drastic. In response to load
changes, the fuel feed rate is increased or decreased.
Decreasing the feed rate usually has no adverse effect on
the combustion reaction. The fire burns to a lower level,
and steam production drops off.
An increase in steam demand, however, may cause sub-
stantial problems. Consider a furnace that is operating at
75 percent of full load. Suddenly, the load demand in-
creases to 100 percent. As the steam demand increases, the
fuel feed rate increases. The furnace receives hogged fuel
with moisture content of 45 to 50 percent. This increase in
the rate of wet fuel going to the furnace may reduce the
temperature in the combustion zone. As the temperature
falls, so does the combustion rate. To compensate for this,
more air is added, usually as underfire air, to help dry the
fuel and increase the rate of combustion, which increases
the percentage of excess air. This procedure tends to
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reduce combustion efficiency and frequently causes emission
of substantial amounts of unburned material. Gradually, as
the wet fuel dries, the temperature and the rate of com-
bustion increase, and the steam output also increases.
The degree to which the combustion process is upset
depends on the initial rate of combustion, the change in
fuel feed, the design and size of the furnace, the moisture
content and size of the fuel, the temperature of underfire
and overfire air, the amount of excess air, and other re-
lated combustion variables. If the feed rate of hogged fuel
is increased drastically over a short time, substantial
upsets can be expected. If the feed rate is increased
gradually, less disturbance will occur. The most dramatic
upsets can occur in furnaces that are batch fed from a
hopper. Maintaining stable combustion is virtually impossi-
ble when a ton or more of wet, cold, hogged fuel is dropped
into a furnace.
Controlling Variations in Fuel Feed Rates
The ideal condition for combustion control is a con-
stant rate of fuel feed to maintain a constant rate of steam
generation. The worst condition is batch feeding of fuel to
accommodate a highly fluctuating demand for steam.
Fortunately, few furnaces are now batch fed. The fuel
flow usually is controlled by a hopper-fed screw conveyor or
similar device. Direct-current drives are common, with the
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control signal coming indirectly through a transducer for
steam header pressure. Great ingenuity has been shown in
boiler plants to provide uniform fuel feed to the furnaces.
Process operations in the plant control the steam
demand and therefore the fuel flow rate. Improving the
control of process operations often can eliminate wide
fluctuations in steam demand. Such improvements require an
understanding of the problems and the cooperation of plant
supervisors and production personnel.
Depth of Fuel Pile in the Furnace
Depth of the fuel pile affects the combustion process
in two ways. First, it determines the amount of underfire
airflow. As most hogged fuel boilers are not equipped to
vary air pressure, the airflow rate decreases when the pile
height increases. A reduction of underfire airflow may
raise the overfire airflow if the air duct system is not
equipped with individual damper controls.
The reverse also occurs. When depth of the fuel pile
decreases, the underfire air encounters less resistance to
flow as it passes through the pile. The underfire air flow
therefore increases, and overfire airflow may decrease.
This reaction occurs with Dutch oven and spreader-stoker
designs, although the responses to pile depth are not equal.
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The second effect of fuel pile depth is to change the
transfer of radiated heat to the fuel, applicable to Dutch
ovens only. In a Dutch oven, the closer the fuel is to the
hot refractory lining, the faster the volatile portion of
the fuel receives radiated heat and evaporates to the gase-
ous phase. Thus, increasing the pile depth can increase the
rate of combustion in a Dutch oven. There is an upper
limit, however. As the surface of the fuel pile approaches
the top of the Dutch oven, the volume of gas in the oven is
reduced. As a result, residence time is reduced and gas
velocities increase. The resulting incomplete combustion of
fuel will reduce both the temperature and the rate of com-
bustion in the furnace.
Fuel Pile Depth Controls
Over the past 60 to 70 years, the depth of fuel piles
has been controlled principally by the boiler operator.
Only recently have there been efforts to control the depth
of piles by automatic means. This technology has been
applied to Dutch ovens with moderate success.
In the automatic controls a temperature sensing probe
is inserted from the top into the pile. As the pile burns
down, more of the probe is heated. As fuel is added, it
covers the probe and thereby insulates it from the flame
temperatures. The probe temperature thus provides a direct
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measure of the pile depth. The temperature can be used as a
signal to the feed system to control the depth of the pile
automatically.
Among the several commercial models now available, some
sense the temperature with a thermocouple and others measure
the temperature of water flowing continuously through the
probe. Each system works well, with little or no mainten-
ance difficulty. Either is preferable to manual control by
the boiler operator, which requires continued surveillance,
particularly during load swings, and constant adjustment to
maintain optimum operation.
Separate Firing Practices
In operation of hogged fuel boilers, the various fuel
components (bark, planer shavings, sanderdust) can be fed to
the furnace as a mixture or they can be fed separately. The
two fuel components that usually are fed through separate
systems are sanderdust and cinders.
Sanderdust particles are small and relatively dry.
These characteristics allow extremely rapid combustion if
the fuel is properly suspended and other conditions are
favorable. In rapid combustion the available oxygen is
consumed at a high rate. If the oxygen supply is limited,
the sanderdust and any other fuel may be "starved" for
oxygen, in which case unburned particles will leave the
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furnace as dense, black smoke. For this reason sanderdust
is often injected separately with its own controlled air
supply.
Separate firing of sanderdust offers several advantages.
In a well-designed system it will limit dust emissions in
handling and storage, provide a proper balance of air and
fuel, provide air at the correct place, and generally improve
combustion. Further, sanderdust firing systems can respond
rapidly to changes in boiler load. They can be used to
release heat energy quickly to compensate for rapid swings
in load, whereas if sanderdust is mixed with other hogged
fuel, the response to load swings is less rapid. Further-
more, sanderdust often is not well mixed with hogged fuel.
As a result the rates of combustion are spasmodically high
when the sanderdust predominates in a mixture, and rates of
excess air are high when the proportion of sanderdust is
reduced.
Sanderdust Firing
Most difficulties with sanderdust firing occur because
of failure to recognize the unique properties of this fuel
and to provide for them in system design and operation. The
salient properties are the small size of the particles and
their low moisture content. Taking these into considera-
tion, one can develop design criteria that allow advantage-
ous use of sanderdust. A well-designed system would control
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dust and plugging, provide variable control of feed rate,
ensure good particle suspension, locate the particles in the
flame, and maintain a pilot light. These features are
examined individually.
1. Dust control. Systems for transporting, storing,
and feeding must be designed to minimize dust
emissions. This is important for control of air
pollution as well as for control of fire or ex-
plosions.
2. Control of plugging. Plugging generally does not
present special problems with sanderdust unless
the material is wetted to limit dust emissions.
Dry sanderdust flows easily and responds well to
the use of vibrators. Bridging can be a problem,
but it is easily avoided through proper design of
the system.
3. Control of variable feed rate. In burning of
sanderdust special attention is needed to ensure
constant feed to maintain steady combustion.
Control of combustion air is equally important.
Because sanderdust burns rapidly, enough air must
be supplied at the right place and large quanti-
ties of excess air must be avoided. A well-
designed system incorporates variable airflows
that correspond to the full range of sanderdust
feed rates.
4. Good particle suspension. The firing system
should separate individual particles of sanderdust
as they are injected into the furnace. This is
necessary to mix the particles with combustion
air. Separation usually is accomplished with
swirling vanes or a cyclonic type of feeding
system.
5. Location in the flame zone. Sanderdust particles
injected directly into the flame are exposed to
high temperature long enough to burn completely.
If they enter the furnace at a point where they
are not exposed to flame temperatures long enough,
combustion will not be completed.
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6. Pilot light requirements. Many boiler installa-
tions incorporate a pilot light system for sander-
dust burning. The pilot is located at the point
of sanderdust injection. The pilot light probably
does not add significantly to the combustion
process, but it is a desirable safety feature.
The prime function is to prevent explosion in the
furnace under fluctuating conditions of operation.
COMBUSTION AIR VARIABLES
Percentage of Excess Air
For complete combustion of hogged fuel each molecule of
fuel in the gaseous state must come into contact with one or
more molecules of oxygen. Supplying excess air increases
the probability of this occuring. There is a limit, how-
ever, to the amount of excess air that can be added and
still help the combustion reaction. Several factors are
influential.
Air that is brought into the combustion chamber is well
below flame temperatures. During combustion, it must be
heated to combustion temperatures, an increase of up to
1800°F. This process requires heat energy that comes from
the combustion. As the amount of incoming air is increased,
more energy is taken from the combustion process to heat it.
This lowers the temperature in the combustion zone, which
slows the rate of the reaction. If the fuel fails to burn
completely because of slow reaction rate, air pollutants
will be generated.
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As the energy requirement to heat incoming air in-
creases with the amount of air introduced, thermal effi-
ciency of the combustion system goes down and more fuel is
required to produce a given amount of steam.
As airflow into a furnace increases, the velocity of
gases passing through the furnace increases. Furnaces are
designed for a range of gas velocities based on an assumed
upper limit of excess air, usually 50 percent. If more than
50 percent excess air is introduced, gas velocities in the
furnaces may be so high (particularly at high rates of steam
generation) that they carry fuel out of the combustion zone.
If this occurs and the unburned fuel enters the heat ex-
change tubes of the boiler, gas temperatures will drop
quickly below those required for the combustion reaction to
go to completion. The boiler then emits the products of
incomplete combustion as air pollutants.
An interrelated effect of high gas velocities caused by
excess air is reduction of the residence time of fuel in the
combustion zone. Again, the process may be stopped before
combustion is completed, and unburned materials will leave
the stack as air pollutants.
The rate of gas flow into and out of a furnace in-
creases in linear proportion to the increase in excess air;
that is, at 100 percent excess air, roughly twice as much
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gas passes through the furnace as at 0 percent excess air.
Pressure drop through the system, however, increases ex-
ponentially with the gas flow. Movement of this gas re-
quires the operation of forced-draft and induced-draft fans,
which in turn requires power. The cost of energy to run
these fans is significant. For example, operating a hogged
fuel boiler with capacity of 100,000 pounds of steam per
hour at 100 percent excess air would require 50 horsepower
more than operating the same boiler at 50 percent excess
air. Over a year's time at 10 mils per kWh this additional
power will cost $3125.
The size of forced-draft and induced-draft systems,
including motors, fans, ducts, and dampers, is based on the
steam generation rate of the boiler and some reasonable,
maximum value of excess air, such as 50 percent. At more
than 50 percent (or the design value) excess air, one or
more of the system components will be improperly sized for
efficient operation. Control of the systems can be lost
when components must operate outside their design ranges;
improper balance between forced-draft and induced-draft
systems can cause pressurizing of the furnace or excessive
furnace draft and inability of the air systems to respond to
changes in the fuel feed or in load demand.
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The size of particulate collection systems also is
based on the maximum steam generation rate and some reason-
able value of excess air. As with the fan systems, pollu-
tion control equipment does not function at its best if gas
flow rates deviate from the design values. Too much excess
air reduces the collection efficiency of most pollution
control systems.
In summary, although some excess air is required for
proper combustion, too much excess air can be detrimental
for the following reasons.
1. It cools the combustion reaction and slows the
rate of reaction.
2. It reduces thermal efficiency.
3. It increases gas velocities across the grates and
lifts the fuel from the grates before it burns
completely.
4. It reduces residence time in the furnace so that
fuels cannot burn completely.
5. It requires costly additional power in the fan
system.
6. It can unbalance the air system, causing loss of
combustion control, improper pressure conditions
in the boiler furnace, and inability of the system
to respond to load variation.
7. It reduces the efficiency of pollutant collection
equipment if the gas flow exceeds design conditions,
Most designers and manufacturers of hogged fuel boilers
identify an optimum range of excess air from 25 to 90 per-
cent. In practice, however, most hogged fuel boilers are
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operated at 100 to 150 percent excess air; most of these
units would operate more efficiently at lower levels of
excess air.
The optimum level of excess air varies among individual
boilers. Generally, a unit functions reasonably well at
levels from 40 to 75 percent. These values correspond to
carbon dioxide levels in the exhaust gases of 14.3 to 11.0
percent. Because of the variations in furnace design, fuel
moisture content, steam generation rate, and other factors
that affect the combustion process, optimum conditions for
excess air cannot always be maintained. Operators should
nonetheless be aware of the negative effects of too much
excess air.
Control of Excess Air
The first step in controlling excess air is to monitor
the products of combustion (carbon dioxide or oxygen).
Without instruments to monitor the flue gas constituents,
excess air can be controlled only by guesswork. Note that
it is necessary to measure either carbon dioxide or oxygen.
Measuring both is not necessary.
The signal from a flue gas analyzer can be fed directly
to controls for the forced-draft and induced-draft dampers
(Figure 23). As an alternative, the signal may be read by
the operator, who then adjusts the airflow controls manually,
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I
M
CX>
CONTROL SIGNAL
TO FUEL FEED
"I
BOILER CONTROL PANEL
I. D. FAN
DAMPER POSITIONER
F. D. FAN
DAMPER POSITIONER
Figure 23. A flue-gas analyzer used to control dampers for induced-draft
(I.D.) and forced-draft (F.D.) fan systems8
-------
the type of adjustment depending on the boiler design and
the available equipment. Obviously, control of the process
requires fans, dampers, and positioners, and sufficient
instrumentation to provide status data to the operator.
Regulating the percentage of excess air is simple. As
the level of carbon dioxide drops, the rates of overfire and
underfire airflow are reduced. (Again, this reduction
depends on the design of the furnace and the firing equip-
ment available.) For many hogged fuel furnaces, the desired
set point for carbon dioxide is about 13.5 percent (or 50
percent excess air). When levels of carbon dioxide go above
the set point, the airflow rates should be increased.
Although the concept is simple, continuous control of
excess air is complicated by variations in steam generation
rate, fuel moisture content, fuel size, fuel heating value,
amount of ash buildup on grates and in heat exchangers, and
other variables that affect combustion. Even so, a skilled
operator, using information provided by continuous flue-gas
analysis, can usually correct the system and maintain
reasonable combustion.
Air Temperature
Preheating the air entering the combustion zone offers
the following advantages: It increases ability of the air
to remove moisture from wet fuel; it increases the furnace
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temperature, which increases the rate of combustion and
reduces formation of air pollutants; it increases overall
efficiency of the system by utilizing heat energy that
otherwise would be lost up the exhaust stack; and it in-
creases the steam generation capacity.
Air Temperature Control
In most plants, the boiler operator cannot regulate air
temperature directly. If the system includes a preheater,
it normally is used to full capacity. If there is no pre-
heater, the furnace must function on colder air.
Although the boiler operator usually cannot control the
temperature of the forced-draft air system, he can control
other air inputs to the furnace. With few exceptions,
hogged fuel boiler furnaces are operated at a slightly
negative pressure. Therefore, cold ambient air can be
pulled in through such openings as inspection ports, clean-
out doors, cracks in the casing or refractory, and fuel
chutes. It can also enter through inadequate seals around
sources of cold air, such as doors, drums, pipes, and soot-
blowers .
By closing sources of cold air to the furnace, the
operator gains additional control of the combustion process.
Not only does he increase combustion-zone temperatures, but
he prevents local "cold spots" and gains greater' control of
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excess air. Note that infiltration (leakage) air has all of
the detrimental characteristics of cold excess air, but
provides none of the benefits.
Ratio of Overfire to Underfire Air
In most hogged fuel boilers, the incoming air for
combustion is split into two ducts, one bringing the air in
under the fuel pile or grates and the other bringing air in
over the fuel pile. In many spreader-stokers, part of the
overfire air is used to pneumatically spread the fuel across
the grates. The ratio of the two flows is a parameter of
concern, the optimum ratio depending mostly on boiler design
and fuel characteristics.
In theory, boilers should function best with 75 percent
overfire air and 25 percent underfire air, these values
based on proximate analyses of hogged fuel. Roughly 75
percent of the fuel is volatile organic material that pyro-
lizes to the gaseous state as it goes through the steps of
combustion. The combustible gases rise above the solid
hogged fuel, mix with air, and burn. Thus, in theory, 75
percent of the air should be supplied above the pile. The
remaining 25 percent of the fuel, the fixed carbon, remains
on the fuel pile or grate system, where combustion air (25
percent of the total) is supplied from underfire air.
This theoretical scheme, however, does not account for
the many variables that affect the combustion process. The
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main influences are furnace design (Dutch oven or spreader
stoker) and fuel moisture content (moist fuel requires more
underfire air). As a result of these influences, many
systems operate best with 75 percent underfire air and 25
percent overfire air rather than the theoretical 25/75
ratio.
Controlling the Ratio of Overfire to Underfire Air
The operator controls air distribution by means of
fans, air ducts, and dampers, all installed and operated in
accordance with furnace design. He is concerned with
several operational problems regarding distribution of air
in the forced draft system. With wet fuel, he must provide
adequate underfire air to help drive off moisture from the
wood. With pneumatic-spreader systems, he must provide
enough overfire air to distribute the fuel. As ash or fuel
builds up on the grates, the flow of underfire airflow is
reduced as pressure across the grates and ash diminishes.
Reduction of underfire airflow also may entail a propor-
tionate increase in overfire airflow, depending on the fan
system. Overfire air should create maximum turbulence
without disturbing ash or fuel on the grates. Furthermore,
the overfire air must be distributed so as to avoid impinge-
ment directly on hot refractory or metal surfaces, and thus
to limit damage caused by condensation, thermal stresses,
and thermal shock.
4-22
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Few hogged fuel boilers are equipped with a forced-
draft air system that can continuously balance the flows of
overfire and underfire air. At most plants the primary
control is to keep the grates clear of heavy ash buildup
that could adversely increase the pressure drop across the
grates. Sealing any leaks in the furnace and air systems
also aids in maintaining proper balance of airflows. Deli-
berate design of high pressure drop (2 to 3 inches of water)
across spreader-stoker grates can aid in insuring good
distribution of underfire air even when fuel distribution on
the grate is not ideal.
Turbulence of Air
For complete combustion, one or more molecules of
oxygen must come into direct physical contact with each
molecule of gaseous fuel at adequate temperature and resi-
dence time. Turbulent gas flow facilitates mixing of the
gaseous fuel and oxygen in the furnace. The primary purpose
of overfire air jets or nozzles is to provide turbulent
flow, which not only enhances the combustion reaction but
also prevents formation of dead spaces or quiescent zones in
which fuel vapors accumulate. Such accumulations can cause
puffing of small explosions in the combustion zone.
Control of Air Turbulence
Turbulent patterns of gas flow are brought about by the
position, direction, velocity, and mass flow rates of gases
4-23
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entering the furnace. Turbulence is high when the gases are
sent into the furnace in swirling patterns from high-velo-
city nozzles, whose position and direction strongly influ-
ence the flow pattern. Since these inlet nozzles usually
are fixed, the operator has little or no control of the
degree of turbulence in the furnace. He can effect minor
changes of turbulent flow patterns by varying the ratio of
overfire to underfire air. With most hogged fuel boilers,
however, control of turbulence in the combustion reaction is
handled primarily in the design and engineering stages.
Turbulence in installed boilers frequently can be improved
by addition of properly located, high-velocity air nozzles.
Forced-Draft and Induced-Draft Systems
The forced-draft air system brings combustion air to
the furnace. The complete system includes facilities to
deliver preheated air under automatically controlled flow
conditions throughout the full range of boiler operations.
The induced-draft air system draws combustion products out
of the boiler under controlled flow rates and removes en-
trained air pollutants. Control equipment such as multiple
cyclones and scrubbers generally is considered part of the
induced-draft system because of the location in the system
and the effects on pressure drops and flow rates.
4-24
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Operation of forced-draft and induced-draft systems
directly affects most of the related combustion parameters,
such as percentages of excess air, turbulence, and air
temperature. Furthermore, the balance between flows in
these two systems determines the pressure in the furnace.
In most hogged fuel boilers, particularly older installa-
tions, a slight negative pressure is maintained in the
furnace and heat exchange sections to minimize puffing and
to retain fuel and combustion products in the furnace.
Not all hogged fuel boilers operating today are equipped
with balanced, automated, forced-draft and induced-draft
systems. Many have no forced-draft system at all. Others
rely on the natural draft from smoke stacks rather than a
controlled induced-draft fan system. Because such installa-
tions cannot control the combustion process throughout the
full range of operation, incomplete combustion may occur at
regular intervals with resultant emissions of smoke, cin-
ders, underburned hydrocarbons, and other air pollutants.
Control of Forced-Draft and Induced-Draft Systems
Forced- and induced-draft fan systems should be oper-
ated so as to provide a proper amount of excess air for good
combustion. As described earlier, most boilers fired with
hogged fuel operate within a range of 40 to 75 percent
excess air. Maintaining a slightly negative pressure to
4-25
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retain the products of combustion is particularly desirable
in old furnaces that have many leakage points. Under such
circumstances, excessive negative furnace drafts can add
undesirable infiltration air. Most new furnaces with com-
pletely sealed exterior casings do not require a negative
furnace draft. These fan systems should assist in providing
turbulence in the combustion zone and should also provide
enough air to distribute fuel in spreader-stokers with
pneumatic spreaders. The fan systems should perform these
functions throughout the full range of steam generating
rates, responding rapidly to load variations.
To meet these criteria the fan system must be equipped
with calibrated, automatic controls. An operator cannot
manually adjust the airflow dampers with the speed or ac-
curacy that is required to maintain air balances throughout
the full range of operating loads. Proper maintenance of
the controls includes regularly scheduled cleaning, lubri-
cating, and calibration by a competent instrument techni-
cian. The boiler operator should be thoroughly familiar
with the capabilities of the control systems at his disposal
and make full use of them.
Cinder Reinjaction Systems
Some plants incorporate a cinder reinjection system on
boilers equipped with dry primary collectors. The cinder
4-26
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reinjection system is located after the heat exchangers and
ahead of the stack to collect the solid material removed
from the flue gas by the primary collector and return it to
the furnace. This material is usually conveyed pneumatic-
ally and reinjected, along with the conveying air, above the
grates.
Cinders collected in control devices, such as cyclones
or multiple cyclones, are difficult to transport, store, and
burn. They consist of fixed carbon, small particles of
inorganic fly ash, and larger particles of inorganic, in-
combustible materials such as sand and clay. The percentage
of this material that is capable of burning, that is, the
fixed carbon, is dependent upon combustion conditions in the
furnace. If conditions are good, perhaps only from 10 to 15
percent of the cinders consists of combustible materials.
If combustion conditions are poor, then as much as 90 per-
cent of the cinders may be fixed carbon.
The rate of combustion of fixed carbon is substantially
lower than the rate of combustion of the volatile materials
in wood fuels. As wood undergoes combustion, the volatile
materials evaporate to the gaseous phase and burn. In the
gaseous phase, they burn more rapidly than does carbon in
the solid phase. This difference is important in operation
of hogged fuel, furnaces because reinjected cinders require
4-27
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longer residence time to complete combustion. If residence
time at high temperature is not sufficient, the unburned
cinders will again leave the furnace as potential air
pollutants.
The carbon portion of cinders is not mechanically
strong. It crushes easily to a fine powder of low density.
This usually occurs in rotary screen systems, ahead of the
cinder reinjectors, that remove sand and heavier particles.
The resultant form of the carbon is dustlike and difficult
to handle. It also presents problems when reinjected into
the furnace. The small, light particles of carbon can
become suspended in the turbulent airflow of the furnace and
be carried out of the combustion zone quickly - often before
the combustion reaction has had time to go to completion.
Consider two extreme situations involving cinder in-
jection. First, consider a furnace in which combustion is
good and only 15 percent of the cinders consists of carbon
(Figure 24). Separation of this material in a screening
system probably will be only partially effective because the
carbon particles are small, much the same size and density
as the inorganic fly ash particles. Thus, the screened
material that is to be reinjected probably is only 50 per-
cent combustible at most, and only 50 percent of that com-
bustible portion likely will burn. The rest will be carried
out of the furnace as "new cinders."
4-28
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25 IB "EC
S LB CAR
ECYCLEO 1
ARBON
20 LB INORG ASH I
JECTION
... ^
BOILER
o
CARBON
BURNS
3— Z t
^
/L
\
y
CL
' SC
MECHANICAL
COLLECTOR
100 LB CINDER
IS LB CARBON
85 LB INORG ASH
;»0 LB ACCEPTED
10 LB CARBON
!0 LB INORG ASH
170 LB REJECTED
5 LB CARBON
\SS LB INORG ASH
Figure 24. Flow path of 100 pounds of cinders high in
inorganic ash, screened and reinjected, with good combustion,
Note the small amount of carbon burned and the
recirculation of inorganic ash.
4-29
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Operating a system like this is difficult to justify in
view of the increased rate of particulate emission from the
stack and the erosion of boiler tubes and the cinder collec-
tion system by the continually recycled inorganic material.
Now consider the opposite extreme, a furnace in which
combustion conditions are poor. Cinders collected in the
multiple cyclones are 90 percent carbon and the particles
are large. After screening, the reinjected material is 95
percent carbon and the particles are reduced in size. When
this material is reinjected into a furnace with poor combus-
tion, perhaps 20 to 30 percent of the carbon burns. The
remainder is recycled through the system. Because the
particles are small, a substantial portion will not be
caught in the collectors but will leave the stack as air
pollutants.
Two basic things are wrong with this system. First is
the attempt to burn, in an already poor combustion situa-
tion, a material that does not burn well. Second is the
amount of inorganic, incombustible material, which is the
same as in the first example; this material is recycled
through the system, causing erosion and higher particulate
loading.
Cinder reinjection is practiced in spite of these
disadvantages because reinjection helps to solve a serious
4-30
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problem of solid waste. For example, a boiler that is
designed for a capacity of 100,000 pounds per hour on hogged
fuel probably emits 800 to 900 pounds of cinders per hour,
of which some 300 to 400 pounds per hour is combustible.
Reinjection reduces the solid waste problem in two ways.
First, it reduces the total volume by the amount that is
combusted. Second, it disposes of the remainder of the ash
by emitting it to the atmosphere as particulate matter.
ftxus, a, solid wa,ste problem is reduced by increasing the
emissions of a,irborne wastes.
One type of boiler developed recently relies heavily
upon cinder reinjection for proper operation. This boiler
is designed for high gas velocities through the heat ex-
change section to prevent buildup of soot on the tubes. The
cinder-ash material continually impinges upon the tube
surfaces in an erosive cleaning action. A centrifugal
particle collector then removes the cinders and ash after
the air heater and sends them to a vibrating screen sepa-
rator. The cinders are taken from the top of the screens
and returned to the furnace, and the fine ash is collected
and removed after it passes through the vibrating screens.
Approximately six percent of the heat input is from
the reinjected cinders and no soot blowing is necessary.
4-31
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New designs, then may reduce the detrimental effects of
cinder reinjection and optimize its advantages. Alterna-
tives to reinjection to reduce the burden of solid wastes
include use of the cinders as landfill, as raw material for
charcoal briquets, as filler in concrete blocks and road-
ways, and as a soil conditioner.
OPERATOR VARIABLES
Soot and ash deposits must be removed from the furnace
and heat exchanger tubes regularly to maintain good combus-
tion and heat transfer. Failure to remove these materials
causes partial blocking of the gas passages. If the grates
are plugged, combustion air will be inadequate in localized
parts of the furnace, leading to loss of steam generating
capacity, loss of efficiency, and an increase in pollutant
emissions. Plugging of the tube passages brings similar
results.
Soot blowing and grate cleaning are regularly scheduled
at most plants. The frequency depends on content of fuel
ash, combustion efficiency, furnace design, average rate of
steam generation, steam demand, local control regulations,
and the operator's initiative.
4-32
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The important point is that a clean boiler generates
heat more efficiently and pollutes less than one that is
fouled with ash and soot. The operator has some control
over the cleanliness of a boiler, but he has less control
over other significant combustion factors such as basic
furnace design, over-all maintenance, steam generation rate,
and water level.
The pronounced effects of boiler design, maintenance,
and steam generation rate on the total combustion pattern
have been discussed in detail. Many operators report that
variations in water level in the steam drum also strongly
affect the combustion rate. Their experience indicates that
a responsive, automatic, liquid-level control system on the
feed-water system at the steam drum is helpful in control-
ling furnace temperatures, particularly in water-walled,
spreader-stoker systems.
In all instances, the experience and judgement of the
operator contribute greatly to the efficiency of plant
operation. His diligence in understanding and applying the
basic principles outlined in this section can make the
difference between a marginal operation and one that is
efficient, safe, and environmentally acceptable.
4-33
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5.0 PARTICULATE EMISSIONS
Particulate emissions from wood-fired boilers may be
either solid or liquid, although the solid matter is pre-
dominant. They consist of inorganic materials, unburned
hydrocarbons, and unburned carbon. Size of the particles
can range from submicron "smoke" particles to pieces of wood
or char 1/2 inch or larger. The material is usually chemi-
cally stable as it enters the atmosphere, but some boilers
emit still-burning particles of wood that may be observed at
night as a discharge of glowing sparks. The particulate
matter may be soluble in water (such as salts) or completely
insoluble (such as unburned carbon).
Regulations covering particulate emissions are usually
nonspecific regarding chemical and physical properties.
Most are concerned only with the amount of concentration of
emissions although regulations in some states incorporate
design or construction standards.
REGULATIONS FOR PARTICULATE EMISSIONS
Emission regulations for wood-fired boilers may be set
by state or regional agencies. As yet, the U.S. Environ-
mental Protection Agency has not promulgated New Source
5-1
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Performance Standards for wood-fired boilers. Most agencies
require a permit to operate, contingent upon the boiler
meeting the agency regulations. Although the emission
regulations vary among the agencies, many similarities may
be noted.
Particulate Concentration
Grains per Standard Cubic Feet
Particulate concentration may be expressed as the mass
of particulate matter per cubic volume of flue gas. This is
usually normalized to 12 percent CO- to account for dilution
by excess air at the furnace or leakage into the furnace or
boiler. For wood fuels 12 percent CO2 in the flue gas
corresponds to approximately 68 percent excess air. A
typical regulation might limit the maximum particulate
emission to 0.2 grain per standard cubic foot of gas, cor-
rected to 12 percent C0~, for existing boilers and 0.1 grain
per standard cubic foot of gas, corrected to 12 percent C0?,
for new boilers constructed after a certain date. The
regulation may state that the standard cubic foot is "dry,"
meaning that the water volume present in the gas phase must
be subtracted. A regulation that does not state whether the
standard cubic foot is "wet" or "dry" leaves the matter open
to interpretation.
5-2
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The "standard" cubic foot is also ambiguous unless it
is defined. The "standard" temperature for a cubic foot may
be 32, 60, 68, or 70°F, or 20°C, which is equivalent to
68°F. The "standard" pressure for the same cubic foot may
be expressed as 29.92 inches of mercury, which is the same
as 14.7 pounds per square inch absolute or 1 atmosphere.
Some agencies, however, use 30.00 inches of mercury as
pressure for the "standard" cubic foot.
Consider an example in which a stack sample is col-
lected at 8 percent C02 , 400°F, and 29.75 inches of mercury
with a water vapor content of 15 percent by volume. If the
particulate loading is 0.05 grain per cubic foot at stack
gas conditions, what is the at "standard" conditions of 12
percent CO2/ 68°F, 29.92 inches of mercury, and dry? The
following calculations show the method of correction to
standard conditions:
0.05 grain 12 percent C02 46Q + 400oF
test cubic foot 8 percent CC>2 x 460 + 68°F x
29.92 inches 100 test ft3 =
29.74 inches X ffc3
0.14 grain _ @ 12 ercent
L XZ percenr
standard cubic foot
The original grain loading appeared quite low; when it
was corrected and expressed in relation to the normalized
"standard" cubic foot, it was nearly three times greater.
5-3
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Pounds per Million Btu
Expressing an emission standard in terms of mass per
unit of energy overcomes the problems of the "standard"
cubic foot of flue gas and normalizing to 12 percent CO-. A
regulation might specify an emission standard of 0.2 pound
of particulate per million Btu of input energy. Some
agencies might allow a higher value (0.5 pound per million
Btu) for boilers installed or operating before a certain
date.
One flaw in this emission standard is in the definition
input energy. One needs to know whether the higher or lower
heating value is used, whether a correction is made for the
energy used to evaporate the water from wet fuel, and whether
the fuel input should be weighed or calculated from values
for flue gas volume and gas analysis. The regulations
should specify these considerations.
Pounds per Pound of Fuel or Ton of Fuel
Some agencies specify allowable particulate emissions
based upon fuel throughput. These values coincide with the
values used in emission inventories. Problems occur, how-
ever, because it is difficult, if not impossible, to weigh
the fuel going to a wood-fired boiler. Again, the regula-
tion also should specify what corrections should be made for
the weight of moisture and whether flue gas volumes and gas
analyses can be used to calculate the mass of fuel.
5-4
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Mass of Emissions
The mass emission per unit of process weight is usually
included with the allowable mass emission for the entire
mill or plant. If a process weight chart shows an allowable
atmospheric discharge for the mill, the boiler emissions may
be included along with those from cyclones or dryers to
determine the total for the operation. If the boiler is the
only source at the mill, it could emit particulate up to the
maximum allowed by the process weight chart and still be
legal. Again, it is obvious that the regulation should be
well-defined.
Opacity
Regulation of boilers by means of visual emission
standards usually refers to the opacity of the effluent from
the boiler. A certified observer must "read" the opacity
periodically and determine whether the boiler is in compli-
ance. Typical regulations may state, "No visual emissions
exceeding 20 percent opacity will be permitted except for 3
minutes in any 1 hour." Some agencies may allow 40 percent
opacity for existing boilers or boilers located in areas of
low population density. The regulation may state the time
exemption differently or may clarify or further define it.
The observer making the opacity readings must be trained
and certified by the control agency. He should be aware
5-5
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that opacity readings are affected by such things as dia-
meter of the stack exit, moisture content of the plume,
particle size and color, background lighting and textures,
position of the sun, and color of the sky.
Certification schools for smoke and opacity readings
have been set up across the country. Classes are held
throughout the year to meet the demand. The classes consist
of two sessions, first to learn the theory and limitations
of the techniques, and second to gain experience in the
field by reading plume opacities. Examinations are held at
the end of each session to determine degree of competence.
Recertification of ability in smoke and opacity reading is
required at intervals ranging from 6 months to 1 year.
Particle Size
Some agencies have established limits on the maximum
size of particles that may be emitted by boilers. The
limitation usually is set at 250 microns. The purpose is to
prevent emission of large pieces of unburned carbon, which
act as a soiling nuisance. Consideration now is being given
to establishing regulations on the maximum allowable con-
centration of smaller particles (less than 10 microns),
since many studies indicate that smaller particles present
the greatest hazard to human health.
5-6
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Particle size measurement requires sophisticated equip-
ment for collection and analysis, as well as skill in analy-
tical techniques. Representative sampling for particulate
matter can be achieved only if the particulate matter enters
the sampling system at the same velocity as the airstream in
which it is entrained. This is called isokinetic sampling.
Analysis of the samples usually is done with a micro-
scope in the laboratory. A minimum of 100 particles should
be measured to determine the size distribution of particles
in each sample. Distribution is reported in terms of the
percentages of particles smaller than a given size.
When particles are collected in impaction systems,
analyses for size and weight distribution is done by weigh-
ing the samples collected in each section of the impactor.
This method also allows a determination of mean size and
size distribution of the particles, based on the weight
distribution of the sample.
Nuisance Regulations
Most agencies regulate nuisance emissions, usually in a
statement to the effect that no process or operation shall
emit materials that are a nuisance to the surrounding pro-
perty or community. Such regulations are not directed
specifically toward boilers fired with hogged fuel. They
are cited occasionally, however, if fly ash or unburned
carbon from a stack becomes a public nuisance.
5-7
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Regulatory Problems
The regulations regarding particulate emissions from
boilers are usually written for the general case of a single
boiler on a single stack, operating routinely. Some boilers,
however, are not operated in this manner. When two or more
boilers are connected by breeching to the same stack, the
visual opacity readings at the stack exit indicate only the
conditions of the combined flue gases. The emission of
dense smoke may be caused by one boiler or by several. A
measurement of particulate loading in the stack is equally
nonspecific. The loadings must be measured in the breeching
from each boiler to determine the individual boiler emis-
sions.
A second type of nonroutine situation involves the
exhausting of boiler flue gases through another process. As
energy conservation becomes more important, more mills and
plants are looking for potential uses of the hot flue gas,
for example as input to the particle dryer at a particle-
board or hardboard plant. The question then becomes whether
the flue gas leaving the dryer is classified as a boiler or
a dryer emission. Similarly, if the flue gas is ducted to a
system for predrying of the fuel before it enters the fur-
nace, is exhaust from the fuel dryer classed as a boiler
emission or another process emission? Many regulations
leave these questions unanswered.
5-8
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Soot blowing and grate cleaning can introduce further
complications. Emissions of particulate matter usually
increase severalfold during intermittant soot blowing and
intermittent cleaning of grates. An emission sample col-
lected during these periods is likely to show excessive
particulate loading, as would an opacity reading. For this
reason soot is usually blown at about midnight, and no soot
blowing or grate cleaning is practiced during emission
tests.
PARTICULATE MEASUREMENT METHODS
Compliance with emission standards is usually deter-
mined by sampling at the polluting source. Source sampling
is done by EPA methods or by methods specifically endorsed
by the EPA.
Sampling for particulates involves a problem not en-
countered in sampling for gases. Particles moving in a gas
stream tend to follow the streamlines, but the particles
have a greater inertia than the gas molecules. Anytime a
streamline makes a bend, the particle tends to continue on
its original path, deviating from the streamline. This
accurate sampling of particulate concentrations must be done
isokinetically; that is, the probe must draw a sample at the
same velocity as the gas stream being sampled. If the
sampling velocity is less than the gas flow velocity, the
5-9
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streamlines will bend out and around the probe inlet.
Instead of following these streamlines the particles will
tend to continue in a straight line to the probe inlet. The
analysis will show falsely high particulate loading for the
volume of gas sampled. If the sampling velocity is greater
than the gas flow velocity, the opposite will occur; the
streamlines will bend into the probe inlet, and the par-
ticles will tend to continue past it. The analysis will
show a falsely low particulate loading for the volume of gas
sampled.
EPA Method 5
In 1971 the EPA adopted a standard method for testing
of new fossil-fuel-fired boilers. Many control agencies
have adopted this as the only acceptable method for sampling
combustion sources. It has not been determined that this is
the preferred method for sampling of wood-fired boilers.
The EPA Method 5 sampling system is a modification of
one developed by the U.S. Bureau of Mines about 60 years
ago. Figure 25 is a schematic diagram of the EPA sampling
train.
The system collects two types of materials: the filter
collects the solid particulates, and liquids that condense
at filter temperature, and the impingers collect materials
that condense at impinger temperature. Everything collected
5-10
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PROBE -ff STACK
II—WALL
REVERSE-TYPE
PlTOT TUBE
IMPINGER TRAIN OPTIONAL. MAY BE P.EPLACtD
BY AN EQUIVALENT CONDENSER
HEATED AREA F,ILTERWOLDER / THERMOMETER CHECK
,VACUUM
LINE
THERMOKETERS
VACUUM
GAUGE
MAIN VALVE
DRY TEST METER AIR-TIGHT
PUMP
Figure 25. Method 5 sampling system
15
5-11
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up to and including the filter is called the "front-half"
catch. Everything collected behind the filter is considered
the "back-half" catch. In sampling New Source Performance
Standards the EPA measures only the "front-half" catch using
the impinger train only to determine the amount of water
vapor in the sample and to protect the pump and gas meter
from corrosive, condensible vapors. Many agencies, however,
require reporting of the total catch (front and back) for
emission testing of combustion sources.
The EPA Method 5 train samples at approximately 1 cubic
foot per minute over collection periods of about 2 hours.
This relatively long sampling period requires that the
boiler operator hold a steady load to obtain valid test
results.
High-Volume Method
The high-volume stack sampler was developed to obtain a
sample rapidly during actual operation. It provides a valid
sample from a wood-fired boiler in 1 or 2 minutes. Other
advantages of the sampling train are discussed by Boubel.
Many producers of forest products use the high-volume sampl-
ing train to test ambient temperature sources, and they have
naturally adopted its use to their wood-fired combustion
sources. Several state and regional control agencies have
accepted results obtained with the high-volume system as
valid for determining compliance.
5-12
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The latest high-volume sampling train incorporate an
electronic computer to adjust the sample flow rate auto-
matically for isokinetic sampling. The computer displays
the flow in cubic feet per minute and total cubic feet
sampled. This sampling train has been used successfully on
several wood-fired boilers.
One definite advantage of the high-volume system for
sampling wood-fired boilers is the large probe. The large
flow volumes permit isokinetic sampling with probes of 15/16
to 1 7/8 inches in diameter. The advantage is that a boiler
with no particulate collection equipment may emit particu-
late as large as 1/2 inch on a side and the high-volume
sampler collects these particles whereas low-volume trains
with small probes (such as EPA Method 5) reject them.
The high-volume sampler appears to be the method of
choice for use with wood-fired boilers. Comparison sampling
with this sampler and the Method 5 sampler has shown no
significant difference in particulate emissions from wood-
fired boilers (these studies are described later). The
system allows accurate calculation of the moisture in the
stack gas, and since wood contains practically no sulfur,
the flue gas does not attack the sampler. The flow measure-
ment system is an orifice plate that determines the flow of
all gases (even water vapor) accurately. The cost of test-
ing with the high-volume system is considerably lower than
that for other methods currently in use.
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Opacity Measurement
Regulation covering the opacity of emissions from wood-
fired boilers usually specify readings by a qualified ob-
server. Smoke density readings by qualified inspectors have
been accepted and upheld in most court actions. Some
agencies regulate only opacity, rather than particulate
loading, because source testing is expensive and complaints
by citizens usually are concerned with visual emissions.
Certified Observers
Emission regulations based on opacity, optical density,
or Ringlemann number require plume readings by a trained and
certified observer. Because wood smoke is sometimes light
grey or white, the observer must be qualified by a smoke
school to read both "white" and "black" plumes. The ob-
server must also be experienced in reading moist plumes
because the water vapor content of flue gas from wood-fired
boilers is high. The observer must keep accurate records of
all conditions at the time of the readings. Reexamination
is required before expiration of a certificate if an ob-
server's readings are to be accepted in court. Certifica-
tion periods usually cover 6 months or 1 year.
Opacity Monitors
Although opacity monitors are useful for informing the
boiler operator of the visual condition of the plume, they
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involve several inherent difficulties. One is that sub-
stantial errors can occur because of differences in geometry
of the stack and the monitoring system. Also, being mounted
in the boiler breeching, the monitors may be subject to high
temperature and vibration and thus may need frequent main-
tenance and recalibration. A further difficulty is that
particulate emissions tend to coat the protective lenses on
the optical system, causing false readings of opacity.
Lenses must be cleaned frequently to keep the instruments
functional. The most expensive commercial models are equip-
ped with continuous purge systems to overcome this problem.
Opacity is dependent upon many factors, such as gas
temperature (density), size and concentration of particulate
matter, relative humidity, and length of light path. Should
any of these parameters differ at the monitoring location
and the discharge point of the stack, the monitor would not
indicate opacity at the discharge point. Because opacity is
strongly dependent on size of the particles in the gas
stream, measurements of opacity cannot be used as measure-
ments of particle concentration. Attempts to relate concen-
trations of flue gas particles and opacity have not been
highly successful. Some are discussed later.
The cost of opacity monitors ranges widely. The least
expensive units can be installed for less than $500. At the
5-15
-------
other end of the scale, the investment can exceed $8500.
Such a system would include automatic recalibration at
regular intervals, continuous purge systems to keep the
lenses clean, automatic correction for geometric differences
in the monitoring location and the stack outlet, low main-
tenance, and high reliability.
Some commercial monitors measure optical density rather
than opacity. Opacity is measured on a percentage scale,
whereas optical density is scaled from zero to infinity.
The relationship is illustrated in Figure 26, which shows
that zero percent opacity corresponds to zero optical den-
sity. The term "absorbance" is used interchangeably with
optical density.
THEORETICAL EMISSIONS
Particulate emissions from a wood-fired boiler may be
approximated by calculation. The following example problem
will illustrate the method:
ASSUMPTIONS - Fuel is Douglas fir bark with 50 percent
moisture and 1 percent ash.
Fuel feed rate is 20,000 pounds of wet fuel
per hour.
Heating value is 9000 Btu per wet pound.
Excess air is 50 percent.
Half of the ash leaves the stack as fly ash
containing 25 percent carbon.
5-16
-------
0.5
to
z
UJ
O
0.!
0.05
0.02
20 40 60 80 100
OPACITY, PERCENT
Figure 26. Relation of opacity to optical density
5-17
-------
The first calculation is to determine the gas flow, in
scfm, through the boiler.
At 0 percent excess air, 1 dry pound of Douglas fir
bark requires 6.17 pounds of air for complete combustion.
50 percent excess air =1.5 (6.17) = ?'2^ lb aif
^ Ib dry fuel
Neglecting any ash, the flue gas (dry) is composed of
the 9.26 pounds of air plus the pound of dry fuel (after
combustion), minus the water from hydrogen combustion; so:
9.26 Ib of air _ 10.20 Ib flue gas
Ib of fuel+ °'y4 lb tuel Ib dry fuel
The volume of flue gas may be calculated using mol
percentage, but a good approximation is 13 standard cubic
feet per pound.
10.20 Ib flue gas 13 standard cubic feet _
Ib of dry fuel Ib of flue gas
132.6 standard cubic feet/pound of dry fuel
The fuel rate is:
20,000 Ib wet fuel 0.5 Ib dry fuel _
hour Ib wet fuel
10,000 Ib dry fuel
hour
The fuel gas volume (dry) is:
132.6 scf 10,000 Ib dry fuel _
Ib dry fuel hour
1,320,000 standard cubic feet per hour
5-18
-------
The particulate as fly ash is:
20,OOP Ib wet fuel 0.01 Ib ash
hour Ib wet fuel
1 Ib fly ash _ 100 Ib fly ash
2 Ib ash hour
The emission may now be expressed in terms approximate
to those of the regulations:
1. Grains per standard cubic foot at 50 percent excess
air:
100 Ib 7000 grains hour 0.53 grain
hour X Ib X 1,320,000 scf scf
2. Pounds per million Btu:
100 Ib hour Ib wet fuel
hour X 20,000 Ib wet fuel X 9000 Btu X
106 Btu 0.56 Ib
million Btu million Btu
3. Pounds per ton of fuel:
100 Ib hour 2000 Ib wet fuel
hour x 20,000 Ib wet fuel ton of wet fuel
10 Ib
ton of wet fuel
4. Pounds per hour:
, , .. 100 Ib fly ash
From previous calculation = =- *
These simple calculations show clearly that some method
of particulate control will be required to meet any realis-
tic emission standard.
5-19
-------
MEASURED EMISSIONS
Measurements of emissions from boilers have shown the
same order of magnitude as the calculated emissions. A
boiler with no particulate removal equipment, firing a dirty
fuel at approximately its rated capacity, may emit more than
1.0 grain per standard cubic foot corrected to 12 percent
C0?. A boiler with primary and secondary flue gas cleaning
systems, firing a relatively clean fuel, may emit as little
as 0.01 grain per standard cubic foot corrected to 12 per-
cent CO-. The boiler emitting 1.0 grain/scf would not meet
any emission standard, whereas the boiler emitting 0.01
grain/scf would meet all standards.
EPA Method 5 Testing
As stated earlier, in EPA Method 5 sampling of fossil-
fuel-fired boilers for compliance with New Source Perform-
ance Standards, only the front half (ahead of the impinger
train) is considered as particulate. Many states require
reporting of the total catch, while others require reporting
only the front half. It may be useful, then, to consider
what portion of the particulate emissions is collected in
the impinger train (back half). For wood-fired boilers,
that portion is approximately 5 to 10 percent of the total.
Although some values as high as 25 percent have been re-
ported, these are probably due to leaks in the filter sec-
tion that allowed the particulate to reach the impingers.
5-20
-------
Usually the ratio of front- to back-half catch can be
determined by careful examination of the data. Table 14
shows data from one series of tests recently reported by
18
Morford. Front-half catch and back-half catch were re-
ported separately for all runs. This tabulation indicates
that 93 percent of the catch was in the front half and 7
percent in the impinger train.
In considering the relative importance of the back-half
catch, one must also consider the over-all accuracy of the
method. It has been reported that the data from EPA Method
5 tests are probably accurate within +25 percent. In view
of the wide range, it seems trivial to debate the inclusion
of a portion of sample amounting to 7 percent.
Table 15 compiles results of 135 particulate emission
tests of wood-fired boilers in Oregon and Washington since
19
1965. The data represent both front- and back-half catch,
as required in these states. The tests encompass a wide
variety of boilers firing different wood and bark fuels,
operating at light to heavy steam loads, with and without
particulate controls. Figure 27 summarizes these emissions
data in graphic form.
High-Volume Testing
Since the moisture in flue gases of a wood-fired boiler
may be calculated, a valid sample from a wood-fired boiler
5-21
-------
Table 14. EPA METHOD 5 DATA AS REPORTED BY MORFORD
18
Test
EWEB No. 2
EWEB No. 31
EWEB No. 32
U of 0 No. 1
U of 0 No. 3
GP NO. 1
GP No. 2
Morning
Afternoon
Morning
Afternoon
Morning
Afternoon
Morning
Afternoon
Morning
Afternoon
Morning
Afternoon
Morning
Afternoon
Average
Total catch,
grain/scfa
0.157
0.147
0.197
0.405
0.174
0.306
0.246
0.244
0.120
0.116
0.070
0.118
0.242
0.288
0.202
Front-half catch
grain/scf
0.140
0.135
0.162
0.364
0.136
0.235
0.235
0.233
0.117
0.114
0.064
0.108
0.233
0.275
0.182
% of total
89.17
91.84
82.23
89.88
78.16^
76.80
95.53
95.49
97.50
95.49
91.43
91.53
96.28
95.49
92.86
At 12 percent CO^.
Omitted from average because of leaking filters.
5-22
-------
Table 15. EPA METHOD 5 TESTS ON HOG FUEL BOILER
INSTALLATIONS3 IN OREGON AND WASHINGTON19
gr/scf
0.13
0.07
0.063
0.82
0.13
0.238
0.115
0.19
0.075
0.175
0.195
0.11
0.069
0.220
0.113
0.143
0.38
0.42
0.192
0.15
0.39
0.16
0.095
0.064
0.17
0.19
0.16
0.13
0.09
0.10
0.29
0.21
0.31
0.22
0.67
0.10
0.16
0.30
0.43
0.27
0.46
0.51
0.33
0.36
0.12
Ib part.
ton fuel
5.79
3.12
2.82
36.54
5.79
10.61
5.12
8.46
3.34
7.81
3.69
4.90
3.07
9.81
5.04
6.37
16.94
18.72
8.56
6.69
17.38
7.14
4.24
2.85
7.58
8.46
7.14
5.79
4.02
4.46
12.93
9.36
13.82
9.81
29.86
4.46
7.14
13.38
19.17
12.03
20.50
22.74
14.70
16.05
5.34
/ *b
gr/scf
0.16
0.08
0.17
0.11
0.17
0.05
0.10
1.23
0.68
0.91
1.27
1.12
0.17
0.17
0.07
0.098
0.098
0.149
0.139
0.237
0.357
0.184
0.374
0.102
0.199
0.326
0.518
0.191
0.163
0.10
0.140
0.141
0.154
0.08
0.07
0.17
0.32
0.092
0.136
0.69
0.62
0.144
0.174
0.104
0.177
Ib part.
ton fuel
7.14
3.57
7.58
4.9
7.58
2.22
4.45
40.0
26.0
36.0
46.0
32.0
8.4
8.2
2.64
3.68
3.72
5.4
6.6
9.2
13.0
7.2
12.4
3.8
7.6
13.0
19.6
4.8
4.6
4.0
5.0
5.0
5.96
3.0
2.6
6.7
12.34
4.1
5.4
16.54
20.6
6.6
5.48
4.64
7.89
gr/scf
0.126
0.0219
0.0106
0.184
0.377
0.236
0.222
0.163
0.150
0.165
0.136
0.603
1.17
0.104
0.177
0.154
0.126
0.149
0.199
0.237
9.351
0.092
0.136
0.167
0.171
0.184
0.374
0.326
0.518
0.191
0.163
0.018
0.008
0.08
0.07
0.17
0.32
0.067
0.098
0.102
0.199
0.140
0.141
0.184
0.377
Ib part.
ton fuel
5.62
0.98
0.47
8.2
16.81
10.51
9.89
7.26
6.69
7.36
6.06
26.88
52.16
4.64
7.89
6.86
5.62
6.64
8.86
10.56
15.92
4.10
6.06
7.44
7.62
8.21
16.67
14.53
23.09
8.51
7.26
0.8
0.35
3.57
3.07
7.58
14.27
2,99
4.37
4.54
8.86
6.24
6.29
8.21
16.80
These boilers are not identified by type, size, or owner.
At 12 percent CO.,.
5-23
-------
ui
I
NJ
CM
O
O
CO
o;
CD
O
co
CO
O
*—*
C£
Q-
1.0
.9
.7
.5
.4
.3
.2
.1
.09
.07
.05
.04
.03
.02
.01
0.01
III
I I
I L
I I I I I I
J I
1 2 5 10 20 30 40 50 60 70 80 90 95 98 99
CUMULATIVE PERCENT
99.99
Figure 27. 135 EPA Method 5 tests in Oregon and Washington
19
-------
stack can be obtained by use of a probe followed by a filter
and metering section, as in a high-volume sampler. With
this sampler several samples can be taken in a single day
for statistical analysis or for following intentional
changes of boiler load or combustion conditions. Some
states accept this high-volume sampling data for compliance
testing. In states requiring compliance tests by EPA Method
5, many companies use the high-volume sampler for precom-
pliance testing and adjustment of the boiler before under-
*| /- -i *y I Q
taking the expensive EPA Method 5 test. ' '
High-Volume, Steady-State Tests
Because the high-volume system provides a valid sample
in 1 or 2 minutes, several samples can be obtained at rela-
tively steady boiler loads for statistical analysis. The
test results can then be expressed in terms of a mean emis-
sion loading with a standard deviation, which is much more
meaningful than a single test result number. Table 16
summarizes results of several such tests performed over the
17 18
past 10 years by Boubel and others. '
The table indicates that six to eight tests generally
produce a standard deviation of about 10 to 20 percent of
the mean. Two tests produce a higher standard deviation, 30
to 60 percent of the mean. For an accurate picture of
particulate emissions, probably at least six tests should be
run at each boiler loading.
5-25
-------
Table 16. HIGH-VOLUME TESTS OF WOOD-FIRED
17 1 fi
BOILERS AT STEADY LOADING '
Code letter
of boiler
A
B
B
C
D
E
F
G
G
G
H
I
J
K
L
L
M
M
N
N
N
0
P
Q
R
S
Boiler load,
% of rating
30
82
47
75
75
46
46
33
75
83
100
67
42
75
67
92
67
92
60
80
100
100
100
100
100
100
Total no.
of tests
8
8
6
8
7
5
6
3
3
6
6
6
4
6
3
3
3
3
2
2
2
3
2
2
2
2
Mean loading, Std. deviation,
gr/scf at 12% CO2
0.204
0.223
0.265
0.240
0.106
0.113
0.246
0.169
0.132
0.176
0.524
0.138
0.112
0.204
0.384
2.091
0.403
0.739
0.942
0.913
1.385
0.774
0.189
0.567
0.115
0.626
0.019
0.090
0.032
0.030
0.010
0.032
0.063
0.020
0.021
0.022
0.041
0.017
0.012
0.049
0.047
0.462
0.079
0.004
0.376
0.341
0.030
0.052
0.101
0.019
0.075
0.183
5-26
-------
High-Volume Tests at Varying Conditions
Testing with the high volume sampler is rapid enough
that plant personnel can vary the operating parameters to
determine their effects on particulate emissions. Table 17
shows the effects of varying both load and excess air on a
boiler during 1 day of testing.
Table 17. HIGH-VOLUME TESTS OF A WOOD-FIRED BOILER AT
VARIABLE LOADS AND EXCESS AIR SETTINGS (BOILER 5)
Steam load,
% of rating
35%
35%
55%
55%
55%
100%
100%
Excess
air, %
400
165
180
145
105
45
35
Particulate emissions,
gr/scf at 12% C02
0.727
0.174
0.418
0.227
0.184
0.496
0.755
High-volume testing also allows determination of par-
ticulate loadings before and after a control device to
determine its efficiency. The boiler must be held at a
steady state for only minutes. Table 18 shows results of an
efficiency test of a centrifugal particulate collector,
measured with a high-volume sampler. The effect of varying
the boiler loading shows in particulate emissions both
before and after the collector. The efficiency of the
collector increased as the loading increased, the expected
trend for an inertial collector.
5-27
-------
Table 18. RESULTS OF EFFICIENCY TEST OF CENTRIFUGAL
COLLECTOR ON WOOD-FIRED BOILER (BOILER K)
Boiler load,
% of rating
54
76
100
Collector loading,
gr/scf
Inlet
0.099
0.170
0.213
Outlet
0.080
0.091
0.102
Collector
efficiency, %
19
46
52
When the fuel load on a wood-fired boiler is changed,
it is probable that emissions will change. For this reason
it is desirable to test a boiler at both its normal operat-
ing load and its rated capacity. High-volume testing is
rapid enough to indicate the emission pattern of a boiler as
the load is changed.
Table 19 shows the results of testing three separate
boilers at one plant, at their normal and rated loads. The
spreader stoker does not seem to be as sensitive to load
change as are the two Dutch ovens. Note that all three
boilers are emitting excessive particulate at all loads.
The plant installed new particulate control devices on the
basis of these tests.
The high-volume sampler was used to test one wood-fired
boiler to show the harmful effect of cinder reinjection.
Two tests were made with reinjection, then the reinjection
5-28
-------
Table 19. PARTICULATE EMISSIONS OF THREE
BOILERS AT VARIOUS LOADS
(Each test is average of two or three individual tests)
Boiler type
and code letter
Dutch oven (L)
Dutch oven (L)
Dutch oven (M)
Dutch oven (M)
Spreader stoker (N)
Spreader stoker (N)
Spreader stoker (N)
Boiler load,
% of rating
73
100
73
100
60
80
100
Particulate emission,
gr/scf at 12% C02
0.384
2.242
0.403
0.739
0.942
0.913
1.385
Table 20. PARTICULATE EMISSIONS FROM A SMALL SPREADER STOKER
WITH AND WITHOUT CINDER REINJECTION (BOILER 6)
Sample no.
1
2
Average
3
4
Average
Reinjection
Yes
Yes
Yes
No
No
No
Particulate emission,
gr/scf at 12% CO2
0.1482
0.1494
0.1488
0.1287
0.1133
0.1210
5-29
-------
system was inactivated for two more tests. Results are
shown in Table 20. Although this boiler did not meet a
grain loading standard of 0.1 grain per scf at 12 percent
CO-, the particulate emissions decreased by 20 percent
without cinder reinjection.
Particle Size Analysis
Samples collected in impaction systems may be analyzed
for particle and weight distribution by weighing the por-
tions collected in each section of the impactor. Deter-
mination of mean size distribution of the particles is based
on the weight distribution of the sample.
Wood-fired boilers may emit particulate too large for
analysis by impaction methods. The material may be sized by
a screen analysis, but this requires a very large sample.
Such a sample may be obtained by operating a high-volume
sampler over a long time period.
The usual method for particle sizing of material col-
lected in a high-volume sampler is to scrape some of the
material off the filter and place it on a microscope slide.
If the loading is very light, the particles may be sized by
cutting a representative sample from the filter and placing
it on a microscope slide, dirty side up. The filter is then
cleared by a drop or two of immersion oil and the particles
sized directly. In either case, a minimum of 100 particles
should be sized under a microscope. Sizes may be reported
5-30
-------
in terms of the percentage of particles smaller than a given
size. Because the particles sizes usually follow a log
normal distribution, a mean size and geometric deviation
describe the sample. The mass mean may be computed from the
size mean by the formula:
In M'g = In Mg + 3 (In a)2
where:
M'g = Mass Mean
Mg = Size Mean
a = Geometric Deviation
Table 21 shows particle sizes from several tests of
wood-fired boiler with high-volume samplers.
Table 21. PARTICLE SIZES FROM HIGH-VOLUME TESTS
17 1 R
OF WOOD-FIRED BOILERS '
Boiler tested
(code letter)
Ga
H
I
J
K
L
L
M
M
N
N
sa
Size mean,
microns
1.9
3.6
4.5
5.0
2.1
5.3
23.4 .-•
6.5
26.4
6.8
13.7
6.8
Geometric
deviation
1.71
2.03
1.73
1.88
1.75
1.62
2.01
1.66
2.10
1.71
1.69
1.59
Mass mean,
microns
4.5
16.2
11.1
16.5
5.4
10.6
100.8
14.1
137.5
17.3
31.3
13. ,0
Boiler with centrifugal primary collector.
5-31
-------
Examination of Table 21 indicates that a large percent-
age of the particulate emitted from some wood-fired boilers
is in the respirable size range (less than 10 microns),
whereas emissions from others are so large that they con-
stitute only a nusiance problem.
Particulate-Combustible/Ash Analysis
If a boiler is operating at maximum efficiency, it will
consume all the combustible material and emit only inorgan-
ics as fly ash. An inefficient boiler will emit large
quantities of unburned organic material and carbon. By
collecting the particulate matter on a glass fiber filter
and ashing the filter in a muffle furnace, the analyst can
calculate the percentages of organic and inorganic materials
in the fly ash. The high-volume filter is particularly
useful for such analyses because it can collect a large mass
of sample. Table 22 shows the analysis of several particu-
late samples.
The effect of boiler loading is indicated in Table 23.
The boiler tested was a new spreader stoker with capacity of
45,000 pounds of steam per hour, equipped with a centrifugal
primary collector but with no reinjection system. At the
higher loadings the wood particles were not consumed com-
pletely and the unburned components came through with the
particulate fly ash. This boiler was required to meet a
5-32
-------
Table 22. ASH ANALYSIS OF PARTICULATE FROM SEVERAL
17 IS
WOOD-FIRED BOILERS '
Boiler tested
(code letter)
Particulate ash, %
L
L
M
M
N
N
K
O
P
Q
R
98
94
76
56
87
64
55
15
24
37
24
Table 23. PARTICULATE EMISSION ANALYSIS AND
CALCULATED ASH VALUES (BOILER 5)
Boiler load,
% of rating
35
55
100
Particulate
emissions,
grain/scf
at 12% C02
0.118
0.178
0.232
Particulate
ash, %
59.5
50.7
29.5
Calculated
uncombustible
emissions,
grain/scf
at 12% C02
0.070
0.090
0.068
5-33
-------
standard of 0.10 grain per scf at 12 percent CO.., but emis-
sions exceeded this level during the tests. If combustion
had been complete within the furnace, emissions would have
met the standard at all boiler loads. It is apparent that
emissions can be excessive when combustion is not complete.
Opacity
Opacity of plumes can be measured by observations of a
certified observer or by an opacity-monitoring instrument
mounted in the stack. Values obtained in these two types of
measurements may differ because of such variables as humid-
ity, chemical reactions, plume geometry, background condi-
tions, and winds.
20
Cristello has reported opacity values measured by a
trained observer and by an optical transmissometer. The
measurements were made on three different days under varying
conditions. The results, shown in Table 24, indicate con-
siderable differences between the visual and the instru-
2
mental readings. The coefficient of determination (r ) for
the data is 0.498, which indicates relatively poor correla-
tion. Data such as these are sometimes cited to show that
instrument readings may not be substituted for readings by a
certified observer in determining compliance with opacity
regulations. Interestingly, Cristello reports fairly high
correlations between instrumental opacity readings and
5-34
-------
particulate emissions determined by EPA Method 5, as dis-
cussed in the following section.
Table 24. COMPARISON OF VISUAL OPACITY WITH OPTICAL
TRANSMISSOMETER FOR A WOOD-FIRED BOILER20
Sample
date
5-22-74
5-30-74
7-4-74
Visual
opacity, %
30
20
40
0
15
20
80
0
100
Transmissometer
opacity, %
30
20
35
51
57
66
75
20
99
Comparison of Measured Emissions
Comparative testing of particulate emissions by dif-
ferent methods is done for several reasons. A large company
may operate boilers in several states and wish to standard-
ize on one test procedure. If they can demonstrate good
correlation with the standard method used in a particular
state, they may be allowed to use their method as an alter-
native or equivalent procedure. Also, correlations can
provide valuable guidance for boiler operation, since high
opacity reading may be expected if particulate emissions are
high.
5-35
-------
Comparison of EPA Method 5 and High Volume Method
18
Morford reports on an extensive series of tests in
which an EPA Method 5 sampling train and an automatic high-
volume sampler were operated in parallel on several wood-
fired boilers. Results are shown in Table 25. The values
are averages of two runs for Method 5 and Modified Method 5,
and four to eight runs for the high-volume method. The
Modified Method 5 values represent front-half catch only.
Table 25. COMPARISON OF EPA METHOD 5 AND HIGH-VOLUME
PARTICULATE SAMPLING VALUES
Boiler
code
A
B
B
C
D
E
F
Date
6 May 75
4 Mar 75
22 Apr 75
11 Mar 75
18 Mar 75
20 May 75
27 May 75
Mean grain loadings
High-volume
0.204
0.223
0.265
0.240
0.106
0.113
0.246
Method 5
0.152
0.301
0.240
0.245
0.118
0.094
0.265
Modified
Method 5
0.138
0.263
0.186
0.234
0.116
0.086
0.254
a Grains per standard dry cubic foot (gr/dscf) adjusted to
12 percent CO,,.
&
Statistical analysis of the data in Table 25 showed no
significant differences (a = 0.05) in the particulate load-
ings measured by the three methods. The standard deviation
5-36
-------
and standard error for the high-volume method were lower
than those for the EPA Method 5 and Modified Method 5.
This series of tests indicates that the high-volume
method could be considered as an acceptable alternative to
either EPA Method 5 or the Modified Method 5 in particulate
emission testing of wood-fired boilers.
Comparison of EPA Method 5 and Opacity
'20
Cristello reports comparative testing of two wood-
fired boilers. Particulate was measured with the EPA Method
5 sampling train at the same time a Lear-Siegler model RM-4
optical transmissometer was recording opacity of the plume.
Only front-half catch by the Method 5 train was reported.
The first test series was on a boiler rated at 300,000
pounds of steam per hour at 600 psi. A multiple cyclone
collector was the only control device. In a series of 21
2
tests, the coefficient of determination (r ) was 0.89. The
linear regression equation was:
% Opacity = 0.014 +1.29 (front-half particulate,
grains per scf)
The equation was developed from particulate values ranging
from 0.06 to 0.29 grains per dry scf.
The second test series was run on a common stack from
two Dutch oven boilers burning hogged fuel. The particulate
control device was an annular ring incorporating water spray
showers, the unit functioning as a wetted cyclone. In a
5-37
-------
2
series of eight tests the coefficient of determination (r )
for opacity versus the front-half particulate catch was
0.97. The linear regression equation was:
% Opacity = 0.105 +2.05 (front-half particulate,
grains per scf)
The equation was developed from particulate values ranging
from 0.01 to 0.20 grains per dry scf.
The two regression equations developed from tests of
the two boilers differ significantly, an indication that
although comparisons of particulate emissions and opacity
may be reliable for individual boilers, such comparisons
should not be applied to more than one boiler. Each boiler
must be tested to determine the correlation and regression
equation, which can be useful for predicting emissions.
5-38
-------
6.0 CONTROL TECHNOLOGY
The calculations presented earlier show that a wood-
fired boiler is unlikely to comply with a particulate emis-
sion standard of 0.2 grain per dry scf corrected to 12
percent C02 without some type of control device between the
boiler and the stack. If the emission standard is 0.1 grain
per dry scf, at least one control device is needed, and most
boilers required to comply with that standard over their
entire operating range must use two separate control devices
in series.
Operation of a boiler system in compliance with emis-
sion regulations is a function not only of the control
devices but also of the operator's training and skills, the
system instrumentation, the plant's maintenance and operat-
ing procedures, and the applicable regulations. These
factors, discussed earlier, are now considered as part of
the total technology for control of particulate emissions
from wood-fired boiler.
CONTROL DEVICES
The effectiveness of pollution control devices depends
to a large extent on the characteristics of the particles
6-1
-------
they are intended to capture. Consideration of these char-
acteristics is an important aspect of control technology.
1. Size - The size of fly ash particles from a boiler
may range from less than 1 micron to more than 100
microns. In determination of particle size, many
particles are measured and the results are aver-
aged. Particle size may be expressed as an aver-
age or mean size, or, as weight fractions with
assumed shape and density.
2. Density - Density of the particles affects the
collection efficiency of a pollution control
device. Low-density particles are more difficult
to collect by inertial collection devices than
high-density ones.
3. Settling velocity - Settling velocity is the
maximum speed that a particle can attain when it
is falling through quiet air. Particles that
settle at rates less than 1 centimeter per second
are considered to be aerosols.
4. Resistivity - Resistivity of particles is related
to their ability to carry electron charges and is
of concern only with respect to electrostatic
precipitators. Some particles can accept electron
charges, others cannot. The ability of fly ash
from hogged fuel to accept electron charges is
limited because of its resistivity.
5. Adhesiveness - Some particles are naturally
sticky, adhering to themselves and to other
surfaces under proper conditions of temperature
and moisture. Such particles may be easy to
separate from an airstream but difficult to remove
from the control device. Most emissions from
hogged fuel boilers present no such problem.
6. Particle strength - A major difficulty with fixed
carbon particles is that they break easily into
smaller particles. Mechanical processes that
involve rubbing, abrasion, vibration, or crushing
can greatly reduce the size of carbon particles.
This is of major concern in control of systems for
collecting and handling carbon.
6-2
-------
Inertia! Collectors
The most common particulate control device in use is
the cyclone separator, which separates particles from ex-
haust gases. As shown in Figure 28, the particle-laden gas
enters the top of the cyclone through a tangential inlet (or
inlet guide vanes) that spins the gas stream in a helical
path down the inside. 'The particles in the gas stream are
forced to deviate from a straight pathway as they rotate
about the cyclone axis. Their resistance to change in
direction causes the particles to migrate toward the cyclone
walls. As they reach the walls, gravity and the downward
motion of the gas stream carry them to the bottom. The gas
stream changes direction as it approaches the bottom and
rises toward the discharge in a return vortex.
From among many factors that affect cyclone efficiency,
six important ones are discussed here.
1. Diameter of cyclone. As cyclone diameter increases,
particles must travel farther through the air
stream to reach the wall. Therefore, increasing
the diameter reduces collection efficiency.
2. Length of cyclone. As cyclone length increases,
the residence time of the gas also increases,
allowing more time for the particles to move
through the gas to the wall. Thus, increasing the
length of the cyclone increases efficiency.
3. Particle disengaging zone. When particles reach
the bottom of the cyclone, they drop out under the
force of gravity. If a bin collection chamber is
at the bottom, the return vortex may dip into the
bin and reentrain particles in the exit gas stream.
6-3
-------
INLET
GAS EXHAUST
I V)
PARTICLE
SEPARATION
ZONE
PARTICLE
DISENGAGING
ZONE
PARTICLE OUTLET
Figure 28. Cyclone collector for particles in flue gases
6-4
-------
To prevent this occurrence, some cyclones are
equipped with disengaging zones at the outlet. As
particles reach the bottom of the first cone, they
drop into a second one, where their helical path
sends them to the periphery, away from the return
vortex. This design reduces the chance of reen-
trainment and increases cyclone efficiency.
4. Flow rates of the gas stream. Cyclones are de-
signed to operate within a range of gas flow
rates. If flow rates are too low, the centrifugal
force is not great enough to separate the par-
ticles from the carrier gas. If flow rates are
too high, then energy is wasted in pressure drop
across the unit and the return vortex configura-
tion may be disrupted. Operators should follow
the manufacturer's design criteria for the speci-
fied range of flow rates.
5. Push- or pull-through systems. Cyclones can be
operated either as push-through systems or under
vacuum as pull-through systems. Although there is
little theoretical difference in efficiency, the
push-through systems must include vacuum seals on
the bottom of the cyclone where the particles are
discharged. Any leakage of these seals will admit
air that can reentrain particles. Even though
they are generally less efficient, the pull-
through systems normally are used on hogged fuel
boilers because push-through systems subject the
induced-draft fan to extensive abrasion from
particles in the flue gas.
6. Particle characteristics. As noted earlier, the
size and density of particles control their settl-
ing velocity. Small particles with low settling
velocities may not be able to reach the cyclone
walls in the brief time that the gas is in the
cyclone. Figure 29 illustrates a typical curve of
cyclone efficiency for various particle sizes.
Note that for a typical cyclone the probability of
capture of particles whose diameters exceed 40
microns is 99 percent, whereas for particles with
diameters below 10 microns it is only 64 percent.
6-5
-------
SINGLE LARGE
CYCLONE
MULTIPLE
SMALL CYCLONES
20 40
PARTICLE SIZE, MICRONS
Figure 29. Relation of particle size to collection
efficiency of cyclones.
PARTICLE
DISCHARGE
Figure 29a. Simplified diagram of a multiple cyclone
6-6
-------
In multiple cyclone systems the cyclones are ducted in
a parallel-flow arrangement. Usually the term is applied to
systems that contain 50 to 250 small-diameter cyclones,
enclosed in a single box. A typical multiple-cyclone in-
stallation is pictured in Figure 29a. The inlet gas stream
is ducted to a manifold cyclone inlet. The gas stream
entering the top of any individual cyclone is directed
through inlet guide vanes into a heical path providing the
centrifugal force for separation of the particles. As with
conventional large cyclones, the gas stream moves downward
and then reverses direction and exits the cyclone in a
return vortex. Particles that are removed from the gas
stream drop into a hopper or bin.
Because the diameter of each of the multiple cyclones
is much smaller than that of a large cyclone, the efficiency
of particle collection is greater, particularly with small
particles. Figure 29 illustrates typical collection-effi-
ciency curves for multiple cyclones and standard large
cyclones.
Most multiple-cyclone installations on hogged fuel
boilers are installed upstream from the induced-draft fan to
eliminate erosion by particle-laden air entering the fan.
Because such an installation requires operation under vac-
uum, any leakage in the bin or collection hopper will cause
6-7
-------
reentrainment of particles and will reduce collection effi-
ciency. Leakage into a collection hopper also increases the
danger of fires in the hopper. The gas stream in multiple
cyclones is usually oxygen deficient because it comes from a
combustion process. The hot bits of unburned carbon usually
will burn rapidly if subjected to a stream of fresh air.
Attention should be given also to sealing of inspection
ports.
The rate of removal of material from the hopper must
equal the rate of input to prevent plugging of the hopper
and eventually of the individual cyclones. Inspection ports
or other means of monitoring are usually provided.
A great disadvantage of multiple cyclone systems is
that they are encased in a metal box that prevents regular,
visual inspection of each of the cyclones inside. Because
the material removed from the exhaust gases contains small
amounts of ash and sand, abrasive damage to individual
cyclones is common. A cyclone can be completely eroded
before the operators are aware of its condition. A regular,
visual inspection of each cylone is recommended. Such
inspections are difficult to schedule when the boiler must
be kept in service continuously.
Uneven distribution of gas to multiple cyclones can
decrease their efficiency. Substantial variations in inlet
6-8
-------
pressures within the box will cause improper flow of the
flue gases, a portion of which may flow into the hopper and
back up through some of the cyclone outlets, causing sub-
stantial reentrainment.
The literature contains many theoretical discussions of
fractional size collection by centrifugal collectors. In
operation on wood-fired boilers the inlet and outlet size
distributions apparently do not differ greatly until the
particle size exceeds 5 microns. laen the collector tends
to selectively collect the larger particles. Table 26 gives
data from a test of an experimental centrifugal collector on
a boiler rated at 140,000 pounds of stream per hour. Note
that both the outlet grain loading and the outlet mean
particulate size remained fairly constant over the range of
steam loads tested.
Table 26. EFFICIENCY TESTS OF A CENTRIFUGAL COLLECTOR
Steam load,
Ib/hr
80,000
100,000
130,000
Location
Inlet
Outlet
Inlet
Outlet
Inlet
Outlet
Particulate emission,
grains/scf
0.099
0.080
0.170
0.091
0.213
0.102
Mean size, y
3.87
3.38
6.30
3.51
6.01
3.32
6-9
-------
Wet Scrubbers
One approach to particle control is to trap small
particles on the surface of large particles, such as liquid
droplets, and then collect the large particles. Devices
based on this principle are called scrubbers or wet scrub-
bers, since most use a liquid to capture the particles.
The designer of a scrubber seeks to optimize three
parameters: surface area of the liquid, contact between
particles and liquid, and collection of the liquid.
Surface area of the liquid can be maximized by use of
spray showers (Figure 30), venturi throat (Figure 31),
water curtains, foam materials, and other techniques for
converting the liquid into small droplets. (When one gallon
of water is sprayed into droplets the size of a period, the
surface area increases to about 300 square feet.)
Contact of the particles and the surface of the liquid
is an integral feature of scrubber design. In venturi
scrubbers, the area just downstream from the throat of the
nozzle is extremely turbulent, increasing the probability of
contact. In spray-nozzle systems, increasing the pressure
drop across the nozzle increases the velocity of the drop-
lets formed by the nozzle and promotes their impact upon the
particles in the gas stream. Some scrubbers incorporate
mechanical fans to aid in bringing the liquid into contact
with the particles.
6-10
-------
CLEAN-GAS
OUTLET
DEMISTER
RECIRCULATED
SCRUBBER LIQUID
DIRTY-GAS
INLET
SCRUBBING LIQUID
TO CLARlFlER
Figure 30. A cascading shower scrubber for increasing the
efficiency of removing small particles from gases.
CLEAN-GAS'
OUTLET
VENTURI THROAT
LIQUID
DRAIN
PARTICLE-LADEN
GAS INLET
Figure 31. A venturi scrubber system in which turbulence downstream
from throat increases the contact of particles and liquid droplets.
6-11
-------
Collecting the liquid is relatively easy because of the
size of the liquid droplets. A properly designed cyclone
system works well in conjunction with venturi scrubbers and
spray-shower systems. An enclosed liquid-curtain will keep
all of the liquid in the stream except for the portion that
may go off as a vapor in the exit gas stream.
The liquid used in wet scrubbers is usually water.
When the systems are applied to hogged fuel boilers, the
liquid becomes basic, with a pH in the range of 7.5 to 10.
The scrubbing liquid evaporates because of the heat provided
by the incoming flue gas. This often results in a visible
plume of water vapor.
The efficiency of collecting small particles generally
increases with increasing energy input to the system. The
energy input may be in the form of pressure drop across
liquid spray nozzles, venturi sections, collection cyclones,
or other devices.
Collection efficiencies for wet scrubbers extend over a
wide range. A system designed for use on boilers fired with
hogged fuel, usually operates with overall collection effi-
ciency ranging from 95 to 98 percent by weight. Collection
efficiencies are higher for large particles and lower for
small particles.
6-12
-------
An advantage of wet scrubbers is that they are not
subject to fire damage. If hot sparks carry over to a wet
scrubber, the liguid quenches the fire quickly. The obvious
disadvantage of such systems is that they generate water
pollution. Particles trapped in the scrubbing liquid must
be removed and the liquid recirculated. The solid particles
settle out of the water in a reasonably brief time (about 30
minutes). Thus, a clarifier works well to settle the par-
ticulate. Construction is costly, however, and disposal of
the solids from the clarifier is an associated problem. For
example, a hogged fuel boiler with a capacity of 100,000
pounds per hour may generate 8 to 10 tons per day of solids
in the exhaust gas stream. If this material is collected in
a wet scrubber, the solids from the clarifier will be in the
form of a slurry that is difficult to handle and dispose of.
It is extremely important in designing a wet scrubbing
system to make adequate provision for collection and dis-
posal of the solids.
Corrosion and erosion are potential problems in wet
scrubber systems. Corrosion problems with wet scrubbing
equipment are discussed in detail in Reference 21.
Erosion can be severe in scrubbers and in sludge handl-
ing and removal systems if the particulate ash is abrasive.
For one wet scrubber system, the maintenance-replacement
6-13
-------
schedule for the sludge handling system is about 1 year.
Severe erosion can increase operating costs and reduce
scrubber efficiency.
Farrell and Rippee, reporting on a low-energy wet
scrubbing system installed on a 180,000-pound-per-hour
22
boiler, state that typical outlet emissions run from 0.04
to 0.08 grain per standard cubic foot, with a pressure drop
of only 1/2 to 1 1/2 inches of water. Table 27 summarizes
the boiler emissions.
22
Mick recently reported the problems of Georgia-
Pacific in operating wet scrubbers on wood-fired boilers.
He states that though the plant can meet emission standards
the operational problems may dictate another control system.
Dry Scrubbers
The dry scrubber, a recently developed system, shows
promise in overcoming some of the undesirable features of
the wet scrubber. The dry scrubber utilizes a moving bed of
granular material (called media) as the entrapment material
rather than water droplets. The dirty media is shaken at
the bottom of the unit and the particulate matter falls to a
storage bin. The clean media is removed to a conveyor,
which returns it to the top of the unit. The unit provides
the following advantages:
6-14
-------
Table 27. EMISSIONS FROM BOILER EQUIPPED WITH LOW ENERGY SCRUBBER
22
Date
1971K
1972°
1/15/73
1/15/73
1/25/73
1/25/73
2/6/73
2/6/73
3/19/73
3/19/73
3/20/73
3/20/73
6/5/73
6/5/73
Stack
1
1
North
South
North
South
North
South
North
South
North
South
North
South
Gas
Flow,
ft3/min
121,000
111,000
55,200
58,900
55,200
47,800
59,400
47,100
46,400
56,800
43,400
44,600
54,300
55,200
Moisture,
%
17.1
19.4
16.4
19.7
17.4
19.5
22.5
22.7
23.5
27.2
24.3
22.2
22.6
20.9
Temperature ,
F
404
413
180
182
178
183
174
179
187
179
157
162
178
185
Particulate matter
Loading,
gr/scf
0.51
1.44
0.068
0.068
0.071
0.068
0.054
0.068
0.054
0.059
0.042
0.041
0.077
0.065
Loss,
Ib/day
6,730
15,660
526
535
545
437
419
418
316
408
237
243
547
473
Standard,
Ib/day
1,780
1,896
1,700
1,790
1,945
2,070
2,070
1,890
Inorganic,
%a
54.2
57.6
55.6
57.3
49.0
48.6
57.5
63.9
55.9
58.2
54.6
56.3
60.3
61.6
Inorganic percentage of total particulate matter.
Tests in 1971 and 1972 were before scrubber installation with only one stack.
6-15
-------
1. No water supply is required.
2. No water is discharged, since the particulate is
removed as a dry material.
3. No corrosion occurs; the unit can be made of mild
steel.
4. The scrubber is small. High velocity through the
filter media permits small dimensions and light
weight.
Dry scrubbers are being installed in several locations,
and on some of the largest wood-fired boilers ever con-
structed (500,000 pounds of steam per hour). If they prove
as efficient and trouble-free as preliminary data indicate,
dry scrubbing may be the best available technology.
Extensive test data are available from various boilers
with dry scrubbers. Table 28 reports data for a hogged fuel
power boiler, and Table 29 reports similar data for a power
boiler burning hogged fuel with salt content. Table 30
gives results of a dry scrubber test on a combination
bark/coal-fired boiler; Table 31 gives results of a dry
scrubber test on a combination bark/oil-fired boiler.
Electrostatic Precipitators
Although electrostatic precipitators are used widely to
control particle emissions from combustion sources, they are
rarely used on boilers fired with hogged fuel.
Among the many factors affecting collection efficiency
in these units, an important one is resistivity of the
6-16
-------
Table 28. EFFICIENCY OF DRY SCRUBBER ON HOGGED FUEL BOILER
01
I
Date
1/6/75
1/7/75
1/8/75
1/8/75
Media
size,
in.
1/4 x 1/8
1/4 x 1/8
6-8
6-8
Media
gas
velocity,
f t/min
125
170
150
125
Media
pressure
drop,
in. H20
6
9.3
11.8
9.7
Cyclone
pressure
drop,
in. H2O
1.2
2.0
1.4
1.0
Total loading,
gr/dscf at 12% C02
Cyclone in
2.768
1.486
2.542
4.719
Media in
0.875
0.609
0.800
0.618
Media out
0.075
0.080
0.070
0.026
Collection efficiency, %
Cyclone
68.4
59
68.5
86.9
Media
91.4
86.9
91.3
95.7
Total
97.3
94.6
97.3
99.4
-------
Table 29. EFFICIENCY Of DRY SCRUBBER ON BOILER BURNING
HOGGED FUEL WITH HIGH SALT CONTENT
Date
4/10
4/10
4/14
4/19
4/19
4/21
4/24
Media
gas
velocity,
ft/min
112
114
71
91
75
89
74
Media
pressure
drop,
in. H20
9.5
14.7
9.6
9.7
15.0
12.2
10.0
Cyclone
pressure
drop,
in. H-O
0.5
0.5
0.3
0.4
0.2
0.3
0.3
Total loading,
gr/dscf at 12% CO-
Cyclone in
0.781
0.837
1.089
1.398
0.773
1.264
1.016
Media in
0.431
0.559
0.381
0.403
0.182
0.488
0.297
Media out
0.059
0.070
0.065
0.064
0.024
0.071
0.028
Collection efficiency, %
Cyclone
44.8
33.3
65.0
71.2
76.5
6.14
70.8
Media
86.3
87.5
82.9
84.2
86.8
85.4
90.5
Total
92.5
91.6
94.1
95.5
96.9
94.4
97.3
NaCl
in dust
to media,
%
62.3
63.8
48.9
60.0
44.4
47.6
29.8
Collection
efficiency (NaCl
from media) , %
83.3
86.1
85.5
79.9
85.6
87.4
89.0
(Ti
I
M
CO
-------
Table 30. EFFICIENCY OF DRY SCRUBBER ON BOILER BURNING BARK/COAL FUEL
Date
7/16/75
7/17/75
7/17/75
7/18/75
7/18/75
7/18/75
7/21/75
7/21/75
Pressure drop,
in. H2O
3.0
3.2
4.5
6.6
5.5
4.8
6.1
8.5
Velocity,
ft/min
100
100
125
150
125
100
100
125
Fuel input
Bark,
tons/hr
8.5
18.0
18.0
17.5
17.8
17.8
18.7
18.7
Coal,
M Ib/hr
16.3
19.1
18.5
15.4
16.1
15.1
14.6
15.2
Total,
MM Btu/hr
289
411
403
358
370
357
358
366
Particulate
concentration ,
gr/acf
inlet
0.073
0.150
0.197
0.193
0.191
0.084
0.050
0.185
outlet
0.005
0.007
0.009
0.017
0.010
0.006
0.006
0.007
Scrubber
efficiency,
%
92.5
95.6
95.7
91.0
94.6
92.7
89.2
96.1
Particulate
emissions ,
Ib/MM Btu
Actual
0.035
0.048
0.062
0.118
0.069
0.041
0.041
0.048
Allowed
0.304
0.304
0.304
0.304
0.304
0.304
0.304
0.304
-------
Table 31. EFFICIENCY OF DRY SCRUBBER ON BOILER BURNING BARK/OIL FUEL
Media
6-8
6-8
6-8
6-8
1/4x1/8
1/4x1/8
1/4x1/8
1/4x1/8
1/4x1/8
Pressure drop,
in. H20
9.0
11.3
14.1
11.4
2.8
2.9
4.2
1.8
2.9
Velocity,
ft/min
100
125
150
125
100
100
125
75
100
Fuel input
Bark,
tons/hr
35
45
35
45
28
35
45
46
43
Oil,
M Ib/hr
17.18
14.97
18.09
13.81
20.09
15.32
13.83
12.67
11.65
Total,
MM Btu/hr
614
658
630
637
608
579
636
624
580
Particulate
concentration ,
gr/acf
inlet
0.1125
0.1532
0.1367
0.2099
0.1021
0.1329
0.1642
0.2357
0.1731
outlet
0.0108
0.0248
0.0330
0.0256
0.0297
0.0141
0.0284
0.0446
0.0388
Scrubber
efficiency,
%
90.4
83.8
75.9
87.8
70.9
89.4
82.7
81.1
77.6
Particulate
emissions,
Ib/MM Btu
Actual
0.075
0.162
0.224
0.172
0.209
0.104
0.191
0.306
0.287
Allowed
0.305
0.300
0.303
0.302
0.305
0.308
0.302
0.304
0.308
I
ro
o
-------
particles. Particles with low electrical resistivity, such
as that of carbon, give up the negative charge to the posi-
tive plate and assume a positive charge. Since like charges
are repelled, the carbon particles are pushed away from the
plate and are reentrained in the gas stream. Particles
having high electrical resistivity are unable to give up
their negative eletric charge. As these particles build up
on the collecting plate, they can form an insulating barrier
and even set up a net negative charge. In either case, with
excessively low or high resistivity, precipitator efficiency
is reduced.
Fly ash and unburned carbon from boilers fired with
hogged fuel have low electrical resistivity. The efficiency
of electrostatic precipitators can be increased if the
particles are conditioned by injection of a material that
alters resistivity to a more appropriate operating range.
Sulfuric acid mist is sometimes used in some instances to
accomplish this, but can in turn cause corrosion and in-
crease the potential for environmental pollution.
Another way of overcoming the low resistivity of par-
ticulate from wood-fired boilers is to operate the precipi-
tator at high current levels. In practice, because of the
great variability of the particulate leaving the wood-fired
boiler, the precipitator must be capable of operating at
high current levels even though it may be operated at normal
levels most of the time.
6-21
-------
23
Betchley reported in 1973 that only two power boilers
at paper mills were equipped with electrostatic precipita-
tors for particulate control. Both used multiple cyclone
primary collectors and both were fired with coal and bark.
The clue to successful operation of these units was probably
the use of coal as primary fuel. The precipitator was
designed to accommodate the coal, which is a more consistent
fuel than wood residue. The sulfur in the coal also aided
the operation of the precipitator. It is important to note
that coal was the primary fuel and that less than 50 percent
of the heat input was from wood.
Table 32 lists all combination-fuel-fired power boilers
24
at paper plants in the United States. The four boilers
fired by coal-oil-bark/wood use coal in proportions of 66,
80, 76, and 75 percent. The corresponding wood energy
inputs to these systems are 16, 7, 23, and 25 percent,
respectively. The table also indicates that emissions from
the power boilers fired with wood residue and coal are
relatively high (0.17 to 1.2 grains per dry scf); so equipped,
these boilers would have difficulty meeting most emission
standards in force today.
Electrostatic precipitators are large and are costly to
install. The combustion of high capital cost and potential
for low efficiency has resulted in their limited use for
control of emissions from boilers fired with hogged fuel.
6-22
-------
Table 32. EMISSION DATA FROM POWER BOILERS FIRED WITH BARK/WOOD PLUS OTHER FUELS
24
Mill
number
031
048
072
096
107
113
144
183
185
191
217
218
219
253
260
292
272
026
205
284
Average
Total
toiler
number
7
4
1
1
3
1
21
4
5
7
3
3
4
5
3
2
3
1
11
12
3
7-8
BB
2
3
4
Collector rating
Pressure drop,
in. H~0
2
2.8
2.5
2.5
2.5
4.8
3
3
3
2.5
3.6
3.0
3
3
2.5
3
2.8
0.2
3
4
0.6
2.1
Efficiency,
%
90
88
92
92
92
93
90
90
92
80
93
82
82
93
95
95
90
84
84
75
84
97
96
96
89
Percent of fuel
supplied, Btu basis
a
B/Wa
75
51
68
16
7
23
25
73
82
44
35
98
64
57
31
100
37
28
39
41
100
25
44
30
30
40
48.5
Oil
25
59
32
18
13
1
0
27
18
65
2
36
43
0
0
63
38
18
20
0
75
56
70
70
60
31
Gas
0
0
0
0
0
0
0
0
0
46
0
0
0
0
69
0
0
34
43
39
0
0
0
0
0
0
9.2
Coal
0
0
0
66
80
76
75
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
11.3
B/Wa
t/day
200
384
450
30
31
136
200
205
305
26
65
165
250
250
360
145
215
370
765
815
70
400
500
120
120
750
7337
Fly ash
reinjection
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
No
No
Gas flow
rate,
103 dscfm
83
55
51
51
91
123
76
56
57
48
50
131
40
50
153
187
156
19
198
60
35.5
58
172
84
Particulate
concentration,
gr/dscf
Inlet
9.90
0.59
2.3
0.90
2.11
3.01
1.7
1.83
2.10
1.4
4.3
2.74
Outlet
0.81
0.14
0.12
1.1
1.2
0.18
0.17
0.51
0.30
0.16
0.43
0.32
0.44
0.35
0.18
0.37
0.10
0.13
0.30
0.51
0.4
0.6
0.94
0.52
0.93
0.4
0.45
Collection
efficiency,
%
92
80
93
64
79
88
92
84
76
71
90
83
Emission
rate,
Ib/hr
402
100
57
480
528
140
180
104
209
156
183
150
202
127
43
171
482
682
65
1020
488
158
463
588
299
7177
\
NJ
CO
Bark and wood wastes.
-------
Baghouses
Baghouse filters are not used extensively on boilers
fired with hogged fuel, largely because of fire hazard. The
baghouse is a container housing cylindrical bags made of
cloth. The particle-laden airstream enters the bags from
the bottom. As the gas passes through the bags, the par-
ticles are trapped on the inside surface. The trapped
particles are removed by various methods, such as shaking,
reversing the gas flow, and impinging a high-velocity jet of
air at regular intervals. In each system the goal is to
make the trapped particles fall from the bag into a collec-
tion hopper.
Baghouse filters are extremely efficient, even for fine
(submicron) particles, with collection efficiencies commonly
greater than 99 percent. They do not require a great deal
of energy to operate. Pressure drops are normally less than
10 inches of water. Because they do not use liquid, there
is no visible plume and no water cleanup problem.
The disadvantages, however, may outweigh these advan-
tages. The bags are temperature-limited, with an upper
limit of about 600°F for most commercially available mate-
rials. A small fire in the ash collection hopper or a
glowing ember in the flue gas, could cause extensive damage
to a baghouse. If the baghouse is located downstream from
6-24
-------
an efficient multiple-cyclone collector, however, the com-
bustible content of the captured material generally is too
low to support combustion.
The potential for fire damage is the most critical
disadvantage. Others must be considered, however. For
example, baghouse life is limited by wear. The constant
flexing or shaking action to remove collected particles
reduces normal bag life to 18 to 24 months, leading to high
maintenance costs. Further, baghouses are generally large
structures, and many plants do not have adequate space for
this type of installation. Baghouses must be fully insulated
to prevent condensation inside the bags or on cool surfaces.
This is particularly important where sulfur-bearing auxil-
iary fuels are burned. Finally, the initial capital cost of
a baghouse installation is high relative to costs of alter-
native control systems.
One wood-fired boiler at Spokane, Washington, has been
operating with Nomex bags with an air-to-cloth ratio of 4.1
acfm per square foot of fabric. Extensive tests were run on
this boiler. The results have not yet been published but
were obtained by private communication.
The boiler operated at a rate of approximately 30,000
Ib/hr for all tests. Flue gas from the breaching of the
boiler traveled through a baffled settling chamber 20 feet
6-25
-------
high by 8 feet in diameter, then through an induced draft
fan, and 120 feet of 33-inch diameter ducting (to cool the
gas stream). It then passed through a cyclone with a settl-
ing chamber, and an expanded-metal type spark arrester, and
finally to the baghouse, followed by a second induced-draft
fan and a dampered stack.
The inlet samples were collected after the cyclone but
ahead of the spark arrester. The outlet samples were col-
lected from a port located in the duct between the baghouse
exit and the last induced-draft fan. Table 33 gives the
results of this test series. Note that the grain loadings
were not corrected to 12 percent CO^ because of an Orsat
instrument problem. Test observers believe that the excess
air during the test was within normal operating ranges.
Other Control Devices
Many devices and combination systems now under develop-
ment show promise for control of emissions to varying de-
grees. One of these is the Becker Sand Filter, which is an
adaption of a water filtration system. The dirty gas stream
enters the top of the unit and passes downward through a
wetted sand bed. Water is continually sprayed onto the sand
from the top. The cleaned gas is separated from the water
as it leaves the bottom of the sand bed. The key to success-
ful operation of the system is that the sand is uniformly
6-26
-------
Table 33. TESTS OF A HOGGED FUEL BOILER EQUIPPED WITH NOMEX FILTERS
Test
no.
1
2
3
4
5
6
7
Date
1/7/75
1/8/75
1/8/75
1/8/75
1/9/77
1/9/75
1/9/75
Test
location
Outlet
Outlet
Outlet
Inlet
Inlet
Inlet
Outlet
Particulate
concentration
(105°)
gr/acf
0.0041
0.0017
0.0022
0.6609
0.7910
0.6035
0.0035
gr/dscf
0.0073
0.0030
0.0040
1.4354
1.6459
1.2289
0.0066
Stack
temp.
oF
278
293
293
410
413
413
328
Moisture
in
fuel , %
14.78
14.85
15.07
18.59
14.73
12.86
15.57
Average
velocity
(wet basis) ,
ft/sec
58.7
57.1
57.2
59.2
60.7
60.7
57.7
Gas flow,
acfm
13,148
12,792
12,799
21,097
21,625
21,625
12,915
Gas flow,
dscf
7,470
7,118
7,103
9,713
10,392
10,620
6,808
I
to
-------
graded. The device is expensive to operate because of the
pressure drop (12 to 15 inches of water). Problems with
water supply and water clean-up are similar to those of a
wet scrubber.
Systems incorporating moving bed filters, wetted elec-
trostatic precipitators, precoated bags in baghouses, and
several other concepts may see future use.
Combination Devices
A single control device seldom provides adequate con-
trol of a wood-fired boiler. When control is limited to a
cyclone or multiple cyclone, emissions probably exceed
regulations. If a cyclone or multiple cyclone is not used
ahead of a baghouse or scrubber, the inlet loading may be so
high that the device is overloaded. Failure of some dry
scrubber systems to meet environmental regulations has
recently been reported. Since these dry scrubbers were used
without inertial precleaners, it is conceivable that the
friable particulate matter entering the scrubber was being
crushed in the scrubber and emitted as very fine particu-
late. Installation of multiple cyclones ahead of the dry
scrubbers might cure the problem. Change of the scrubber
medium may be another solution.
The generally accepted primary cleaner is the multiple
cyclone. For stringent control the cyclone may be followed
6-28
-------
with a wet scrubber, a dry scrubber, a baghouse, or an
electrostatic precipitator (for combination coal burners).
Table 34 summarizes the information now available on
control devices for wood-fired boilers. These data describe
current installations. For any proposed installation on a
wood-fired boiler, the costs and design data must be de-
veloped by a qualified engineer.
OPERATOR TRAINING
Proper boiler operation is often overlooked as a means
of controlling particulate emissions, even though emissions
from a boiler that is operated poorly can be 10 times as
great as those from the same boiler when it is operated
properly. The difference is in the knowledge, skill, and
diligence of the person firing the boiler. In preparation
for placing a boiler in operation, the engineer who designs
the boiler and related systems must be licensed, the manu-
facturer and contractor must be bonded and required to
guarantee their work, and the boiler inspector must be
licensed. In practice, this boiler can then be turned over
to a fireman or stationary engineer who has received no
training at all or to one having years of theoretical and
practical experience. A great deal is at stake: energy
conservation, air pollution control, plant safety, and
efficient, uninterrupted plant operation. The boiler opera-
tor, therefore, must be the best available.
6-29
-------
Table 34. PROPERTIES OF PARTICULATE COLLECTORS ON WOOD-FIRED BOILERS'
Collector type
Single cyclone
Multiple cyclone
Wet scrubber
Venturi scrubber
Dry scrubber
Baghouse
Multiple cyclone plus
scrubber
Multiple cyclone plus
ESP
Multiple cyclone plus
dry scrubber
Multiple cyclone plus
baghouse
Costb
$/100 acfm
50
150
180
150
150
200
300
400
300
350
Power req'd.
HP/ 1000 acfm
0.7
1.0
1.7
3.0
1.5
1.7
3.0
1.5
2.5
2.7
Pressure drop,
in. H20
1.0 to 2.0
1.5 to 3.0
3.0 to 8.0
15 to 30
5.0
3.0
8.0
2.0
7.0
5.0
Temp.
limit,
°F
1000
1000
1000
1000
1000
500
1000
1000
1000
500
Expected
performance
Effic.,
%
80
90
95
95
95
99
99
99.5
99
99.5
Loading,
gr/scf
0.4
0.2
0.1
0.1
0.1
0.005
0.05
0.01
0.05
0.001
Disposal of collected
particulate
Dry: landfill or
charcoal
Dry: landfill or
charcoal
Wet: landfill or
settling pond
Wet: landfill or
settling pond
Dry: landfill or
charcoal
Dry: landfill or
charcoal
Wet: landfill or
settling pond
Dry: landfill or
charcoal
Dry: landfill or
charcoal
Dry: landfill or
charcoal
Remarks
Collected material light
and hard to handle
Collected material light
and hard to handle
Slurry difficult to handle;
10 gpm of water needed;
visible plume
Erosion may be severe;
other properties same as
wet scrubber
Small, lightweight
Ultraclean; fire hazard
Dry material; water required
Very expensive; ultraclean
Still small and lightweight
Expensive; ultraclean; fire
hazard
I
OJ
o
a Boiler capacity approximately 100,000 Ib steam per hour.
Does not include ductwork or fans. For new installations add 50 percent; for retrofit installations add 75 percent.
-------
Certification of boiler operators, based on both theo-
retical and practical examinations, would be desirable.
State and local agencies could require such examinations and
could establish a required level of experience for "journey-
men," the only persons eligible to be in charge of a boiler
facility. Many companies are currently doing this inter-
nally with both formal and on-the-job training.
Formal Courses
Formal training for boiler operators consists of lec-
tures, visual aids, problems, examinations, and field trips.
Junge has successfully developed such a course, which he has
Q
presented several times on the West Coast. His manual is
an excellent guide for the student. This course has been
sponsored by local community colleges, by groups of lumber
industries, and by individual firms.
On-the-Job Training
Training on the job is best done by an individual
company or utility. Experienced operators can provide
practical training for new employees in operation of boilers
and other equipment, perhaps using written or oral tests in
Q
conjunction with the work experience. Junge's manual would
be a valuable aid in such a program. The employer can award
certificates for this type of training, as is done upon
completion of a formal course. Structured on-the-job train-
6-31
-------
ing programs have been conducted successfully in other
trades for years.
INSTRUMENTATION
Proper boiler operation requires adequate, accurate
instrumentation. A boiler operator should not be expected
to operate within the limits required by air quality stan-
dards without instrumentation to indicate how the boiler is
operating. The principal types of instruments required are
those that monitor combustion, emissions, and opacity.
Combustion Instrumentation
Combustion instrumentation, such as oxygen analyzers
and temperature indicators, should be considered as impor-
tant boiler components. The oxygen analyzer, for example,
may signal a potential malfunction. A boiler operating with
twice as much excess air as the optimum not only will under-
go high gas velocity through the system but will suffer an
additional penalty when the particulate emission is adjusted
back to 12 percent C0» equivalent. The operator must be
aware of the ways in which combustion and particulate emis-
sions are affected by the situation the instruments are
indicating. Some especially critical instruments, such as
oxygen recorders, are often connected to an alarm that gives
an audio or visual signal when prescribed operating limits
are exceeded.
6-32
-------
All persons concerned with boiler operation should know
the procedure for calibration of oxygen or carbon dioxide on
a dry gas basis, whereas the boiler instrumentation may
report the same component as a percentage of the wet gas.
For example, if the flue gas is composed of the following
hypothetical percentages of gases:
Nitrogen 68
Carbon dioxide 10
Oxygen 7
Water 15
100%
the analysis on a dry basis (as indicated by an Orsat in-
strument) would be:
Nitrogen 80.0
Carbon dioxide 11.8
Oxygen 8.2
100.0%
The differences in these values are significant in terms of
combustion and particulate emissions.
Emission Instrumentation
Emission instrumentation is designed to indicate
whether boiler emissions are within the regulation limits or
are exceeding them. At present, few control agencies will
allow the substitution of emission instrument records for
stack tests or visual opacity readings to determine compliance,
6-33
-------
Opacity Instrumentation
Opacity monitors installed in breeching or stacks,
after all control devices, give the operator a good indi-
cation of the amount of particulate emitted to the atmo-
sphere. These monitors are particularly useful if their
readings have been correlated with values determined in
stack emission tests or visual opacity readings. These
instruments range from indicating "smoke meters" costing
approximately $1,000 to recording, self-calibrating opacity
meters costing nearly $10,000.
Equipping the opacity meter with a visual or audible
alarm will let the operator know when limits are being
exceeded. Such an alarm immediately signals that a change
must be made in the boiler operation to bring the emissions
within the prescribed range.
Use of a recording opacity meter along with other
recording combustion instruments (fuel flow, air flow, steam
flow, temperature, draft, etc.) will provide a permanent
record, which can be analyzed to determine the optimum
firing conditions for various situations. Such a record
also can aid the engineering supervisors in determining how
well the boiler is being operated and what maintenance may
be necessary.
6-34
-------
TV Stack Monitors
Closed-circuit television systems have been installed
in many plants for visual monitoring of stack emissions.
The stack monitor provides a continuous display of plume
visibility. Although this indicator is useful during day-
light, it is of little value at night unless the plume from
the stack is well lighted. The advantages of this system is
that the operator can observe the stack emissions without
leaving the boiler control panel. The main disadvantage is
that the operator must constantly observe the monitor.
MAINTENANCE AND OPERATION
Controlling the combustion process requires a substan-
tial amount of complicated equipment. The following systems
are needed to achieve high efficiency of operation and low
levels of pollutant emission:
0 Equipment for fuel sizing, drying, mixing, stor-
age, and feeding, with special provisions for
firing sanderdust, cinders, and auxiliary fuel.
0 A grate system with provisions for ash removal.
0 An air system with forced-draft and induced-draft
fans, dampers> damper positioners, and controls.
0 An air-preheater system.
0 Pollution control devices to remove particles from
the flue gas.
0 Monitoring equipment to provide information for
control of excess air.
6-35
-------
0 A heat exchanger system, equipped with soot
blowers to prevent ash buildup in the gas passage.
Without proper maintenance, the various parts of these
essential systems soon will fail to perform their intended
functions. Many maintenance needs are obvious. For ex-
ample, it is readily apparent that sliding surfaces need
regular lubrication; without it, they will eventually stop
sliding or be severely damaged. Other maintenance needs are
not so obvious. For boilers fired with hogged fuels, two
are of particular concern: maintenance of the boiler con-
trol systems and maintenance to prevent leakage of air into
the system.
Most boiler control systems have pneumatic controls
that are operated with compressed air at low airflow rates.
Problems arise because of contamination of the compressed
air. Lubricating oil and condensed water collect in the air
lines, plugging the lines and coating the controls with a
gummy, sticky substance. As an indication of the magnitude
of the problem, consider that a control system with air
flowing at 1 cubic foot per minute through control lines,
uses over 500,000 cubic feet of air a year. If the com-
pressor is equipped with an aftercooler to remove 90 percent
of the entrained water, 5 gallons of water may still con-
dense in the lines each year. Mixed with cylinder lubri-
cating oil, this water forms a coating that can make a
control system inoperative in 1 to 2 years.
6-36
-------
Two corrective measures are recommended. First is
installation of a refrigerating and filtering system to
remove the impurities. Second is regular cleaning and
recalibration of the boiler controls by a competent instru-
ment technician. Major cleaning and recalibrating should be
done at least every 2 years. This service is available from
reputable contractors if it is not readily available in-
house.
Maintenance to prevent inleakage of air is critical in
efficient operation. Any uncontrolled airflow into the
process results in some loss of control of the process.
Because most furnaces and emission control devices are
operated under slightly negative pressures, any opening in
the system causes air to enter. Typical openings causing
inleakage are inspection ports, cracks in the furnace casing
or setting, cleanout doors, openings around soot blowers,
cracks in breaching and fan casings, and fuel chutes, which
can allow passage of large airflows. These various uncon-
trolled sources of air should be sealed tightly.
An important part of maintenance of the furnace-boiler
is prompt, scheduled removal of accumulated ash from the
grates and ashpit. Data recently obtained on two similar
18
Dutch oven boilers indicate the emission problems created
by excessive ash buildup within the firebox.
6-37
-------
In boiler number 1 at the University of Oregon heating
plant ash was allowed to accumulate for several days within
the Dutch oven furnace, building to a depth of 2 or 3 feet
on top of the grates. In contrast, boiler number 3, a
similar furnace operating at the same steam load, was
cleaned the day before an emission test and no ash buildup
on the grates was apparent. The test showed that boiler
number 1 was emitting 0.245 grain per scf corrected to 12
percent C0» while boiler number 3 was emitting 0.118 grain
per scf. At an allowable emission limit of 0.20 grain per
scf, the ash buildup caused enough additional particulate
emission to prevent boiler number 1 from complying with the
regulations.
Schedules
The problem of ash buildup can be controlled by setting
a reasonable schedule for cleaning and then adhering to the
schedule. A competent engineer can observe the operation
over a sufficient period of time to determine an optimum
schedule for raking of the ash. This schedule should be
posted in the boiler house and operators should initial it
after he performs each cleaning.
In a plant with multiple boilers, the scheduling can be
done to minimize plant upset and spread the workload. For
example, the following schedule could apply when four simi-
6-38
-------
lar boilers are used for steam generation with three on the
line and one kept cold but on standby:
ASH CLEANING SCHEDULE
With two odd-numbered boilers and one even-numbered
boiler on the line - Clean odd-numbered boilers on odd-
numbered days, lower number at 0300 and higher number
at 0500. Clean even-numbered boiler on even-numbered
days at 0400.
With one odd-numbered boiler and two even-numbered
boilers on the line - Clean odd-numbered boiler on odd-
numbered days at 0300. Clean even-numbered boilers on
even-numbered days, the lower number at 0200 and the
higher number at 0400.
With this schedule all boiler ash cleaning would be
completed between 0200 and 0600, which is assumed to be the
period of lightest load on the plant. It also staggers the
cleaning to maintain at least two boilers on the line.
Soot blowing is another operation that must be sche-
duled. Soot can be blown in compliance with regulations if
the excess opacity does not exceed a specified time period,
such as 2 minutes in any one hour. Any soot blowing during
daylight hours, however, especially on a sunny day, may
elicit complaints even though it is done in compliance with
the letter of the regulations.
Maintenance operations around the boiler plant can
either be scheduled (routine) or unscheduled (upset). Any
scheduled plant shutdown, such as for a week at Christmas,
is the time to perform major boiler repairs or changes.
6-39
-------
This of course would require scheduling with the affected
plant personnel as well as suppliers and contractors.
Written Logs
The boiler operator should maintain a written log on
which he notes and initials routine readings and separately
indicates nonroutine or upset readings. This written log
should be checked regularly by the engineer in charge or
other responsible person. If an operator learns that no
attention is given to his entries in the log, he may rapidly
become lax in his record keeping.
Charts and Recordings
The filing and storage of all the charts and recordings
from a modern boiler plant can rapidly become a problem if
space is limited. Such records usually are only for inter-
nal use by operators and engineers concerned with the
boiler. Normally, a 30-day storage period is probably
adequate. Persons interested in the operation should be
able to get information from the charts within this time
period.
If an engineer wishes to conduct a long-term study, he
should request that pertinent data from the charts of inter-
est be recorded on data sheets for his use. The values
indicated on charts and recordings must be converted to
digital data, either manually or by data-logging systems,
6-40
-------
before they can be of use in engineering or statistical
studies.
REGULATORY ASPECTS OF WOOD-FIRED BOILER OPERATION
Control of emissions from wood-fired boilers requires a
knowledge of the fuel, the boiler, the available control
equipment, and the applicable regulations. As mentioned
earlier, emission regulations can take many forms. Several
state and regional regulations are based on a process weight
chart or emission table, which specifies the maximum allow-
able emission in pounds of particulate per million Btu of
heat input. The pounds of particulate emitted may be ob-
tained in a stack test. Determining the heat input to the
system may be more difficult, particularly if the wood is
fired concurrently with oil, gas, or coal.
Even if wood is the only fuel fired, the estimation of
heat input is difficult. Seldom is the wood fuel weighed as
it is fired. Also, since the moisture content of wood is
usually both high and variable, it is difficult to arrive at
a reasonable value for gross heat input. The problems of
estimating heat input and the recommended method of deter-
mination are described in a recent publication from the
National Council of the Paper Industry for Air and Stream
25
Improvement. This report covers the matter so thoroughly
that it is included in its entirety as Appendix C.
6-41
-------
Current Regulations
The regulations governing particulate emissions from
wood-fired boilers vary among states and regions. These
regulations are summarized in Table 35.
Examination of the regulations and their wording indi-
cates many points for concern and discussion. For example,
assume the following for simplification:
1000 Btu input = 1 pound of steam
or
1 million Btu per hour = 1000 pound of steam per hour
1 pound of dry fuel produces 10,000 Btu
1 pound of dry fuel produces 87 dscf at 0 percent
excess air
1 pound of dry fuel produces 122 dscf at 50 percent
excess air
68 percent excess air corresponds to 12 percent CO^ .
Suppose a boiler is steaming at 60,000 pounds of steam
per hour and the particulate emission is measured at 0.10
grain per dscf corrected to 12 percent CO- :
/-A AAA lt> steam 1,000 Btu input ,„ •-,-,• „.
60,000 - r- - x — '- — ^-r- — r - - — = 60 million Btu
hr ib steam ,
per hour
c.r\ AAA nnn Btu lb fuel , nnr. Ib fuel
60,000,000 gp- x 10fQOO Btu = 6,000 -^ -
6 non lb fuel x 122 dscf = 732 000 dscf
6,000 x L2.2. 732,000
0.10 grain Ib dscf
X g
lb Part-
dscf X 7,000 grains X /J^'UUU hr
6-42
-------
Table 35. SUMMARY OF REGULATIONS FOR WOOD-FIRED BOILERS
(Ti
I
^
OJ
O
CO
State
or
county
Alabama 1
Alabama 2
Alaska
Arizona
Arkansas
Calif., Kern Co.
Calif.. Kern Co.
Calif.. La. Co.
Calif., Bay Area
Connecticut
Delaware
District of Columbia
Florida. OaOe Co.
Florida
Georgia
Hawaii
Idaho
Illinois, Chicago
Illinois. Other
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Ml i sour 1
No.. Springfield
Green Co.
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New Vork
New Vork City
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pa. Allegheny Co.
City of Philadelphia
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
West Virginia
Wise. Milwaukee Co.
Washington
Wyoming
Date
of
reg.
or
Rec'd.
5/75
5/75
7/72
5/76
7/73
7/74
7/74
1/72
5/70
5/74
5/75
3/74
5/75
4/75
5/75
5/75
5/75
5/75
5/75
11/74
5/75
1/72
5/75
5/75
5/75
5/75
3/74
5/75
5/75
5/75
4/71
3/74
5/74
6/75
5/75
3/74
1/74
5/75
5/74
5/74
1/-71
5/74
5/74
6/70
3/74
5/75
5/75
5/75
5/75
5/75
5/75
1/72
5/75
5/75
5/74
5/75
6/75
gr/dscf at 121 CO,
Old
O.I5b'c
•. ib,c
). It *
0.3°'c
0.15°
(Area 11)
0.2"
D.30T
0.02-0.10TiC
0.2C
0.20C
New
Max 10 Ib/hr
EPA std
Max 10 Ib/hr
0.03-0.05
O.lc
0.10°
Opacity, I
Old
20b
20b
.
4fl"
30
40
20b
4u
40
40
20"
40
40
20b
40
New
30
20
20
20
20
20
20
20
Opacity-sec.
exemption, sK/fcr
Old
180/hr"
N.S.
180/hr"
120/hr
180/hr
180/hrb
260/hr?
MO/hr11
360/hr
360/hr
180/hrb
300/hr
300/hr"
900/8 hr
New
120/hr
120/hr
180/hr
360/hr
360/hr
300/hr
120/hr
lb/106 Btu
Old
0.12-0.50b
0.12-0.80
0.025-0.599"
0.20
0.3° h
0.02-0.13
0.3
0.24-0.7
0.12-0.6
0.2
0.1-1.0
0.8
0.6-0.8 h
0.12-0.60
0.11-0.80
0.6°
0.12-0.60
0.15
0.4-0.6b
0.18-0.6h
0.12-0.6"
0.2-0.6 h
0.15-0.6 h
0.044-1.08°
0.19-0.60
0.1-0.6
0.6 h
0.09-0.40?
0.15-0.70
0.80 h
0.1-0.6°
0.6
0.08-0.40"
0.6-0.8
0.30°
0.1-0.6
0.1-0.3b
0.1-0.5b h
0.05-0.34?
0.10-0.60
0.1-0. 30 h
0.18-0.60
New
0.12-0.50
0.10
0.2
0.1-0.5
0.12-0.6
0.1
0.1
0.6
0.6
0.10-0.56
0.3-0.6
0.10
0.10-0.6
0.12-0.6
0.12-0.60
0.136-0.600
0.180-0.600
0.10-0.60
0.02-0.6
0.1-0.6
Ib/ton process wt.
Old
0.093-11. 2b
0.138-11.0
0.093-14.4"
0.093-14.4"
1.333-8.24"
1.33 -9.60 h
1.33 -11.02"
h
1.33 -9.60"
1.33 -11.02
New
0.093-11.2
(10 Ib/hr max)
(40 Ib/hr max)
0.060-8.00
a
1.33-11.2
Old/ new
date
None
Stated
N.S.
N.S.
N.S.
8/71
8/71
1/73
N.S.
N.S.
N.S.
7/74
1/72
N.S.
11/74
N.S.
N.S.
4/72
N.S.
1/72
3/74
N.S.
N.S.
N.S.
4/71
N.S.
N.S.
N.S.
N.S.
2/72
N.S.
N.S.
1/72
N.S.
N.S.
N.S.
N.S.
6/70
3/74
N.S.
5/69
2/71
N.S.
7/75
N.S.
N.S.
N.S.
N.S.
7/75
Other standards; notes
Ilass 1 county - 501 * urban
Class 2 county - 501 * rural
wood waste special reg.
Based on higher heat value
100 Ib/hr max allowable
Valley basin
Desert basin
0.020-0.100 gr/scf may be subst.
Btu from mfg. maximum
Btu from mfg. maximum
Btu determination N.S.
f.
Stds for 30x10 Btu/hr plus
All sources after 1/73
Btu from heat content
All sources new
After 6/75
0.1 lb/106 8tu, Chicago and Indianapolis areas
Btu from mfg. maximum
Btu from heat input
All sources new after 6/75
991 efficiency dust coll. rqd.
0.5 Ib particulate/lDOO Ib gas
Fossil fuel regulations
Btu from mfg. maximum
Btu from heat input
8tu from heat input
Btu from mfg. maximum
Btu from heat input
Btu from heat input
Heat input 9 normal operat.
8000 Btu dry pound
Btu from heat input
Btu from heat input
Btu from capacity rating
Btu from heat input
(Old) 0.2 It)/ 103 Ib gas, (New) 0.1 lb/103
Btu front capacity rating
Btu from mfg. maximum
Btu from heat input
Fossil fuel regulations
Minimum 851 control
Btu from heat input
Btu from total design input
Btu input to stack
Btu input
Btu input
* When range of values is given, emissions are from tables 1n regulations.
" Old or new boiler not stated.
c Wet or dry scf not stated.
-------
in 5 lb Part- x hr = o 175 lb Part'
-LU.O hr go minion Btu U.J./3 minion Btu
in * lb Part. hr 2,000 lb
U>D lb 6,000 lb fuel ton
=35 lb par t .
ton fuel
The particulate emission from this boiler may be ex-
pressed in several ways:
M \ n i n grain _ n OOQ gram
(±; 0.10 ^ -f— = 0.229 —=-^ —
dscf sdc meter
(2) 10.5 2°i^
hour
0 175 P°und
u.i/b million Btu
4) 3 5 P°unds
' J* ton of fuel
Figure 32 shows these values superimposed on process
weight charts for the States of Vermont and Missouri. This
unit would be operating just in compliance in Vermont. In
Missouri it could be emitting twice as much particulate and
still be in compliance with standards for new boilers. If
the boiler were classed as an "existing" boiler in Missouri,
it could be emitting 0.25 grain per dscf and still be in
compliance.
Figure 33 shows tha data from Table 15 and Figure 28
(assumed for 60,000 pounds of steam per hour boilers) super-
6-44
-------
STATE OF VERMONT
CO CQ
HH
z; -z.
LU O
I—I
LU
o oo
•-H Q
C£. ZD
< O
CL O.
1.00
0.50
0.40
0.30.
0.20
« 0-10
0.05
0.04
0.03
0.02
0.01
1
1.0 10.0 100.0 1000.0
TOTAL ENERGY INPUT MILLIONS OF BTU'S/HOUR
STATE OF MISSOURI
MAXIMUM ALLOWABLE PARTICULATE EMISSION
POUNDS PARTICULATE PER MILLION BTU HEAT INPUT
0.10
5 10 50 100 1,000 10,000 30,000
TOTAL HEAT INPUT - MILLIONS OF BTU PER HOUR
LIMITATIONS ON EMISSION OF PARTICULATE MATTER FROM
FUEL BURNING INSTALLATIONS
Figure 32. Process weight charts.
6-45
-------
STATE OF VERMONT
zoo
CD-
GO I—
OO CQ
LU O
c_> oo
i— i Q
< o
Q- Q-
1 . UU
0.50
0.40
0.30
0.20
0.10
0.05
0.04
0.03
0.02
n.oi
1
: ^
-
1
J
-90%
-75%
-50%
^\27%
i no/ ^**^
-
1
1.0 10.0 100.0 1000.0
TOTAL ENERGY INPUT MILLIONS OF BTU'S/HOUR
STATE OF MISSOURI
MAXIMUM ALLOWABLE PARTICULATE EMISSION
POUNDS PARTICULATE PER MILLION BTU HEAT INPUT
0.10
5 10 50 100 1,000 10,000 30,000
TOTAL HEAT INPUT - MILLIONS OF BTU PER HOUR
LIMITATIONS ON EMISSION OF PARTICULATE MATTER FROM
FUEL BURNING INSTALLATIONS
Figure 33. 135 Oregon and Washington boiler tests on
two process weight charts.
6-46
-------
imposed on the Vermont and Missouri process weight charts.
Had these boilers been operating in Vermont, 42 percent
would have been in compliance. In Missouri, 71 percent
would have met the standard for new boilers and 82 percent
would have been in compliance as existing boilers.
Regulations based on such process weight charts could
give rise to another type of situation. Suppose the owners
of a major forest products manufacturing complex wish to
convert from oil or gas firing to wood firing. They calcu-
late their steam demand as follows:
1. Sawmill dry kiln: 30,000 pounds/hr.
2. Plywood veneer dryer: 30,000 pounds/hr.
3. Particle board plant dryer: 30,000 pounds/hr.
Should they construct a 30,000-pound-per-hour boiler at
each facility or a single 90,000-pound-per-hour boiler? In
favor of one large boiler are the lower capital cost, lower
operating cost for labor, fuel handling, etc., and the
potential for using different boilers or furnaces to obtain
maximum efficiency.
Examination of the process weight charts shows another
point that the owners must consider. Figure 34 shows the
two charts pertaining to Vermont and Missouri. The allow-
able emission values are shown in Table 36. Only the values
for a new boiler in Missouri are shown.
6-47
-------
STATE OF VERMONT
z: oo
o -
"-i ID
oo t-
oo co
UJ O
O t/}
I—l Q
i .00
0.50
0.40
0.30
0.20
0.10
0.05
0.03
0.02
0.01
1.0 10.0 100.0 1000.0
TOTAL ENERGY INPUT MILLIONS OF BTU'S/HOUR
STATE OF MISSOURI
MAXIMUM ALLOWABLE PARTICULATE EMISSION
POUNDS PARTICULATE PER MILLION BTU HEAT INPUT
0.10
5 10 50 100 1,000 10,000 30,000
TOTAL HEAT INPUT - MILLIONS OF BTU PER HOUR
LIMITATIONS ON EMISSION OF PARTICULATE MATTER FROM
FUEL BURNING INSTALLATIONS
Figure 34. 30 and 90 million Btu/hour allowable emissions
6-48
-------
Table 36. ALLOWABLE PARTICULATE EMISSIONS FROM
BOILERS IN VERMONT AND MISSOURI
Design
3-30,000 Ib/hr
1-90,000 Ib/hr
Vermont
lb/106 Btu
0.300
0.175
gr/scf
0.17
0.10
Ib/hr
27
16
Missouri
lb/106 Btu
0.43
0.30
gr/scf
0.25
0.17
Ib/hr
39
27
CTi
I
-------
Inspection and Enforcement
The air pollution control inspector assigned to plants
that operate wood-fired boilers should be thoroughly famil-
iar with wood fuels, furnaces, and boilers. He must realize
the differences and similarities among these and other types
of boilers and control equipment. The use of standardized
permits, forms, and records, will aid the inspector in his
duties and is recommended.
Standard Forms
The Oregon-Washington wood-fired-boiler committee
composed of representatives of industry, control agencies,
and educational institutions has developed several forms for
2 fi
boiler classification, inspection, source tests, etc.
Agencies may wish to adopt this material as a basis for
their own forms.
Standard forms should be required for reporting of
source tests, since they are ameanable to computerization
and tabulation of results. If all the states and regions
were to adopt a uniform standard report form, this would
facilitate reporting by the companies that operate in a
number of states and regions.
Required Records and Charts
Company charts and records should be available for
inspection by control agencies. It was recommended earlier
6-50
-------
that the original charts be retained for 30 days. If an
agency wishes further information (such as hourly opacity
readings for a year) they should arrange with the facility
operator to determine who is responsible for transcribing
the chart data to other forms and records.
It is suggested that control agencies cross-reference
their reports and records pertaining to wood-fired boilers
so that the information can be retrieved easily. In prep-
aration of this report some of the difficulty in obtaining
information was caused by inadequate reference systems
rather than lack of information.
Wood-fired boilers offer great potential for generation
of energy from renewable fuels. If properly designed,
constructed, and operated they can be expected to contribute
a minimum of pollution to the atmosphere.
6-51
-------
REFERENCES
1. Corder, S.E. Properties and Uses of Bark as an Energy
Source. Paper prepared for XVI IUFRO World Congress,
Oslo, Norway, June, July, 1976.
2. Food and Agricultural Organization of the United
Nations. Yearbook of Forest Products for 1972. Rome,
1974.
3. Corder, S.E. Wood and Bark as Fuel. Oregon State
University, Forest Research Laboratory Bulletin 14,
Corvallis, Oregon, August, 1973.
4. de Lorenzi, 0., Editor Combustion Engineering. First
Edition, Published by Combustion Engineering-Superheater,
Inc., New York, 1952.
5. Surprenant, N. et al. Preliminary Emissions Assessment
of Conventional Stationary Combustion Systems. Report
prepared for U.S. EPA by GCA Corp., Bedford, Mass.,
January, 1976.
6. Brown, O.D. Energy Generation From Wood-Waste. Paper
prepared for International District Heating Associa-
tion, French Lick, Indiana, June 20, 1973.
7. Energy Recovery From Solid and Wood Wastes - for
Lane County Oregon.Project No. C7774.0, CH2M/HILL,
Corvallis, Oregon, 1973.
8. Junge, D.C. Boilers Fired With Wood and Bark Residues.
Oregon State University, Forest Research Laboratory
Bulletin 17, Corvallis, Oregon, November 1975.
9. Mingle, J.G. and R.W. Boubel. Proximate Analysis of
Some Western Wood and Bark. Wood Science, 1:1, pp.
29-36, July 1968.
10. Johnson, R.C. Some Aspects of Wood Waste Preparation
for Use as a Fuel. Tappi, 58(7), pp. 102-106, 1975.
-------
11. Keller, F.R. Fluidized Bed Combustion Systems for
Energy Recovery from Forest Products Industry Wastes.
Paper presentation from Forest Products Research
Society Meeting, Denver, Colorado, September 1975.
12. Dearborff, D. Wet Wood Waste as a Viable Fuel Supply.
Paper presentation from Forest Products Research
Society Meeting, Denver, Colorado, September 1975.
13. Jasper, M. and P. Koch. Suspension Burning of Green
Bark to Direct-Fired High-Temperature Kilns for
Southern Pine Lumber. Paper presentation from Forest
Products Research Society Meeting, Denver, Colorado,
September 1975.
14. Archibald, W.B. Some Design and Economic Considerations
in Wood Waste Burning. In wood and bark residues for
energy, Forest Research Laboratory Conference, Oregon
State University, Corvallis, Oregon, February 1975.
15. Environmental Protection Agency—Standards of Performance
for New Stationary Sources, Federal Register, Vol. 36,
No. 247, Part II, December 23, 1971.
16. Boubel, R.W. A High Volume Sampling Probe, Journal of
the Air Pollution Control Association, Vol. 21, pp.
783-787, 1971.
17. Boubel, R.W., J. Hirsch, and B. Sadri. Particulate
Sampling has Gone Automatic, Proceedings of the Annual
Meeting of the Air Pollution Control Association,
Boston, Mass., 1975.
18. Morford, J.M. The Comparison of a High-Volume
Sampling Method with EPA Method 5 for Particulate
Emissions from Wood-Fired Boilers, Air Resources
Center, Oregon State University, September 1975.
19. Strickland, S.R. A Comparison of the Emission Factors
for the Open Burning of Agricultural and Logging
Residues versus the Energy Utilization of these
Residues, Project for M.S. Thesis, Department of
Mechanical Engineering, Oregon State University,
December 1975.
20. Cristello, J.C. An Evaluation of the Lear Siegler RM-4
Optical Transmissometer as a Continuous Particulate
MonitoryProject for M.S.Thesis,Department of Mechani-
cal Engineering, Oregon State University, July 1974.
-------
21. Adams, A.B. Corrosion Problems with Wet Scrubbing
Equipment, Journal of the Air Pollution Control Asso-
ciation, 26(4), pp. 303-307, 1976.
22. Mick, A.H. Wood Waste Fired Boilers; Wet Scrubber
Technology, Proceedings of the Annual Meeting of the
Air Pollution Control Association, Portland, Oregon,
1976.
23. Betchley, R.H. The Use of Electrostatic Precipitators
on Controlled Low Odor Furnaces and Bark Burning
Boilers in the Paper Industry, Paper presentation to
Annual Meeting PNWIS Section of APCA, Paper 73-AP-27,
November 1973.
24. Atmospheric Emissions from the Pulp and Paper Manu-
facturing Industry - Report on NCASI-EPA Cooperative
Study Project, NCASI Technical Bulletin No. 69, February
1974.
25. A Guide to Estimating Heat Input Combination Boiler
Emission Rate Calculations, NCASI Technical Bulletin
No. 70, March 1974.
26. Emission Testing Standard for Wood Fuel Boilers, Pre-
sented by the Oregon-Washington 1973 Hog Fuel Boiler
Study Committee, Oregon Department of Environmental
Quality, November 1973.
-------
APPENDIX A
NUMBER OF WOOD-FIRED BOILERS BY STATE*
*
Estimates are based on a regression analysis of wood con-
sumption by state, using the equation:
N = 0.0416 Q + 12.7
where N = Number of boilers
Q = Wood consumption, 1000 TPY
2
Precision of the regression analysis: r =0.61
-------
A-l
No. Boilers = 0.041564 (Total Ton/Year) + 12.7,
r2 = 0.61
No. of Industrial Commercial- Total
Wood Fired Consumption, Institutional Industrial +
Boilers 103 Ton/Year Consumption Institutional-
(* Estimated) (5) 103 Ton/Year Commercial,
State (5) 103 Ton/Year
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusettes
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hams hi re
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennslyvania
Rhode Island
South Carolina
South Dakota
Tennessee
96
10
14
*100
* 69
9
* 0
0
* 99
102
0
* 61
14
* 15
0
2
* 16
50
35
4
10
27
12
20
11
44
0
1
13
0
3
47
35
0
8
* 0
318
27
0
32
2
75
872
104
0
2111
1359
2
0
0
2084
2286
0
1166
1
48
0
0
68
1624
1298
0
3
0
87
1284
15
632
0
0
24
0
0
0
2615
0
9
0
4336
154
0
677
4
597
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2.5
0
0
0
0
0
61.8
3.9
0
0
0
0
0
0
0
0
0
0
0
0
63.4
0
0
0
0
0
872
104
0
2111
1359
2
0
0
2084
2286
0
1166
1
48
0
0
70.5
1624
1298
0
3
C
148.8
1287.9
15
632
0
0
24
0
0
0
2615
0
9
0
4399.4
154
0
677
4
597
-------
A-2
State
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
No. of
Wood Fired
Boilers
(* Estimated)
25
0
30
23
98
* 0
100
4
Industrial
Consumption,
103 Ton/Year
(5)
323
0
51
626
3771
0
414
0
Commercial-
Institutional
Consumption
103 Ton/Year
(5)
0
0
0
0
0
0
5.6
0
Total
Industrial +
Institutional,
Commercial,
103 Ton/Year
323
0
51
626
3771
0
419.6
0
TOTAL
1693
28,645
137.0
28,782
-------
APPENDIX B
CHARACTERISTICS OF BARK FUEL
-------
Table B-2. A SUMMARY OF SOME PUBLISHED VALUES OF PROXIMATE ANALYSES FOR BARK
Species
Coniferous
Fir, Douglas
(Pseudotsuga menziesii)
Fir, Balsam
(Abies balsamea)
Fir, Grand
(Abies gvandis)
Hemlock, Eastern
(Abies canadensis)
Hemlock, Western
(Abies heterophylla)
Pine, Jack
(Pinus bariksiana)
Pine, Ponderosa
(Pinus ponderosa)
Redwood
(Sequoia sempervirens)
Spruce, Black
(Picea ma.riana)
Spruce, Red
(Picea rubens~)
Spruce, White
(Picea glauoa)
Tamarack
(Larix laraeina)
Non-Coniferous
Alder, Red
(Alnus vubra)
Beech, American
(Fagus grandi folia)
Birch, Paper
(Betula papyri f era)
Birch, Yellow
(Betula alleghaniensis)
Elm, American
(Ulrms americana)
Maple, Red
(Acer- rubrwn)
Maple, Sugar
Volatile
matter
Percent
70.6
77.4
74.9
72.0
74.3
74.3
73.4
71.3
74.7
72.9
72.5
69.5
74.3
75.2
80.3
76.5
73.1
73.1
75.1
Fixed
carbon
by dry weight
27.2
20.0
22.6
25.5
24.0
23.6
25.9
27.9
22.5
23.7
24.0
26.3
23.3
16.9
18.0
.21.0
18.8
18.9
19.9
Ash
2.2
2.6
2.5
2.5
1.7
2.1
0.7
0.8
2.8
3.3
3.5
4.2
2.4
7.9
1.7
2.5
8.1
3.0
5.0
(Acer saccharum)
-------
B-Z
Table B-l. A SUMMARY OF SOME PUBLISHED ULTIMATE ANALYSES OF BARK3
Species
Coniferous
Fir, Douglas
(Pseudotsuga menziesii)
Fir, Balsam
(Abies balsamecC)
Hemlock, Eastern
(Tsuga canadensis")
Hemlock, Western
(Tsuga heterophylla)
Pine, Jack
(Pinus bariksiana)
Pine, Scots
(Pinus silvestris)
Spruce, Black
(Pioea mar-Land)
Spruce, Norway
(Pioea abies)
Spruce, Red
(Piaea rubens)
Spruce, White
(Pioea glauoa)
Tamarack
(Larix laracina)
Non-Coniferous
Beech , American
(Fagus grandi folia)
Birch, European White
(Be tula verrucosa)
Birch, Paper
(Be tula pa.pyrifera')
Birch, Yellow
(Be tula alleghaniensis")
Elm, American
(Ulmus omer"icana)
Maple, Red
(Acer rubrum)
Maple, Sugar
Carbon
53.0
52.8
53.6
51.2
53.4
54.4
52.0
50.6
52.1
52.4
55.2
47.5
56.6
57.4
54.5
46.9
50.1
50.4
Hydrogen
Percent by
6.2
6.1
5.8
5.8
5.9
5.9
5.8
5.9
5.7
6.4
5.9
5.5
6.8
6.7
6.4
5.3
5.9
5.9
Oxygen
and
Nitrogen
dry weight
39.3
38.8
40.1
39.3
38.7
38.0
39.8
40.7
39.1
38.2
34.7
39.1
35.0
34.1
36.8
39.7
41.0
39.6
Ash
1.5
2.3
2.5
3.7
2.0
1.7
2.4
2.8
3.1
3.0
4.2
7.9
1.6
1.8
2.3
8.1
3.0
4.1
(Acer saccHarum}
-------
B-3
Table B-4. A SUMMARY OF SOME PUBLISHED HEATING VALUES AND ASH CONTENTS
FOR BARK OF NONCONIFEROUS SPECIES1
Higher heating value1
(Gross calorific value1)
Species
Alder, Red
(Alnus rubTa)
Aspen, Quaking
(Populus tremulo-ides)
Beech, American
(Fagus grandifolia)
Birch, European white
(Betula verrucosa)
Birch, Paper
(Betula papyri-fera)
Birch, Yellow
(Betula alleghaniensis)
Blacktupelo
(Nyssa sylvatica)
Cottonwood, Black
(Populus trichooavpa)
Elm, American
(Ulmus americana)
Maple, Red
(Acer rubrwri)
Maple, Sugar
(Acer saccharum)
Oak, Northern Red
(Quevcus rubva)
Oak, White
(Quercus alba)
Sweet gum
(Liquidambar styvaoiflua)
Sycamore, American
(Platanus oac-identalis)
Willow, Black
(Salix nigra)
Kcal/kg
4,687
4,958
4,244
5,790
5,506
5,728
5,319
5,111
4,412
5,000
4,121
4,222
4,500
4,315
4,572
4,667
4,156
4,412
4,237
4,237
4,268
Btu/lb
8,436
8,924
7,640
10,422
9,910
10,310
9,574
9,200
7,942
9,000
7,418
7,600
8,100
7,767
8,230
8,400
7,481
7,942
7,627
7,909
7,683
Ash
content1
Percent
3.1
2.8
7.9
1.6
1.5
1.8
1.7
2.3
7.2
-
9.5
8.1
3.0
6.3
4.1
5.4
10.7
5.7
-
5.8
6.0
1Based on oven-dry weight.
-------
Table B-3. A SUMMARY OF SOME PUBLISHED HEATING VALUES AND ASH CONTENTS
FOR BARK OF CONIFEROUS SPECIES1
Higher heating value1
(Gross calorific value1)
Species
Fir, Douglas
(Pseudotsuga menziesii)
Fir, Balsam
(Abies balsamea)
Hemlock, Eastern
(Tsuga canadensis)
Hemlock, Western
(Tsuga heterophylla)
Larch, Western
(Larix occidental-is)
Pine, Jack
(Pinus banksiana)
Pine, Lodgepole
(Pinus cantor ta)
Pine, Scots
(Pinus silvestris)
Pine, Slash
(Pinus elliottii)
Pine, Southern
(Mixed species)
Pine, Spruce
(Pinus glabra)
Pine, Virginia
(Pinus virginiana)
Redcedar, Western
(Thuja plicata)
Spruce, Black
(Picea mariana)
Spruce, Engelmann
(Picea engelamannii')
Spruce, Norway
(Picea abies)
Spruce, Red
(Picea rubens)
Spruce, White
(Picea glauca)
Tamarack
Kcal/kg
5,611
5,265
5,056
5,213
4,939
5,444
4,885
5,211
4,961
5,997
4,775
5,343
4,909
4,787
4,680
4,833
4,899
4,783
5,000
4,914
4,760
4,794
4,739
5,006
Btu/lb
10,100
9,477
9,100
9,383
8,890
9,800
8,793
9,380
8,930
10,794
8,595
9,618
8,837
8,617
8,424
8,700
8,819
8,610
9,000
8,846
8,568
8,630
8,530
9,010
Ash
content'
Percent
_
2.3
2.3
1.6
2.5
-
1.6
» 1.7
2.0
2.0
1.7
0.6
-
-
-
-
2.0
2.4
-
2.5
2.8
3.1
3.0
4.2
(Larix laracina)
-------
APPENDIX C
NATIONAL COUNCIL OF THE PAPER INDUSTRY
FOR AIR AND STREAM IMPROVEMENT
AIR QUALITY IMPROVEMENT TECHNICAL BULLETIN NO. 70
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.-1-
A GUIDE TO ESTIMATING HEAT INPUT FOR COMBINATION
BOILER EMISSION RATE CALCULATIONS
INTRODUCTION
Through the years various methods have been developed to
express the magnitude of particulate emissions from point sources,
The simplest and probably first method used was concentration of
mass per standard unit volume of flue gas. The units used (and
still used in many instances today) were grains per standard dry
cubic foot (SDCF). A concentration adjustment based on a fixed
C02 content of the flue gas or amount of excess air above that
theoretically needed for combustion has been commonly applied
to measured particulate concentrations from boilers burning
fossil fuels. This concentration adjustment is still used to-
day by many regulatory agencies to standardize particulate con-
centration values and avoid situations where dischargers can meet
a permissible concentration level by dilution.
The particulate concentration adjustment factors used for
fossil fuel fired boilers have not been applied to process
sources such as lime kilns or kraft recovery furnaces or a host
of other industrial operations since the flue gas composition
differs widely for manufacturing operations.
Another approach extensively used to express allowable par-
ticulate emissions from fossil fuel fired boilers relates heat
input to the boiler to allowable emissions. The units of expres-
sion for this method are "pounds per million Btu heat input."
The units of expression are used over any range of boiler load-
ing or combustion condition.
EPA promulgated standards of performance for new stationary
sources, published in the Federal Register on December 23, 1971,
express allowable emission rates in pounds/million Btu input
for fossil fuel fired steam Generators.
Many state and local regulatory agencies have formulated
particulate standards for fossil fuel fired boilers that also
express permissible limits for particulates as Ibs. per 10^ Btu.
In formulating particulate emission regulations for combination
fuel fired boilers the same method of expression for describing
permissible limits have frequently been used. It was unfortu-
nately assumed that the same methods for accurately measuring
fuel flow for fossil fuel fired power boilers existed and were
used on these combination boilers. This is usually true in those
cases where oil or gas are burned but not so where coal and bark
are burned. In probably no more than 10% of the cases in this
country where wood derived fuel is burned, are there facilities
installed to weigh bark flow, although such facilities do exist.
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-2-
In those cases where agencies require particulate emissions
from combination boilers to be expressed as Ibs./lO^ Btu's,
this cannot be done by direct measurement of fuel inputs in the
majority of cases. In view of these facts it is felt that a re-
view of the methods for calculating or estimating the heat inputs
to a boiler burning bark is both timely and desirable.
This report reviews the method for calculating heat inputs
by measuring fuel feed rates as is recommended in the Federal
Register. Examples are shown to provide the reader an idea of
the accuracy of "Heat Input" calculations when applied to boil-
ers burning wood derived fuel. Several methods for estimating
heat input are demonstrated and the relative merits or pitfalls
of these estimations are discussed.
II GLOSSARY OF TERMS
E = particulate emission rate in lb/10°Btu
C = particulate concentration in grains/SDCF
SDCF = one cubic foot of dry gas at 29.92" Hg pressure
and 530°R temperature
I
Qf = boiler gaseous effluent flow rate in SDCFM
Hj = gaseous heat input to a boiler expressed in 10^ Btu/hr,
Ho = heat output from a furnace in 10^ Btu/hr.
hstm = enthalpy of steam in Btu/lb. of steam
nfw ~ enthalpy of feed water in Btu/lb. of feed water
Wg = steam generation rate of a boiler in # steam/hr
e = boiler efficiency; the ratio of boiler heat output
Ho to boiler heat input, Hj
Vs = stack gas flow in SDCFM
F = fuel oil flow in GPM
B = bark feed rate in Ib/hr. (oven dry basis)
= excess air correction; 20.9
20.9 - % 02 (in flue gas)
= fuel gas flow rate in CFM
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-3-
III BOILER PARTICULATE EMISSION RATE CALCULATIONS
The method for calculating particulate mass emission rate
used by EPA and other agencies is in this or similar form:
CQ_
E ~ x 60 (1)
„ 7000
HI
It is evident from equation 1 that three items must be mea-
sured before the emission rate E can be calculated. One is C
or the particulate concentration. This value is determined in
accordance with federal,state, or local procedures when compliance
testing is conducted. Other methods may be used for other pur-
poses, and a discussion of the various procedures is beyond the
scope of this report. For illustrative purposes it will be
assumed that the value for C in all examples in this report has
been determined to be 0.1 gr/SDCF. The second term of infor-
mation, Qf, is the total stack gas flow rate as determined by
a suitable method in a stack of known cross section . Again, a
discussion of the procedure used to determine Qf is beyond the
scope of this report. In all examples in this report, it is
assumed Qf has been determined to be 120,000 SDCFM.
The ratio 60 min-lbs is a constant used to convert
7000 hour-grains
the particulate emission rate from grains/SDCF to Ibs/hr. In
the denominator of equation 1 is the total heat input to the
boiler in 10^ Btu/hr, Hj. This item of information and its
determination will be the subject of the bulk of this report.
IV DETERMINING BOILER HEAT INPUT FROM OIL AND GAS
The term Hj is easily determined on straight oil fired boil-
ers since #6 residual oil has a chemical composition that is so
constant the heat content may be assumed to be 150,000 Btu gallon
measured at 60°F (2), and the measurement of liquid flow is simple,
accurate and commonly practiced. Likewise, the measurement of nat-
ural gas presents little problem. The carbon hydrogen content of
natural gas varies causing a shift in the heat content of gas gener
ly assumed to be 1050 Btu/ftJ at 60°F and 30" Hg. (3). Caution mus
therefore be taken to define heating gas heat value.
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-4-
V DETERMINING BOILER HEAT INPUT FROM WOOD DERIVED FUEL
A. Fuel Moisture Content and Fuel Heating Value Related Errors
in Estimating Heat Input
(1) Moisture Content - When bark is used as a fuel, the problem
of measuring heat input by weighing the fuel is complicated by
the fact that the moisture content of the bark can vary con-
siderably. Wood derived fuel either on the log or subsequent
to barking/is usually stored outside where it is subject to
weather conditions. It may also be derived from wet or dry
barking which affects moisture content causing the heat content
on an "as is" basis (which is the way it is weighed when being
fed to the boiler) to vary considerably. Therefore, to achieve
maximum accuracy in the weight of wood derived fuel fired, se-
veral samples should be taken during the particulate test for
determination of representative moisture content on a composite
sample.
(2) Heating Value - Another complication arises from the var-
able heating value of bark (O.D. basis) which varies depending
on the source species. A cursory search of the literature
(2,4,5,6) gives a range of over 2,000 Btu/O.D. Ib. for different
species of bark and wood fuels. If the type of fuel being burn-
ed is known this range of heat value may be reduced to about
±200 Btu/O.D. Ib., according to literature references.
If the heat content of a composite sample of wood fuel were
determined using a bomb calorimeter, the ranae of uncertainty
could be reduced to about ±100 Btu/lb. Needless to say this
procedure is time-consuming but it may be a desirable for fuels
burned during the conduct of compliance tests.
Knowing the heat content of all fuels being burned and the
feed rate, the heat input can then be determined. The following
example shows actual data from a typical Southern mill combina-
tion boiler firing #6 residual oil and Southern pine bark to.
illustrate the degree of uncertainty in estimating heat input
with inadequate fuel heating value information. The ranges
of uncertainty in this example are based on differences in
heating values reported in the literature and based on actual
experience - in measuring variables such as bark moisture content.
-------
,-5-
EXAMPLE 1. CALCULATING HEAT INPUT (Hx) WHEN USING FUEL FLOW
MEASUREMENTS
OIL DATA
A. Feed Rate:
B. Heat Content:
VALUE
RANGE
15.2 GPM
150,000 Btu gal.
C. Heat Input Due to Oil:
Hj-oil = 6
(15-2 x 150,000 x 60)= 136.8 x 10 Btu/hr.
±0.1
±150
± 1.04 x 106
II BARK DATA
A. Feed Rate (as is)
B. Heat Value (1)*
(2)*
82,000 Ib/hr.
8,900 Btu/O.D. lb.
8,900 Btu/O.D. lb.
C. Average Bark Moisture
D. Feed Rate (O.D. basis)
82,000 Ib/hr. x
48%
± 1000
± 1000
± 100
± 5% (absolute-ran'
43 to 53)
= 42,640 Ib/hr. ± 4,620
E. Total Heat due to Bark: Hj-bark
II-B-(l) 42,640 x 8900 = 379.5 x 106Btu/hr.± 83.8 x 106
II-B (2) 42,640 x 8900 = 379.5 x 106Btu/hr.± 46.3 x 106
*NOTE; Value for (1) and II-B-1 based on literature source.
Value for (2) and II-B-2 as determined by bomb
calorimeter, hence the smaller uncertainty range.
Ill TOTAL HEAT INPUT TO BOILER
HI = HI-oil + HI-bark
H! = (136.8 + 379.5) x 106Btu/hr.
Hj = 516.3 x 106 Btu/hr.
-------
-6-
Using the mean heat value for bark taken from the literature the
uncertainty range would be ±1000 Btu/lb. bark and the value for
Hj would be
Hj = 516.3 x 106Btu/hr. ±84.8 x 106
therefore the value for H would have an uncertainty range of
± 17% if other measurements were at limits of precision.
If the heat value for bark were actually determined to be
8900 Btu/# 100 by bomb calorimeter the value for Hj would be
more precise and the uncertainty limits would be reduced. In
this case
Hj = 516.3 x 106Btu/hr. ±46.3 x 106
the range for Hj could be reduced to ± 9% if other measurements
were at limits of precision.
This exercise demonstrates that where heat input determina-
tions are made when wood derived fuel is used, the accuracy of
the heat input determination is much less than when straight oil
or gas is burned. Inability to obtain representative samples for
moisture content and inadequate fuel heating value data are pro-
blem areas even though fuel is weighed. The accuracy with which
heat input can be determined is dependent on (a) accuracy of the
wood derived fuel heating value, (b) inherent limits, of determin-
ing moisture content of wood derived fuel,and (c) the ratio of
wood derived to auxiliary fuel, the larger the ratio the greater
the potential discrepancy.
B. Potential Errors in Estimating Heat Input from Steam Flow
Measurements
Since probably no more than 10% of the facilities burning
bark have the capability to weigh bark flow, other means must
be used to determine heat input. One common method is to esti-
mate heat input from steam generation data. In addition to
steam generation rate, the temperature and pressure of the
steam generated and the temperature and pressure of the feed
water must be known. The enthalpy of feedwater is subtracted
from that of the steam and this result is multiplied by the
steam generation rate? Ws, which is expressed in Ibs/hour:
Ho - Ws (hatm - hfw) (3)
Then the heat input to the boiler, Hi may be determined by
the equation
H - H°
i "e (4)
where e is the efficiency of the boiler. The value e, which is
always less than one, is a term which is used to define the portion
-------
-7-
of heat generated which is not absorbed by the feedwater to gen-
erate steam. Heat is lost through various ways, e.g., radiation
through boiler walls, stack losses, heat required to vaporize
moisture in the fuel, load on the unit, care exercised in operat-
ing it, and boiler age.
The value of e which is initially selected by the boiler
manufacturer at the time of design is therefore subject to many
variables beyond his control. When burning wood derived fuel
possibly the greatest of these variables is fuel moisture con-
tent.
This variable alone makes it difficult to arrive at a true
gross heat input from steam generation data. Since regulations
which relate emission rate to heat input relate them to gross
heat input the procedure at best has severe limitations.
EXAMPLE 2. ESTIMATION OF HEAT INPUT BASED ON STEAM GENERATION
RATE
Assume a boiler is generatina 450,000 Ibs/hour of 1250 psia
steam at a temperature of 900°F. The assumed boiler efficiency
for this boiler is 70% (e = 0.7) . The heat input is determined
as follows:
From steam tables
Vi =1 4TP
"steam J-«*JQ
and
Hfw = 385 Btu/lb.
therefore
HQ = 450,000 (1438-385)
H0 = 473.85 x 106Btu/hr.
Using a value for e of 0.7 H, can now be calculated
473.85 x 106
HI ~ 0.7
H, = 676.92 x io6Btu/hr
-------
-8-
VI ESTIMATING COMBINATION FUEL BOILER HEAT INPUT FROM
COMBUSTION GAS MEASUREMENTS
A. Discussion of Heat Input Estimation Method
When oil and unweighed wood derived sources of fuel are sim-
ultaneously burned, it can be shown that the heat input (Hi) is
expressed in the following equation:
Hj = 282.63 KVS [20.9 - % 021 + 0.75 x 106F (5)
where F = fuel oil flow in GPM (#6 residual oil)
Vs = stack flow is SDCFM
K is a variable that depends upon the heat content of the bark
used. In the equation a heat value of 8900 Btu/O.D. Ib. is assumec
If another value for heat content is used, the value for K may
be determined by dividing the heat content of the bark by 8900.
K _ heat content of bark
8900 (6)
As can be seen from equation 5 the only fuel flow rate needed is
that for oil. The stack flow must be accurately determined and
several Orsat analyses must be made during the particulate test
in order to accurately determine flue gas oxygen concentrations.
These are critical values since the gas flow due to bark is deter-
mined from these values and fuel value of the bark. An ultimate
analysis of the bark is not required since a median value was in-
corporated in the constant during development of equation 5. A
survey of the literature shows that the ultimate analysis does nbt
vary widely from species to species so a single representative
ultimate analysis was universally applied to all barks. The ultinu
analysis used in derivation of equation 5 was:
H2 = 5.5%
C » 56.5%
02 = 37.0%
N2 = 0.4%
Ash = 0.6%
The magnitude of change in estimating heat input with bark with a
different ultimate analysis will be shown.
-------
-9-
B. Example of Use of the Combustion Gas Volume Heat Input Es-
timating Procedure
EXAMPLE 3. ESTIMATING BOILER HEAT INPUT USING COMBUSTION GAS
VOLUMES
Assume that during the particulate test the following data
were collected:
Vg = 120,000 SDCFM
16 oil flow = 15.2 GPM
%0
= 6.0% (average of 12 readings)
Heat content of Douglas
Fir bark = 10,100 Btu/O.D. Ib.
The solution for Hj is:
H = 282.63 x
1QaSn x 120,000 [20.9-6.0] + 0.75 x 15.2 x 106
o y uu
= 573.48 x 10 + 11.4 x 10
Hz = 584.88 x 106 Btu/hr.
C. Combustion Calculations Used in Development of Gas Volume
Heat Input Estimating Procedure
In order to show how equation 5 was derived, this section
discusses the combustion calculations applied to a combination oil
and bark boiler situation.
(1) Weight and Volume of Combustion Products - The weight and
volume of the products of fuel combustion were developed from the
ultimate analysis. In many cases this analysis can be obtained
from a literature reference. In the example used for illustration
an ultimate analysis of Douglas fir bark is used.
ULTIMATE ANALYSIS OF DOUGLAS FIR BARK
ELEMENT
H2
C
02
% BY WEIGHT
6.2
53.0
39.3
MOLECULAR WEIGHT = MOLE %
2 3.1
12 4.42
32 1.23
-------
-10-
COMBUSTION REACTIONS
REACTION REACTANTS PRODUCTS
I. 2H2 +02-*-2 H20 H2 = 3.1 moles (from a) H20= 3.1 moles
3.1 = 1.55 moles
°2 = —
2. C + O2 •*• C02 C = 4.42 moles (from a) CO2 = 4.42 moles
02 = 4.42 moles
The moles (based on 1 gram) of each component are determined by
the stoichiometry of the chemical equations 1 and 2. From the total
moles of reactants and products the following may be determined:
TOTAL 02 consumed (Reaction 1 and 2)= 1.55 + 4.42 = 5.97 moles
There are 1.23 moles of 02 already present in the bark. Therefore,
the total 02 to be supplied from air to support theoretical
combustion is:
5.97 - 1.23 = 4.74 moles
The composition of normal air is: (6)
N2 = 78.1% by volume
02 = 20.9% by volume
other = 1.0% by volume
Since the "other" species are generally inert, the % volume of
N? may be considered to be 79.1% (78.1+1.0). It may be noted
that % by volume is equivalent to mole percent; therefore, these
values may be expressed as mole percent.
WEIGHT OF COMBUSTION PRODUCTS
Since 4.74 moles of 02 must be derived from air, then:
4.74 x 79>1 = 17.94 moles of N-> must also be
20.9 2
introduced.
-------
-11-
The products formed are therefore
1. 17.94 moles N2
2. 4.42 moles C02
3. 2.75 moles H20
and the weight of gaseous products formed in the combustion
of 1 Ib. of Douglas fir bark (assuming 0% excess air) would
be:
Ib. mole fraction x mole weight = weight (Ibs)
0.1794 x 28 = 5.02 Ibs N2
0.0442 x 44 = 1.95 Ibs. C02
0.0275 x 18 = 0.50 Ibs. H20
7.47 total products
The weight of normal air needed to theoretically oxidize
1 Ib. of Douglas fir bark would be
Ibs. H2 = 5.02
Ibs. 02 = 1.52
6.54
As can be seen, 6.54 Ibs. of normal air is required to oxidize
1 O.D. Ib. of Douglas fir bark at 0% excess air. This formed
7.47# of gaseous products (N2,H20,C02). The small apparent
material imbalance of 0.07 Ibs. is due to products that are
solid rather than gaseous (e.g., ash).
VOLUME OF COMBUSTION PRODUCTS (DRY GAS)
Assume 1 gram of bark is oxidized. Since 1 gram-mole of any
gas occupies 22.414 liters at a pressure of 760 mm. Hg and
a temperature of 0° Celsius (6), this is the same as 0.8526
cubic feet at 29.92" Hg. and 70°F, or 0.8526 SDCF.
One gram-mole of this Douglas fir bark was shown to produce
0.1794 gram-moles of N2 and 0.0442 gram-moles of C02. The
volume of dry gas produced is:
ft3
0.1794 g-moles x 0.8526_ = 0.153 SDCF
g-mole
-------
-12-
and 0.0442 g-moles x 0.8526 SDCF/g-mole = 0.038 SDCF
Total gas = 0.153 + 0.038 = 0.191 SDCF
Since there are 454 grams/lb., 1 Ib. of O.D. Douglas fir
bark will produce:
0.191 x 454 = 86.6 SDCF of gas at 0% excess air.
VOLUME OF COMBUSTION GAS FROM OTHER FUELS (DRY GAS)
Using the procedures for determining the dry gas volume of
combustion products it can be shown that:
a. Pine bark with the following ultimate analysis (5):
ELEMENT % BY WEIGHT
H2 5.5
C 56.5
02 37.0
N2 0.4
Ash 0.6
produces 90.3 SDCF of gas per pound of bark. This compares
favorably to the 86.6 SDCF of gas produced by the bark from
Douglas fir. Using other reported ultimate analyses the gas
volume produced by 1 pound of O.D. bark was found to vary
no more than ±5% from the volume produced by 1 Ib. of O.D.
bark from another species. In the absence of an ultimate
analysis the figure 90.3 SDCF/lb. of bark at 0% excess air
can be considered a reliable estimate regardless of bark specy.
b. No. 6 fuel oil with tne following ultimate analysis (2):
ELEMENT % BY WEIGHT
H2 10.5
C 85.7
S 2.8
02N2 0.92
Ash 0.08
Heat content = 150,000 Btu/gal. or 18,500 Btu/lb. produces
-------
-13-
172.1 SDCF of gas per Ib. of oil.
c. Natural gas with the following ultimate analysis :
ELEMENT % BY WEIGHT
CH4 89%
C2H6 5%
C3H8 2%
C4H10 1%
C02 2%
N2 1%
Heat content=1050 Btu/ft.3,produces 9.1 SDCF of gas per ft.3
of feed gas. This may vary as much as ± 15% as a result of
fuel gas composition (3).
VII DERIVATION OF HEAT INPUT FROM GASEOUS COMBUSTION
PRODUCTS EQUATION FOR BARK AND OIL
Using the relationships developed in the previous section
on combustion calculations and assigning a constant value to the
variables of combustion product volumes from oil and bark a
general equation can be derived.
The following assumptions are made:
1) 1 pound bark generates 90.3 SDCF of dry gas at 0%
excess air when combusted.
2) 1 pound of oil generates 172.1 SDCF of gas at 0% excess
air when combusted or 1395 SDCF/gal. oil
3) Heating value of oil is 150,000 Btu/ gallon
The following variables are measured or are the result of
measurements:
1) Fuel oil flow rate = F in Gal/min
2) Vs = Stack gas flow in SDCFM
3) fgA = Excess air correction to adjust Vs to 0%
20.9
oxygen content =
20.9 - % O2 in flue gas
4) K = A variable defined as:
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By definition:
HI = HI-oil + HI-bark
where
HI-oil= 150,000 Btu/gal X 60 min/hr X F gal/min
= F X 9(10)6 Btu/hr (Eq 7)
HT_b k = Heating value of bark Btu/hr X bark feed rate
(B) Ib/hr
By definition:
K = heating value of bark
8900
then:
HI-bark = 8900 X K X B (Eq 8)
The bark flow rate B is:
V_SDCFM \
& Gas volume \ « 6C
" from oil combustion SDCFM j
B=
fEA
90.3 SDCF/lb (Eq 9)
The gas volume from oil combustion is:
1395F SDCFM (Eq 10)
Substituting equation 10 into equation 9 we get
/Vs \
B = 0.6644(_J? 1395 F] (Eq 11}
V EA J
Substituting equation 11 into equation 8:
HI-bark = s _ 8>25 (1Q)6 x K x F
fEA
Rearranging:
HI-bark = 5913 KVs-282.63 KVS %o2-8.25 x 1Q6KF (Eg 12)
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,-15-
Substituting equations 7 and 12 into 6:
Hj = 5913 KVS - 282.63 KVS% 02
- 8.25 x 106KF + 9 X 106F (F.q 13)
Since the effect of K in the expression 8.25 x 10 KF is
small it may be assumed to be 1 and the equation can be sim-
plified to
H - 282.63 [20.9KVS-02 KVS] + 0.75xl06F which (Eq 14)
is equation 5.
VII1 DERIVATION OF HEAT INPUT FROM GASEOUS COMBUSTION PRODUCTS
EQUATION FOR BARK AND GAS
Using the relationships developed in previous sections on
combustion calculations and assigning a constant value to the
combustion product volumes from gas and bark,another general
equation can be derived:
The following assumptions are made:
(1) 1 pound bark generates 90.3 SDCF of dry gas at 0%
excess air when combusted.
(2) 1 ft3 of feed gas generates 9.1 SDCF gas at 0% excess
air when combusted.
(3) Heating value of gas is 1050 Btu/ft3.
The following variables are measured or are the result of
measurements:
(1) Gas flow rate = G in ft3/m
(2) V0 = stack gas flow in SDCFM
5
(3) fT,, = Excess air correction to adjust Vs to 0%
Cif\ . . a
oxygen content =
20.9
20.9 - % 02 content in flue gas
(4) K = A variable defined as:
measured heat content of bark
8900
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-16-
By definition:
- HI-gas + HI-bark
where
HI S = 1050 Btu/ft3 X G X 60 = 63,000 G Btu/hr (Eq 16)
HI-bark = K X 890° X B (Eq 8)
The bark flow rate is:
V0 Gas volume from\ „ fr. . .,
-L. gas combustion X 60 mln/hr
f EA/
90.3 SDCF/lb
The gas volume from gas combustion is 9.1 G SDCFM
Substituting into equation 17:
/vs - 9.1^
B = \fEA
90.3
Rearranging:
'VQ
- 0.16 ) 60
H N ~~ / 1___?_ - 53800 KG (Eq 1
Since the effect of K is small in the second part of the equa-
tion it can be assumed to be 1 and the equation can be simplified
to:
5913 K Vs (20.9 - % 02)- 53800 G (Eq 1
HI-bark = 2079
which is in the same form as equation 5.
The variability in ultimate analysis and heat content of gas
limits the use of this general equation but does not preclude the
development of a similar expression to fit the case at hand.
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IX SUMMARY
(1) The potential errors in estimating heat input to a boiler
when fuel is not weighed or measured have been outlined
and the limitations of estimating heat input from measured
steam production rates and steam characteristics emphasized.
(2) For those situations where wood derived fuel is not weighed
before burning an estimating procedure which is based on
measurement of the volume of the dry products of combustion
and relating this measurement to the composition and heat-
ing value of the fuel was developed.
(3) The estimating procedure is (a) independent of fuel moisture
content, and (b) suitable for use where wood derived fuel
is burned separately or in conjunction with other fuels
(if the feed rate of other fuels is measured).
(4) The procedure depends on two measurments commonly made
during source particulate sampling, namely (a) stack gas
volume and (b) oxygen content of the flue gas (as frequent-
ly as every 5 to 10 minutes during the sampling period).
(5) The procedure depends on a knowledge of heating value of
the fuel or fuels burned and can be further refined if
an ultimate analysis of the fuel or fuels is known. This
would permit adjustment of the numerical constants in
the general equation for estimating heat input which re-
flect ultimate analysis of typical fuels. The flue gas
volume change associated with the minor differences in
published ultimate analysis of oil and wood derived fuel
sources shows this to be of minor importance in arriving
at a rational estimate of heat input. Care must be used
in assuming a typical ultimate analysis for natural gas
however.
(6) A method of estimating emission rates from power plants
burning a single fossil fuel or gas is included in the
Appendix. The procedure is applicable where only one
fuel is burned and does not appear to have application
where wood derived fuel alone is burned unless it can
consistently be demonstrated that the flue gas volume and
fuel heating value relationship is consistent. Information
available at this time shows that a wider range of heat-
ing value for wood derived fuels of reasonably uniform
ultimate analysis indicates this will not be the case.
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-18-
X LITERATURE REFERENCES
1. Federal Register, Standards of Performance for New Stationary
Sources, 36:247, Part II (Dec. 23, 1971).
2. Combustion Engineering, 1st ed., Combustion Engineering, Inc.,
New York, New York (1967).
3. Perry, R.H., and Chilton, C.H., Chemical Engineers' Handbook,
5th ed., McGraw-Hill Book Co., New York, New York (1973).
4. Corder, S.E., "Wood and Bark as Fuel," Oregon State Forest
Research Laboratory, Corvallis Research Bulletin 14,
(Aug. 1973).
5. Koch, Peter, and Mullen, J.F., "Bark from Southern Pine May
Find Use as Fuel." Forest Industries 98 (4): 36-37, April,
1971.
6. Hodgman, Charles D., ed., Handbook of Chemistry and Physics,
43rd ed., 1936 Chemical Rubber Publishing Co., Cleveland
(1961).
7. Millikin, D.E., "Determination of Bark Volumes and Fuel
Properties," Pulp and Paper Magazine of Canada 56(13):
pp. 106-108 (Dec. 1955).
ftU.S. GOVERNMENT PRINTING OFFICE: 1978 Z60-880/3 1-3
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