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

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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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                                             1-10

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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

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             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

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    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
Fe23
CaO
CaC03
MgO
MnO
P25
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 400F).
                            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

-------
                  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

-------
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

-------
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 300F) 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

-------
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

-------
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

-------
     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

-------
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

-------
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
                            3-22

-------
         STACK
                                         *- STEAM TO  KILN
                                              FUEL
                                          SCREW CONVEYER
                                   ASH DOOR
                           AIR PLENUM
Figure  15.   Pile  burning:   "Dietrich" cell.
                       3-23

-------
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 400F 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
                            3-24

-------
                                                        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

-------
       DEFLECTOR  PLATE
          PNEUMATIC STOKER
               NO. 2  BOILER
          EUGENE WATER a ELECTRIC BOARD
                 EUGENE,OREGON
Figure 18.   Pneumatic stoker - No. 2 boiler
                       3-27

-------
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 950F 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

-------
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.
                            3-29

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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

-------
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
                            3-31

-------
                                                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 1400F.  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

-------
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,
                            3-34

-------
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 212F 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.
                            3-37

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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
                            3-44

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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
                            3-45

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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.
                            3-47

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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.
                            3-48

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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
                            3-49

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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.
                            3-50

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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.
                            4-1

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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
                            4-2

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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
                            4-3

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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
                            4-4

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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
                           4-5

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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
                            4-6

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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
                             4-7

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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.
                            4-8

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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
                           4-9

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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
                            4-10

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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
                            4-11

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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.
                           4-12

-------
      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

1800F.  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.
                           4-13

-------
     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
                           4-14

-------
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.
                           4-15

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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
                            4-16

-------
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,
                            4-17

-------
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
                              4-19

-------
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
                              4-20

-------
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
                             4-21

-------
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

-------
     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

-------
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

-------
     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

-------
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

-------
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

-------
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

-------
                   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

-------
     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

-------
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

-------
      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

-------
     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

-------
                 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

-------
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

-------
      The  "standard"  cubic  foot  is  also  ambiguous  unless  it


 is  defined.   The  "standard"  temperature for  a  cubic  foot may


 be  32,  60,  68, or  70F,  or 20C, which  is  equivalent to


 68F.   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 , 400F, 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/  68F, 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  +  68F  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

-------
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

-------
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

-------
     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

-------
     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

-------
           PROBE   -ff STACK
                   IIWALL
     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

-------
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.






                            5-13

-------
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
                            5-14

-------
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

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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

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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

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    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

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          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

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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

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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

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     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

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     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

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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

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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

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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

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                   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

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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 600F 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 2i^
                hour
          0 175    Pund
          u.i/b million Btu
      4)  3 5   Punds
       '  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
   II
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/}
    Il 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 AgencyStandards 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

-------
                             .-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.

-------
                             -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/10Btu

     C    = particulate concentration in grains/SDCF

     SDCF = one cubic foot of dry gas at 29.92" Hg pressure

            and 530R 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 60F  (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 60F 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.

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                             ,-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.

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                              -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

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                               -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 900F.   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

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                            -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.

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                              -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

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                               -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.

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                          -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 70F, 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

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                          -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

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                              -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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                              -14-



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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                             -17-


                         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).
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