U.S. Environmental Protection Agency Industrial Environmental Research EPA~600/7~77~054
Office of Research <)rnl Development Laboratory 4t\*w^
Research Triangle Park, North Carolina 27711 May 1977
PRELIMINARY ENVIRONMENTAL
ASSESSMENT OF COAL-FIRED
FLUIDIZED-BED
COMBUSTION SYSTEMS
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S.
Environmental Protection Agency, have been grouped into seven series.
These seven broad categories were established to facilitate further
development and application of environmental technology. Elimination
of traditional grouping was consciously planned to foster technology
transfer and a maximum interface in related fields. The s.even series
are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from
the effort funded under the 17-agehcy Federal Energy/Environment
Research and Development Program. These studies relate to EPA's
mission to protect the public health and welfare from adverse effects
of pollutants associated with energy systems. The goal of the Program
is to assure the rapid development of domestic energy supplies in an
environmentallycompatible manner by providing the necessary
environmental data and control technology. Investigations include
analyses of the transport of energy-related pollutants and their health
and ecological effects; assessments of, and development of, control
technologies for energy systems; and integrated assessments of a wide
range of energy-related environmental issues.
REVIEW NOTICE
This report has been reviewed by the participating Federal
Agencies, and approved for publication. Approval does not
signify that the contents necessarily reflect the views and
policies of the Government, nor does mention of trade names
or commercial products constitute endorsement or recommen-
dation for use.
This document is available to the public through the National Technical
Information Service, Springfield, Virginia 22161.
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EPA-600/7-77-054
May 1977
PRELIMINARY
ENVIRONMENTAL ASSESSMENT
OF COAL-FIRED FLUIDIZED-BED
COMBUSTION SYSTEMS
by
Paul F. Fennelly, Donald F. Durocher,
Hans Klemm, and Robert R. Hall
GCA Corporation
GCA/Technology Division
Bedford, Massachusetts 01730
Contract No. 68-02-1316, Task No. 15
Program Element No. EHE623A
EPA Task Officer: D. Bruce Henschel
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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ABSTRACT
This report provides a preliminary evaluation of the potential pollutants
which could be generated in coal-fired fluidized bed combustion processes.
Because S09 and NO formation have already received considerable attention
£ X
from a number of investigators, the primary emphasis here is on the so-
called "other" pollutants namely, trace elements, organic compounds,
inorganic compounds (other than S0? and NO ) and particulates.
£* X
Using available bench scale or pilot plant data and/or simple thermodynamics
and empirical correlations with data from other combustion systems, order
of magnitude estimates have been made of the concentrations of various
elements and compounds in either the flue gas, the solid waste, or the
water discharge.
The results suggest that, in general, no special environmental problems
should result from coal-fired fluidized bed combustion. But the results
also indicate that better data are required in several areas, particularly
with regard to particle size distributions, possible organic compounds,
and the fate of elements such as Be, As, U, Pb, Cd, Ni, Cl, Se, F and
their compounds.
iii
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CONTENTS
Page
Abstract ±±±
List of Figures viii
List of Tables x
Acknowledgments xii
Sections
I Summary 1
General Comments 1
Estimated Concentration Ranges of Potential Pollutants
From Coal-Fired Fluidized Bed Combustion 5
Flue Gas 5
Solid Waste 5
II Introduction 7
References 8
III Overview of Fluidized Bed Combustion Systems 9
Types of Fluidized Bed Combustion Systems 11
Potential Effluent Streams From Fluidized Bed
Combustion 15
Principal Differences Between Fluidized Bed Combustion
and Conventional Combustion 24
References 25
v
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CONTENTS (continued)
Sections Page
IV Potential Pollutants From a Coal-Fired Fluidized
Bed Combustor 28
Introduction 28
Fluidized Bed Combustion 29
Trace Elements 29
Gaseous Organic and Inorganic Compounds 45
Particulate Emissions 56
References 62
V Potential Pollutants From Auxiliary Processes Associated
With Fluidized Bed Boilers 67
Limestone Regeneration 67
One-Step Regeneration 67
Two-Step Regeneration 68
Solid Waste Disposal 74
Experimental Studies 74
Trace Metal Leaching 75
Fuel Storage and Handling 80
Coal Storage Requirements 80
Coal Pile Drainage and Leachates 80
Air Emissions From Coal Storage and Handling 82
Coal Drying 82
Cooling Systems 83
References 87
vi
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CONTENTS (continued)
Sections Page
VI Suggested Control Technology For FBC Systems 91
Introduction 91
Flue Gas Treatment: And-On Control Technology 91
Particulate Control Equipment for Atmospheric
Pressure Combustion 92
Particulate Control for Pressurized Combustion
Systems 105
Control of Gaseous Emissions 109
Pollution Control Via Process Modifications: Some
Consideration Based Upon Fluidizatioh Fundamentals 110
Bed Depth 111
Bed and Boiler Tube Geometry 112
Fluidized Grid Design 113
Particle Size 114
Fluidization Velocity 116
Excess Air 117
Mechanism of Coal Injection 119
Pressure 119
Control of Pollutants From Spent Stone Disposal 120
Solid Waste Control Methods 122
Commercial Uses for Solid Waste By-Products 124
References 127
Append ix
Preliminary List of Conceivable Pollutants 132
vii
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FIGURES
No. Page
1 Schematic of Fluidized Bed Boiler 10
2 Selected Fluidized Bed Combustion System Options 12
3 Schematic Diagram of an Atmospheric Pressure Fluidized
Bed Combustion System 16
4 Schematic Representation of Coal Combustion 46
5 Schematic Representation of Coal Pyrolysis 48
6 Pyrolytic Synthesis of B(a)P 49
7 Variation in Hydrocarbon Concentration with Flue Gas Oxygen
Content in the Fluidized Bed Module (FBM) 51
8 Typical Particle Size Distribution of Elutriated Material
Collected in Primary Cyclone, Secondary Cyclone, and Fil-
ter Bag During Period of Additive Injection 58
9 Fly Ash Size Distribution from Pope, Evans and Robbins,
Inc., Atmospheric Pressure Fluidized Bed Combustion (AFBC) 59
10 Solids Loading of Flue Gas Leaving the Combustor in Argonne
National Laboratories Pressurized Fluidized Bed Combustion
(PFBC) 61
11 M. W. Kellog One-Step Regeneration Scheme 69
12 M. W. Kellog Two-Stage Regeneration Scheme 71
13 Solubilities of Trace Metals - (Free Aqueous and Mono-
Hydroxo Complexes Only Considered) 77
14 Control of Flue Gas Emissions From an Atmospheric Pressure
FBC Boiler 93
viii
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FIGURES (continued)
No. Page
15 Control of Flue Gas Emissions From a Pressurized FBC
Boiler 94
16 Particle Size Distribution Before Final Control Device 97
17 Dew Point Elevation as a Function of SO., Concentration 99
18 Measured Fractional Efficiencies for a Hot Side Electro-
static Precipitator, with the Operating Parameters as
Indicated, Installed on a Pulverized Coal Boiler 101
19 Penetration Calculated From a Venturi Scrubber Model as a
Function of Pressure Drop and Particle Aerodynamic Diameter 103
20 Median Fractional Collection Efficiency for 22 Tests 104
21 Schematic Representation of Aerodyne Particulate Separator 108
22 Quality of Fluidization as Influenced by Type of Gas
Distributor 114
23 Comparison Between Calculated and Experimental Entrainment
at Various Pressures 121
ix
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TABLES
No. Page
1 Atmospheric Pressure Fluidized Bed Combustion System Material
Flows and Characteristics 17
2 Estimated Trace Element "Worst Case" Emission Factors for
Bituminous Coal 32
3 Estimated Trace Element "Worst Case" Emission Factors for
Lignite 33
4 Typical Values of Trace Elements in Limestone and Coal (ppm) 35
5 The Separation of Elements in the Geochemical Classification
Scheme 36
6 Comparison of Exxon and Argonne Data on Trace Element
Recoveries 37
7 Projected Atmospheric Emissions of Trace Elements From
Conventional and Fluidized Bed Combustors Expressed as a
Percentage of the Element Entering the System 38
8 Comparison of Estimated Trace Element Concentrations
(Class I Elements) With an Environmental Index Based on
Threshold Limiting Values 40
9 Boiling Points of Compounds Often Found in Coal 41
10 Comparison of Estimated Trace Element Concentrations
(Class II Elements) With an Environmental Index Based on
Threshold Limiting Values 42
11 Calculated Equilibrium Concentration for Selected Species
Produced by Incomplete Combustion of Coal 55
12 Probable Chemical Form of Trace Elements in the Regenerator -
Extrapolated From Fuel Gasification, Free Energy Minimiza-
tion Calculations 72
x
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TABLES (continued)
No.
13 Volume of Spent Bed Plus Ash Produced Per Year By a
635-MW FBC Plant 74
14 Coal Ash Contamination of Beneficated Lime/Anhydrite 76
15 Relative Solubilities in Weakly Alkaline Solutions 79
16 Composition of Drainage From Coal Piles 81
17 Chemicals Used in Recirculative Cooling Water Systems 85
18 Cooling Tower Corrosion and Scale Inhibitor Systems 86
19 Distribution by Particle Size of Average Collection Effi-
ciencies for Various Particulate Control Equipment 95
20 Summary of Potential Particulate Removal Systems 107
21 Spent Bed Plus Ash Produced by a 635-MW Once-Through
Sorbent FBC Plant 120
22 Ash Collection and Utilization, 1971 125
23 Preliminary List of Possible Pollutants From Fluidized Bed
Combustion of Coal 133
xi
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ACKNOWLEDGMENTS
The authors would like to acknowledge helpful discussions during the
preparation of this report with Mr. D. Bruce Henschel of the U.S. En-
vironmental Protection Agency. The cooperation of the technical staff
of the fluidized bed combustion projects at Argonne National Labora-
tories, Argonne, Illinois; Exxon Research and Engineering Company,
Linden, New Jersey; and Westinghouse Research Laboratories, Pittsburgh,
Pennsylvania, is gratefully acknowledged. Other members of the GCA/
Technology Division who provided assistance were Mr. Mark Bornstein,
Mr. Richard Wang, Ms. Dorothy Sheahan, Ms. Sandra Sandberg, and
Ms. Josephine Silvestro.
xii
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SECTION I
SUMMARY
GENERAL COMMENTS
This report provides a preliminary evaluation of the potential pollutants
which could be generated in coal-fired fluidized bed combustion processes.
Because SO- and NO formation in fluidized bed combustion have received
2 x
considerable attention from a number of investigators, the primary empha-
sis here is on the so-called "other" pollutants - namely, organic com-
pounds, inorganic compounds (other than S02 and NOX), trace elements and
particulates. The major purpose in a sense has been to serve as a "devil's
advocate" with respect to pollutant generation. The aim is to focus atten-
tion on potential environmental problems as early in the development cycle
as possible. Accordingly, conclusions are often based on limited data; in
some cases, no data are available and one must rely on scientific and
engineering estimates. The results are intended primarily to stimulate
interest in potential problem areas and to assist in the design and plan-
ning of future experimental programs.
Based on data from bench scale reactorsa fluidized bed combustion offers
significant potential for reducing atmospheric trace element emissions in
comparison with conventional coal combustion systems, but data on trace
element emissions from larger fluidized bed pilot plants are still lacking.
Also lacking are data with respect to trace element composition as a
function of particle size. Based on "worst case" analyses with bituminous
and lignite coal as feed materials, elements whose emission pathways
warrant further attention are: Be, As, U, Pb, V, Cl, and F.
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Limited experimental data on particulate emissions from atmospheric pres-
sure bench scale and pilot plant operations indicate that control devices
such as cyclones, fabric filters or electrostatic precipitators should be
able to control emissions to a level similar to that attained in conven-
tional combustion systems. However, the compatibility of particulate
control devices with full-scale fluidized bed boilers has not yet been
tested; the need for experiments in this area is very important. Control-
ling particulates in pressurized fluidized bed is a difficult matter. Pilot
plant experiments indicate the use of two stage cyclones will not meet
current New Source Performance Standards. As yet, no satisfactory third
stage device which can operate at high temperature and pressure has been
demonstrated.
There is virtually no experimental information available concerning poten-
tial organic pollutants which could form in coal-fired fluidized bed com-
bustion. An evaluation based on chemical engineering experience and simple
thermodynamic considerations indicates no special problems should occur
from gaseous organic pollutants; however, experimental verification of
estimated emission rates should receive high priority.
The following generic classes of "potential" pollutants have been consid-
ered in this report:
Acids and Acid Anhydrides
Organic Acids - Compounds such as carboxylic acids,
dicarboxylic acids, and sulfonic acids could conceiv-
ably form from incomplete combustion of hydrocarbons;
however, at the temperatures involved (~850°C), com-
pounds of this type should quickly decompose to form
small hydrocarbons and CC^
Inorganic Acids - The predominant inorganic acids
should be HC1 and HF. Sulfuric, sulfurous, nitric
and nitrous acid should not form until the flue gas
has cooled to temperatures less than 240°C.
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Carbon Compounds
The major carbon compounds, as expected, will be CC>2 and
CO. Soot (solid carbon) could be a problem since it would
be emitted as small particles (< 0.1 ym) which could pass
through most particulate control devices. Calcium and mag-
nesium carbides could also form in small quantities in the
ash formed in the combustor, the carbon burn-up cell or the
regenerator. After ash disposal, these compounds could re-
lease acetylene upon contact with water. The quantities
generated, however, should pose no special problems.
Halogen Compounds
Halogens should be emitted primarily as HX (where X =
F, Cl, Br). Experience in coal combustion chemistry
indicates that the presence of chlorine in coal en-
hances condensation reactions via elimination of HC1;
hence, species such as chlorinated hydrocarbons are
not favored. Furthermore most chlorinated aliphatics
are unstable at the temperatures prevailing in the
combustor.
Hydrocarbons
Long chain aliphatics and cyclic hydrocarbons should
decompose within the bed to form H2 and smaller hydro-
carbons . Some of these smaller hydrocarbons could
condense to form polycyclic species such as pyrene,
anthracene, etc. Hydrocarbon concentrations are
strongly dependent on the amount of excess air. With
excess air levels of about 20 percent, total hydrocarbon
levels (measured as methane) of less than 100 ppm are
attainable. Based on a comparison with data from conven-
tional combustion systems, 1 ppb of benzo(a)pyrene (or
similar compounds) could be present in fluidized bed
combustion. With excess air levels of 10 percent,
benzo(a)pyrene could reach 10 ppb.
Nitrogen Compounds
The predominant nitrogen compound should be NO. Trace
amounts (< 1 ppm) of HCN, (CN)2 and azoarenes may be
present. Species such as amines, pyridine, pyrroles,
and nitrosamines, which could form as combustion inter-
mediates, should quickly decompose within the bed to
form hydrocarbons, NO and HCN.
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Oxygen Compounds
Oxygenated hydrocarbons such as furans, ethers, esters,
aldehydes, etc. could form as combustion intermediates.
These species, however, are unstable at temperatures on
the order of 850°C, and they should decompose before
escaping from the bed. Ozone, if formed, would also
decompose at these temperatures.
Particulates
As mentioned earlier, although there are only very limited
data available on particulate concentrations and particle
size distributions, it seems that no special problems should
result from particulate loadings, provided the conventional
process cyclones and a control device such as an electro-
static precipitator or a fabric filter are used. The
actual performance of these devices on full-scale fluidized
bed boilers, however, has not yet been tested.
Radioactive Isotopes
Based on a "worst case" analysis with lignite coal, uranium
could be emitted at significant levels, but the radioactive
isotopes of uranium as well as those of other radioactive
elements should not be present in high enough quantities to
cause concern.
Sulfur Compounds
S02 and 803 will be the major sulfur compounds formed.
The presence of limestone in the bed, however, should keep
these emissions below present emission standards. COS could
form in trace quantities (~1 ppm). Compounds such as
thiophenes or mercaptans, if formed as combustion inter-
mediates, will decompose to hydrocarbons and H2S; the
H2S will then be oxidized to form S02-
Trace Elements
Data should be acquired with respect to the fate of
trace elements such as Be, As, Pb, V, Ni and Cl. Also
needed are data with respect to chemical composition as
a function of particle size. For the most part, the
other trace elements commonly encountered in coal com-
bustion are captured in the coarse solids and remain in
the bed. The high pH of the bed material is advantageous
in that it tends to retard the leaching of the heavier metals.
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ESTIMATED CONCENTRATION RANGES OF POTENTIAL POLLUTANTS FROM
COAL-FIRED FLUIDIZED BED COMBUSTION
Using available data and/or simple thermodynamics and empirical correla-
tions, estimates have been made of the concentrations of various elements
and compounds in either the flue gas or the solid waste. In some cases,
these estimates are based on simple and tenuous assumptions; but, in gen-
eral, they should be good to within an order of magnitude. The main pur-
pose of estimates such as these is to help define experiments which can
be used to test the environmental acceptability of fiuidized bed combustion.
Flue Gas
One hundred parts per million;
(100 ppm)
Ten parts per million:
(10 ppm)
One part per million:
(1 ppm)
One part per billion:
(1 ppb)
One-tenth part per billion:
(0.1 ppb)
CH4, CO, S02, NO
S03,
, HC1
HF, HCN, NH3, (CN)2, COS, H2S,
H2S04, HN03, Elemental Vapors,
As, Pb, Hg, Br, Cr, Ni, Se, Cd,
U, Be, Na
Diolefins, Aromatic Hydrocarbons,
Phenols, Azoarenes
Carboxylic Acids, Sulfonic Acids,
Alkynes,, Cyclic Hydrocarbons,
Amines, Pyridines, Pyrroles,
Furans, Ethers, Esters,
Epoxides, Alcohols, Ozone,
Aldehydes, Ketones, Thiophenes,
Mercaptans, Chlorinated Hydrocarbons
Solid Waste
0.1 to 1 percent
Al, Ca, Fe, K, Mg, Si, Ti, Cu, Na
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Ten part per million
(10 ppm)
One part per million
(1 ppm)
One part per billion
(1 ppb)
One-tenth part per billion:
(0.1 ppb)
Cu , Ni , Co, Pb, As, U
Zn, V, F, Br, Cl
Ba, Co i Mn, Rb, Sc, Sr, Cd, Sb,
Se, Be
Eu, Hf, La, Sn, Ta, Th.
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SECTION II
INTRODUCTION
The overall technical objective of this project is to provide a prelimi-
nary evaluation of the potential pollutants which could be generated in
all variations of coal-fired fluidized bed combustion processes. In per-
forming a preliminary environmental assessment, one's major role in a
sense is to serve as a "devil's advocate" with respect to pollutant genera-
tion. The aim is to focus attention on potential environmental problems
as early in the development cycle as possible. This provides maximum
lead time to gather the technical data on which decisions regarding con-
trol technology or process modifications (should they be needed) can be
based. This particular project was divided into three phases.
The first phase was to provide a review of fluidized bed combustion tech-
nology and to identify conceivable pollutants. An overview of fluidized
bed combustion systems appears in Section III. The identification of
conceivable pollutants was based on the materials involved (coal, bed
material, etc.) and pertinent process parameters (temperature, pressure,
etc.); a list was made of possible pollutants which could be emitted
from coal-fired fluidized bed combustion processes. This list, which is
provided in the Appendix, served as the focal point of the second phase,
which consisted of an engineering and scientific evaluation to determine
at what concentration levels the pollutants identified in phase 1 could
exist in the various effluent streams (air, water, solid waste) of a
fluidized bed combustion system. The methods used to estimate the various
pollutant levels for the major unit operations of a fluidized bed
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combustion system are described in Section IV which forms the main body
of the report. The primary emphasis was on trace elements, inorganic
compounds, organic compounds and particulates; S02 and NOX have already
received considerable attention. This evaluation included calculations
or extrapolations based on available laboratory or pilot plant data. In
cases where data were lacking, simple kinetic or thermodynamic estimates
were used. No emission measurements were made as part of this program.
The third phase, which is described in Section VI, involved the providing
of suggestions for appropriate control measures to reduce any emissions
which may exist at undesirably high levels.
This project was part of EPA's Program for Environmental Characterization
of Fluidized Bed Combustion Systems. It is the first step in a long-range
environmental assessment program being carried out by a number of con-
tractors which will include: more detailed process stream information,
a comprehensive analysis of emissions, control technology assessment and
environmental impact analysis. The overall program strategy has been
recently described.
REFERENCES
Henschel, D. 3. The U.S. Environmental Protection Agency Program
For Environmental Characterization of Fluidized Bed Combustion
Systems. (Presented at the Fourth International Conference on
Fluidized Bed Combustion. Sponsored by U.S. Energy Research and
Development Administration. McLean, Virginia. December 1975.)
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SECTION III
OVERVIEW OF FLUIDIZED BED COMBUSTION SYSTEMS
A fluidized bed boiler can be simplistically depicted as an enclosed
cavity containing boiler tubes and a bed of granular solids, to which fuel
is added. As shown in Figure 1, the solids are supported on a grid at the
bottom of the boiler through which combustion air is passed at high veloci-
ties, typically 2 to 5 feet per second. The solids are held in suspension
by the upward flow of the air and a quasi-fluid is created which contains
many properties of a liquid. The most important liquidlike property to
the boiler designer is the fact that the bed material is exceptionally
well mixed and flows throughout the system without mechanical agitation.
Fluidized bed coal combustion systems for the production of steam and/or
electricity have several advantages over conventional combustion sys-
tems.1'2 Capital and operating costs should be lower for the following
reasons:
High heat transfer coefficients and volumetric heat
release rates will reduce the boiler size by 1/2 to
2/3 or more compared to a conventional unit.
Capital costs will be reduced due to the size reduction
and the potential for shop fabrication instead of field
cons truetion. » > 3
First generation plants1'2'3^*5 should achieve fuel-to-
electricity efficiencies comparable to the best con-
ventional systems (36 to 38 percent)1"5 while second gen-
eration plants may achieve higher efficiencies of 40 to
47 percent.2 The higher efficiencies will be achieved
by operating at higher steam temperature and pressure
than is possible with a conventional system.
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COAL SUPPLY
FLUE GAS TO
STACK
COAL
METERING
FAN
FLUID1ZED-BED
COMBUSTION ZONE
STEAM
FEEDWATER
BREECHING
FUEL INJECTION
AIR
BOILER TUBES
IN FORM OF
WATER WALLS
COMBUSTION
AIR
PLENUM
CHAMBER
AIR DISTRIBUTION
GRID
Figure 1. Schematic of fluidized bed boiler
10
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Flue gas emissions of SO and NO will be reduced without the use of aux-
^ x
iliary control equipment. A limestone bed will collect the SO while the
NO emissions will be low due to the inherent ability of fluidized bed
X
combustors to achieve low NO emissions. The mechanism for reducing NO
x x
emissions is not completely understood. It involves low thermal fixation
of atmospheric nitrogen as well as low conversion of fuel nitrogen to NO .
Cooling requirements will be reduced for those fluidized bed systems that
use gas turbines to extract part of the energy.
Potential problem areas include environmental impacts of limestone regenera-
tion and/or solid reuse disposal and unknown flue gas emissions. Potential
pollutants which could form in FBC flue gases but have not yet been
measured are discussed in depth in later sections of this report.
TYPES OF FLUIDIZED BED COMBUSTION SYSTEMS
A fluidized bed combustion system is defined by a combustor, an energy use
or conversion cycle, and a spent stone regeneration or disposal method, as
well as numerous auxiliary systems. Some major options regarding combustor
design conditions include operation of the bed at atmospheric versus
elevated pressure and the presence or abscence of heat transfer surfaces
in the bed. Energy may be generated as process steam or converted to
electric energy through steam turbines, gas turbines, and combined sys-
tems. Stone processing options include: (1) no processing (once-through
operation) and (2) one-step or two-step regeneration followed by sulfur
recovery, sulfuric acid recovery, or SO scrubbing. Figure 2 presents
some of the most probable options for selected variables in a complete
fluidized bed combustion system.
Three basic combustion types can be defined by the operating pressure and
excess air. These are atmospheric combustion, pressurized combustion
(15 to 25 percent excess air) and adiabatic combustion (pressurized and
300 percent excess air). The energy output from the atmospheric combustor
will be steam from tubes in the bed for process use or conversion to
11
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FLUIDIZED BED
COMBUSTION SYSTEMS
I USER
2 PURPOSE
3 PROBABLE TYPICAL SIZE,
I06 Btu/hr FUEL WJPUT
4 OPERATING PRESSURE
5 EXCESS AIR, PERCENT
6 CYCLE TYPE
7 FUEL-TO-ELECTRICITY
EFFICIENCY
8 REGENERATION
9 REGENERATION PROCESS
10 FINAL S REMOVAL
INDUS'
STEAM G
5<
AT MO*
15-
PROCES
PRIAL UTIL
ENERATION ELECTRIC
30
>PHERIC ATMOSI
-25 15-
S STEAM STEAM
5C
'HERIC
25 15
rURBINE 22
ITY
GENERATION
00
1
PRESSURIZED
(10 ATM)
1
1 I
-25 300 (ADIABATIC)
AM TURBINE(8O%) GAS TURBINE(80%)
GAS TURBINE(20%) AND WASTE HEAT
BOILER-STEAM
TURBINE (20%)
N.A. 36-38 36-38 31-
I 1 1
1 ' 1 1 1 1
NO YES NO YES NO YES Y
1
I-STEP I-S
1
TEP
-38
ES
1
I-STEP 2-STEP PRESSURIZED
i i
I 1 1 I I
S H2S04 SOo S H9SOd
RECOVERY RECOVERY SCRUBBING RECOVERY
RECOVERY
PROBABLE Co = S MOLE RATIO IN FEED TO COMBUSTION IS 2=1. COAL SULFUR CONTENT MAYBE 4 PERCENT
IN INITIAL SYSTEMS. PROBABLE OPERATING TEMPERATURE OF THE MAIN COMBUSTOR IS 850-950° C.
Figure 2. Selected fluidized bed combustion system options
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electricity. Pressurized systems (both normal excess air and adiabatic)
will produce electricity through steam and gas turbines. The normal
excess air pressurized system energy output will be 80 percent through a
steam turbine (driven by steam generated in tubes in the bed) and 20 per-
cent through a flue gas turbine. In the adiabatic system, no heat transfer
tubes will be in the bed and the total amount of heat will be absorbed by
the large amount of excess air. The energy will be extracted from the
flue gas and converted to electricity by the flue gas turbines (80 percent)
followed by a waste heat boiler/steam turbine combination (20 percent
of energy output). Without the waste heat boiler, the fuel-to-electricity
efficiency of the adiabatic system would be low (25 percent).^ Even with
the waste heat boiler, the efficiency will probably be lower than the
normal excess air pressurized system.
The atmospheric pressure combustion system has been simpler to develop,
should be easier to operate and is in the most advanced stage of develop-
ment compared to other fluidized bed systems. Two reasons for the relative
ease of operation and more advanced development have been the lower pressure
and and lack of need for flue gas turbines. Pope, Evans and Robbins,
Inc.^>9 have developed a process and are building a system under an Energy
Research and Development Administration contract. Under a subcontract,
Foster Wheeler is assisting with the detailed design and construction of the
demonstration plant. The demonstration plant will have a fuel input capacity
of 375 x 106 Btu/hr or 28,800 Ib/hr of coal at the projected heat content
of 13,000 Btu/lb (30 MW). The size of the unit will be similar to an
industrial boiler, thus serving as a demonstration for industrial utiliza-
tion and a scale-up step toward a utility size unit. Construction of the
demonstration plant is progressing with shakedown scheduled for completion
in 1977. Pope recently told a Congressional subcommittee that commercial
use of fluidized bed combustion could be possible by 1979.10 ERDA and the
Electric Power Research Institute (EPRI) are considering the design and
construction of a 200 MW boiler as the next step in a combined development/
demonstration program.10
13
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The pressurized fluidized bed combustion system operating at normal excess
air appears to be an economically attractive system compared to conven-
tional coal-fired utility boilers and to atmospheric pressure systems.2*7
One reason is the small size and lower capital cost. The pressurized com-
bustion concepts have only been evaluated as a utility application because
a percentage of the energy must be recovered from the flue gas as mechani-
cal or electrical energy and because the system is more complex. In addi-
tion, the potential advantages of higher steam temperature and pressure
(improved fuel-to-electricity efficiency) are only applicable to utility
systems.
High temperature gas cleaning to prevent turbine blade erosion is one
area of technical investigation.6'11
The National Coal Board of England has operated a 2-foot by 3-foot,
five atmosphere pressurized combustor with a heat input of 4.0 to 6,5 x
106 Btu/hr for at least the past 5 years.12 Exxon began operation of a
12.5-inch diameter 10 atm "miniplant" with a capacity of 6.3 * 106 Btu/hr
in 1975.13 ERDA has recently awarded a contract to Curtiss-Wright Inc.
for the development of a 10 MW unit which is a cross between a steam-tube
and adiabatic design. The International Energy Agency is also planning
a 30 MW unit in England.
Combustion Power Company is primarily responsible for development of the
adiabatic fluidized bed combustion concept; coal combustion work at Com-
bustion Power is funded by ERDA. The adiabatic combustor appears to have
several disadvantages, including the much larger volumes of gas.that must
be handled at 300 percent excess air instead of 15 to 25 percent. In
addition, preliminary estimates indicate a lower fuel-to-electricity
efficiency.7 Handling large volumes of gas and lack of boiler tubes in
the bed appear to negate two potential advantages of fluidized bed com-
bustion, mainly small size and high heat transfer rates. Possible advan-
tages of the system are complete combustion without a carbon burn-up cell,
no boiler tube erosion and the ability to burn low grade fuels including
-------
refuse. Combustion Power Company has operated a 7-foot diameter process
development unit at about 25 * 106 Btu/hr heat input and is testing turbine
performance and life.°
Although a commercial atmospheric pressure and possibly a pressurized
fluidized bed combustion system should be in operation by the early 1980's,
they will not be widely used in the utility industry until the late 1980"s-
One reason is the long lead time of 5 or more years involved between plan-
ning and operating an electric power plant.
POTENTIAL EFFLUENT STREAMS FROM FLUIDIZED BED COMBUSTION
In a complete fluidized bed combustion system there are many potential
effluent streams including air emissions, liquid wastes and solid wastes.
Figure 3 is a schematic diagram of a complete atmospheric pressure fluid-
ized bed' combustion system. Estimates of the numbered flows normalized to
a coal feed of 1 pound per hour are presented in Table 1. (Flow diagrams
for the stone regeneration system will be presented later.) Many of the
effluent streams will be similar to a conventional coal-fired steam power
plant as described in reference 15. A few minor effluent streams, such as
preoperational and operational boiler water side cleaning wastes and boiler
and air preheater fireside cleaning wastes, have not been included. Fig-
g
ure 3 is based primarily on the Pope, Evans and Robbins (PER) system with
emission points, cooling tower systems, and water treatment systems added
by GCA. (Details on the emission streams are presented in later sections
of this report.)
Based on the overall flow of materials depicted in Figure 3, the fluidized
bed combustion system can be categorized into the following major unit
operations:
Fluidized Bed Combustion
Limestone Regeneration
Solid Waste Disposal
15
-------
1 LIMESTONE
SCPi'ATOS
FROM
BCD MATERIAL
51 SEPARATOR
AMD
STORAGE
LIWESTO'tE I
TR'.'C* I
COOLING
WATEn
MAKEUP
WATCH flt
Figure 3. Schematic diagram of an atmospheric pressure fluidized bed combustion system
(reference 8 was a basic data source; GCA added, emission points, cooling
tower, and water treatment system)
-------
Table 1. ATMOSPHERIC PRESSURE FLUIDIZED BED COMBUSTION SYSTEM MATERIAL FLOWS AND CHARACTERISTICS0
Material flows
1. Coal feed to bedsb
2. Limestone feed to bedsc
3. Coal storage"
4. Air emissions from
coal storage
5. Coal pile drainage
6. Coal feed to dryer
7. Air emissions from coal
dryer before primary
control
8. Hot air to coal dryer
9. Coal feed to crusher
10. Air emissions from coal
dryer after primary
control but before ESP
11. Coal feed from crusher
12. Solids from coal dryer
primary control
13. Limestone supply from truck
14. Air emissions from lime-
stone separator
15. Limestone to storage bunker
16. Flue gas from primary
fluidized bed combustion
cells (FBC)
17. Bed material from FBC (max)
18. FBC combustion air^
Solid
Total
1.0000
0.2709
1940
0.0008
0.0004
1.0-
1.1
0.01
-
0.993
0.003
0.943
0.007
0.2712
0.003
0.2709
0.2891
2.78
-
Carbon
0.7120
1390
0.0005
0.712
0.0071
-
0.707
0.002
0.707
0.005
0.0983
-
Ash
0.085
160
0.0006
0.085.
0.00085
-
0.079
0.00035
0.079
0.0006
-
Sulfur
0.043
84
0.0004
0.000003-
0.0006
0.043
0.00043
-
0.040
0.00013
0.040
0.003
-
Gas
_
-
_e
-
-
1.2
1.1
-
1.2
-
-
0.005
0.005
-
11.26
9.95
Liquid
_
_
-
-
0.078
-
-
-
-
-
-
-
-
-
-
_
-
Temp., °F
80
80
80
80
80
80
160
600.
160
160
160
160
80
80
80
730
1400
600
-------
Table 1 (continued).
ATMOSPHERIC PRESSURE FLUIDIZED BED COMBUSTION SYSTEM
MATERIAL FLOWS AND CHARACTERISTICS3
Material flows
19. Vents from bed material
handling system
20. Material to cyclone no. 1
(sum of 16 + 19)
21. Air emissions after
cyclone no. 1
22. Cyclone no. 1 bottoms
(solids) to carbon
burn-up cell (CBC)
23. Limestone to CBC
24. Coal to CBC
25. Combustion air to CBCS
26. CBC bed material to FBC
27. Air emissions from CBC
before primary collector
(cyclone no. 2)
28. Air emissions from ash silo
to cyclone no. 2
29. Air emissions from cyclone
no. 2 to ESP
30. Bottom material from cyclone
no. 2 to ash silo
31. Vents from bed material
separator and storage
to ESP
32. Inlet to electrostatic pre-
cipitator (sum of 10 + 14
+ 21 + 29 + 31)
Solid
Total
0.002
0.2911
0.0146
0.2765
0.0437
0
0.0247
0.1879
0.0188
0.1691
0.003
0.0397
Carbon
0.0983
0.00188
0.09642
0
-
0.0097
0.0010
0.0087
0.003188
Ash
0
-
Sulfur
0
-
Gas
0.069
11.33
11.33
-
-
0
1.26
-
1.267
1.267
-
0.104
14.002
Liquid
-
-
-
-
0
-
-
-
-
-
Temp . , °F
1400
730
730
730
80
600
2000
730
730
730
1400
730
00
-------
Table 1 (continued).
ATMOSPHERIC PRESSURE FLUIDIZED BED COMBUSTION SYSTEM
MATERIAL FLOWS AND CHARACTERISTICS3
Material flows
33. Material collected by
electrostatic precipitator
(EFF = 0.96 4- rain)
34. Outlet of ESP
35. Maximum gas leak
36. Air emissions from stack
(sum of 34 + 35)
37. Vent from screens and
bed material transfer
38. Bed material to screens
39. Waste bed material
40. Vent from waste bed
material separator
before rotofin cooler
41. Waste bed material
to rotofin cooler
42. Cooled waste bed material
to ash silo
43. Fine bed material from
vibration screens
44. Air emissions from bed
material separator to ESP
45. Air emissions from bed
material storage to ESP
46. Bed material from
storage to FBC
Solid
Total
0.0381
0.0016
-
0.0016
0.001
2.57
0.1455
(0.694
max) .
0.001
0.1445
0.1445
2.43
0.0028
0.0002
2.43
Carbon
-
Ash
-
Sulfur
-
Gas
_
14.002
1.66
15.662
0.035
0.035
-
-
0.097
0.0069
-
Liquid
_
-
-
-
-
-
-
-
-
-
-
Temp . , °F
730
730
105
270
1400
1400
1400
1400
1400
700
1400
1400
1400
1400
-------
Table 1 (continued).
ATMOSPHERIC PRESSURE FLUIDIZED BED COMBUSTION SYSTEM
MATERIAL FLOWS AND CHARACTERISTICS3
Material flows
47. Cooling water to condenser
48. Cooling requirement
49. Cooling water from condenser
50. Cooling tower drift
51. Cooling tower feed water
(sum of drift (50) +
blowdown (52) + evaporation
52. Cooling tower blowdown
53. Cooling tower water
treatment effluent
54. Total makeup water require-
ments for cooling tower
55. Boiler water blowdown
56. Boiler water makeup
requirement
57. Boiler feed water
treatment wastes
58. Solid waste from ash silo
(sum of 30 + 33 + 42)
59. FBC combustion air
fed with coal^
Solid
Total
-
0.3517
-
Carbon
_
-
-
-
-
-
-
-
Ash
_
'-
-
-
-
-
-
-
Sulfur
_
-
-
-
-
-
-
-
Gas
_
-
-
-
-
-
-
-
0.6
Liquid
490
-
490
0.02
(0.01-
0.05)
6.42
1.3
0.64
7.06
-
-
Temp . , °F
85
(6800 Btu)
85
730
600
NJ
O
-------
Table 1 (continued) . ATMOSPHERIC PRESSURE FLUIDIZED BED COMBUSTION SYSTEM
MATERIAL FLOWS AND CHARACTERISTICS3
o
Based on. Figure 2 , all flows are pound of material per pound of coal. The design of a 30-MW elec-
trical output requires 28,800 pounds of coal per hour.
bCoal, Pittsburgh Seam No. 6; NHV = 13,000 Btu/lb.
Coal
Ash
Species
C
H2
02
N2
S
H20
Ash
Weight %
71.20
5.07
6.33
1.30
4.30
3.30
8.50
100.00
Species
Si02
Fe203
A1203
CaO
K20
Ti02
MgO
Na20
P205
Misc
Weight %
45.30
27.30
21.20
1.90
1.80
1.00
0.60
0.20
0.10
0.60
100.00
Ib/lb coal
0.0385
0.0232
0.0180
0.0016
0.0015
0.0009
0.0005
0.0002
0.0001
0.0005
0.085
-------
Table 1 (continued). ATMOSPHERIC PRESSURE FLUIDIZED BED COMBUSTION SYSTEM
MATERIAL FLOWS AND CHARACTERISTICS3
NJ
cLimestone, BCR 1359 assumed, Ca:S = 2:1.
Species
CaO
CO 2
Si02
MgO
Fe203
H20
Weight %
55.52
40.58
0.50
0.30
0.10
3.00
100.00
Ib/lb fuel
0.1504
0.1100
0.0014
0.0008
0.0003
0.0081
0.2710
Storage capacity (not a material flow).
6
Carbon monoxide and hydrocarbons from spontaneous combustion. Amount unknown.
Eighteen (18) percent excess air.
^Twenty-five (25) percent excess air.
-------
Coal Storage and Handling
Coal Drying
Cooling Operations
The latter operations, coal storage, coal drying and cooling will be
similar for all coal combustion systems. The total cooling required, how-
ever, will vary with the energy feed to the steam turbine and the effi-
ciency of the turbine. In most cases, cooling equivalent to about 60 per-
cent of the energy input to the steam turbine will be required. Effluent
Guidelines and Standards for Steam Electric Power Generation16 will require
recirculative cooling for almost all new plants. A utility will maintain
a coal supply of 90 days while industry commonly maintains a supply of
30 days.1^ Wind erosion and handling cause a minor amount of particulate
emissions. Leachates from coal storage can be a more serious problem and,
as such, are regulated,16 and control measures are applied. Particulates
are emitted from many coal drying operations, but they can be controlled
by conventional equipment.
Water treatment is another conventional unit operation. Make-up.cooling
water is commonly treated by coagulation and clarification with aluminum
and iron salts or lime. Polyelectrolytes are used to increase coagulation
and sedimentation rates. In some cases, more sophisticated water treatment
methods may be needed, depending on the water supply. Waste streams
generated by cooling tower make-up water treatment are generally just
water streams containing higher concentrations of impurities in the feed
water. Even with recirculative cooling, large amounts of make-up water
are needed and supply can be a problem.
There are many solids transfer operations involved in operating a fluid-
ized bed combustion system. Conventional practice is to use cyclones
for initial solids separation in pneumatic transfer systems with fabric
filters as secondary collectors. In the design of the PER system, ma-
terial regenerators and transfer systems will use cyclones vented to the
main high efficiency electrostatic percipitator as shown in Figure 3.
23
-------
The PER system is slightly unusual in that all solid waste products are
transferred dry. Wet sluicing is the most common practice at conven-
tional plants, and ash slurring water discharge can be a major water
pollution problem.
No significant emissions will occur from coal crushing. In all fluidized
bed systems coal will be crushed to about one-quarter inch and less. Coal
crushing is a common and conventional unit operation, and the equipment as
used by electric utilities is entirely self-contained.
The primary focus of this study is the primary fluidized bed combustor,
the carbon burn-up cell (if used), and the regeneration system (if used).
The fluidized bed combustion process and factors affecting pollutant forma-
tion will be discussed in depth in Sections IV and V of this report.
These systems will be the most important potential emission sources.
Potentially very large amounts of solid waste may be produced if regen-
eration is not used. At a Ca:S ratio of 2:1, the PER system generates
about 0.35 to 0.4 pound of waste per pound of coal burned. This is more
than a conventional system and would amount to about 700,000 tons per
year at a typical 500 MW plant.
PRINCIPAL DIFFERENCES BETWEEN FLUIDIZED BED COMBUSTION AND
CONVENTIONAL COMBUSTION
Many of the differences and similarities between fluidized bed combustion
systems and conventional combustion systems have been described in the
previous paragraphs. The discussion here focuses mainly on the primary
fluidized bed combustor and the carbon burn-up cell. Perhaps the most
important difference from the standpoint of pollutant formation is the
low combustion temperature in the primary combustor, most typically 1550 to
1650 F (850 to 900 C). Depending on furnace design, conventional systems
may operate at temperatures of over 3000°F (1650°C). The lower tempera-
ture of fluidized bed combustion contributes to reduced formation of NO
X
and improves the limestone bed reaction with the SO , but could cause less
24
-------
efficient combustion and possibly larger emissions of organics and CO.
In most fluidized bed systems, material containing unburned carbon is
recycled either to a carbon burn-up cell or back to the main cell. Con-
ventional utility coal combustors operate with less than 1 percent unburned
carbon losses at excess air in the range of 15 to 22 percent.18 The low
operating temperature in fluidized bed combustion also may reduce volatili-
zation of trace metals as discussed in later sections.
Excess air in most designs is very similar to conventional systems
15 to 25 percent. Higher amounts of excess air in conventional systems
lead to greater heat losses in the stack gas and lower efficiencies.
The 300 percent excess air used in the adiabatic system greatly exceeds
the amount used in any conventional system. That high level of excess
air is more typical of refuse incinerators.
Other differences in the design of fluidized bed systems are mentioned
at appropriate points throughout this report.
REFERENCES
1. Henschel, D. B. The Environmental Control Potential of Fluidized-Bed
Coal Combustion Systems. (Presented at the Second Seminar on Desul-
furization of Fuels and Combustion Gases. Washington, D.C. Novem-
ber 11-20, 1975.)
2. Archer, D. H., D. L. Keairns, J. R. Hamm, et al. Evaluation of the
Fluidized Bed Combustion Process. Volume I, Summary Report. Westing-
house Research Laboratories. Prepared for U.S. Environmental Pro-
tection Agency, Research Triangle Park, North Carolina. Publication
Number APTD 1165, PB 211 494. November 1971.
3. Keairns, D. L., D. H. Archer, E. J. Vidt, and E. F. Sverdrup. Evalua-
tion of the Fluidized Bed Combustion Process. Volume III.
Westinghouse Research Laboratories. Prepared for U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina. Publica-
tion Number EPA-650/2-73-048c. December 1973.
4. Environmental Impacts, Efficiency, and Cost of Energy Supply and End
Use, Volume II. Hittman Associates. National Technical Information
Service, Washington, D.C. Publication Number PB 239 159. January 1975.
25
-------
5. Steam Electric Plant Construction Cost and Annual Production Expenses.
Federal Power Commission, Washington, B.C. Publication Number FPC-S-
237. April 1974.
6. Energy Conversion From Coal Utilizing CPU-400 Technology. Combustion
Power Company Contract No. 14-32-001-1536. Office of Coal Research,
Washington, D.C. R&D Report No. 94 - Interim Report No. 1. January
1975.
7. Keairns, D. L., et al. Fluidized-Bed Combustion Utility Power Plants -
Effect of Operating and Design Parameters on Performance and Economics.
Proceedings of Third International Conference on Fluidized-Bed Com-
bustion. U.S. Environmental Protection Agency, Washington, D.C.
Publication Number EPA-650/2-73-053. December 1973.
8. Multicell Fluidized-Bed Boiler Design, Construction and Test Program.
Pope, Evans and Robbins, Inc. Contract No. 14-32-0001-1237. Publica-
tion Number PB 236 254/AS, Office of Coal Research, Washington, D.C.
R&D Report No. 90 - Interim Report No. 1. August 1974.
9. Robison, E. B., et al. Study of Characterization and Control of
Air Pollutants From a Fluidized-Bed Combustion Unit - The Carbon
Burnup Cell. Pope, Evans and Robbins, Inc. Prepared for U.S.
Environmental Protection Agency. Publication Number APTD 1170.
February 1972.
10. Energy Users Report. August 7, 1975.
11. Hoke, R. C., et al. Exxon Research and Engineering Company, Linden,
N. J., Proceedings of EPA Symposium on Particulate Control In Energy
Processes, U.S. Environmental Protection Agency. Report No. EPA-600/
7-76-010. 1976.
12. Reduction of Atmospheric Pollution, Volume I-III. National Coal Board,
London, England. Fluidized Combustion Control Group. U.S. Environmental
Protection Agency. Publication Numbers APTD 1082, APTD 1083, APTD 1084.
September 1971.
13. Hoke, R. C., et al. Exxon Research and Engineering Company, Linden,
New Jersey. Private Communication.
14. Smith, J. R., J. R. Hamm, D. L. Keairns. Pressurized Fluid Bed
Boiler Power Plant Operation and Control. Combustion. January
1975.
15. Surprenant, N., R. Hall, S. Slater, T. Susa, M. Sussman, and C. Young.
Preliminary Emissions Assessment of Conventional Stationary Combustion
Systems. Volume II - Final Report. GCA/Technology Division, Bedford,
Massachusetts. Prepared for U.S. Environmental Protection Agency.
Publication No. EPA-600/2-76-046b. March 1976.
26
-------
16. Effluent Guidelines and Standards for Steam Electric Power Generating
Point Source Category. Fed Regist. October 8, 1974.
17. Heist, J. A., R. H. VanNote, J. W. Kluesener. A Demonstration of the
Use of Properly Treated Sewage for Cooling Water at Fifteen Cycles of
Concentration. (Presented at the Second National Conference on Water
Reuse. Chicago, Illinois. May 1975.)
18. Steam. New York, Babcock and Wilcox. 1972.
27
-------
SECTION IV
POTENTIAL POLLUTANTS FROM A COAL-FIRED FLUIDIZED
BED COMBUSTOR
INTRODUCTION
As mentioned earlier in Section III, the fluidized bed combustion system
has been categorized into the major unit operations or activities listed
below:
Fluidized bed combustion
Limestone regeneration
Solid waste disposal
Fuel storage and handling
Coal drying
Cooling operations.
Potential pollution problems from each of these operations are discussed
here as separate subsections. The major emphasis has been on analyzing
the fluidized bed combustion unit and to a lesser extent, the limestone
regenerator. These are the operations which are unique to a fluidized bed
combustion system. In a sense, the solid waste disposal associated with
fluidized bed combustion may also be a unique operation in that the leach-
ing properties of the ash may be different than that from conventional sys-
tems, but to date, there is relatively little data available in this regard,
The environmental hazards which may result from fuel storage, coal drying,
and cooling should differ very little from those also encountered in con-
ventional combustion systems.
28
-------
FLUIDIZED BED COMBUSTION
Since S09 and NO formation in coal-fired fluidized beds has been exten-
£* X
sively investigated by the U.S. Environmental Protection Agency; Exxon;
Argonne National Laboratory; Pope, Evans and Robbins, Inc.; Westinghouse;
Battelle; and BCURA; among others, the primary interest here was the so-
called "other" pollutants namely, organic compounds, trace elements,
inorganic compounds (other than S00 and NO ), and particulates. Based on
Z X
available data and/or simple thermodynamics and chemical experience,
estimates have been made of the concentrations of various elements and
compounds in either the flue gas or the solid waste. In general, the
estimates for the trace elements and particulates are probably good to
within an order of magnitude, while those for the organic compounds are
probably good only to within two orders of magnitude.
Trace Elements
Trace elements and their compounds are of concern because some of these
materials can vaporize and exit with the flue gas. Because vaporized
trace elements would be in the gas phase, they would not be captured by
particle collection devices.
There is also concern about the enrichment of trace elements on fine
particles in combustion processes. Studies have indicated that certain
elements can concentrate in selected size ranges of particulates.1"3
For some elements, such as lead and cadmium, these sizes tend to be less
than a few microns in diameter. Such small particles are of special en-
vironmental concern because they are difficult to remove from the flue
gas and, once emitted, they can be readily embedded in the lung.
*
Numbers refer to references at the end of Section IV, page 62,
29
-------
In addition, trace elements in the solid residue from the process could
present a leaching problem. This possibility is discussed in a later sub-
section on solid waste disposal.
To assess the importance of trace element emissions in coal-fired fluid-
ized bed combustion, a "worst case" analysis approach was used. For both
bituminous and lignite coals, ranges for the heat content and the concen-
tration of trace elements were obtained. Assuming that all of the elemental
material would exit with the flue gas as either a vapor or a particulate,
a "worst case" emission factor was calculated (lbs/106 Btu/hr) using the
lowest heating value and highest trace element content of the coals.
(Calculations to be described later in this section indicated that the
trace element contribution from the limestone sorbent is insignificant.)
Based on this emission factor, stack gas concentrations were calculated
and diluted by a factor of 103 to account roughly for dispersion in the
atmosphere. These "ambient" concentrations were then compared to indus-
trial hygiene threshold limiting values (TLVS). Although industrial
hygiene threshold limiting values cannot be used to assess the absolute
environmental impact of pollutants, they do provide a useful framework
in which pollutants can be rank ordered according to their toxicity. Any
element whose predicted "worst case" ambient concentration was within a
factor of 100 of the industrial threshold limiting value was considered
to be potentially harmful. This safety factor of 100 was arbitrarily
chosen to account conservatively for the effects of long-term exposure.
(Industrial hygiene limits are usually based on exposures to healthy adults
over an 8-hour period.) The results of this investigation suggested that
the following trace elements could pose potential environmental problems:
Be, As, Pb, Cr, V, Cl, U. But again, the results are based on worst case
estimates.
The evaluations from this study also suggested that in comparison with a
conventional coal combustion unit, fluidized bed combustion (FBC) might
reduce some trace element emissions. Therefore, the application of FBC
technology could present an attractive alternative for the control of some
30
-------
trace element emissions. The major parameters in FBC which will tend to
mitigate trace element emissions are expected to be:
Temperature - The range of combustion temperatures in
FBC is 700-1000°C, with most units operating between
800-900°C. In conventional combustion, temperatures
are of the order of 1650°C. Therefore, many of the
trace elements that oxidize, enrich, or vaporize in a
conventional system should be less active in a FBC unit.
Pressure - FBC units can operate at pressures as high
as 20 atm. High pressure can raise the melting and
boiling points of the trace element compounds and
therefore may potentially decrease air emissions.
However, no measurements have been undertaken to con-
firm this particular aspect of FBC technology.
Coal size - The coal size used in FBC is larger than
that used in conventional combustion. Therefore, fine
particulate emissions may be reduced.
Limestone sorbent - Limestone can modify trace element
emissions by acting as a sink for certain trace ele-
ments (e.g., Fe).
Trace Elements in Coal and Limestone and "Worse Case" Emission Rates -
Coal contains, at trace concentrations (-100 ppm or less), virtually all
elements below atomic number 92. For this discussion, it has been as-
sumed that the coals to be used predominantly in FBC are lignite and
bituminous coal. The ranges of concentrations of trace elements in
these coals in terms of lb/106 Btu are given in Tables 2 and 3. Included
in Tables 2 and 3 are the maximum emission factors calculated from the
lowest heating value of the fuel and the highest trace element content.
Because it is impossible to deal with all variations in trace element
concentration, this "worst case" emission factor will be used to determine
which trace elements may be of environmental concern. The concentration
range quoted spans 90 percent of the variations found in different seams.
Not all trace elements are included in Tables 2 and 3, because composition
data are not available for some elements.
31
-------
Table 2.
ESTIMATED TRACE ELEMENT "WORST CASE" EMISSION FACTORS
FOR BITUMINOUS COALa
Heat content, Btu/lb
Sulfur, lb/106 Btu
Moisture, lb/106 Btu
Nitrogen, lb/106 Btu
Ash, lb/106 Btu
Minor elements, lb/106 Btu
Al
Ca
Fe
Mg
K
Si
Na
Ti
Trace elements.
Amount x HT1* lb/106 Btu
Sb
As
Ba
Be
Bi
Bo
Br
Cd
Cl
Cr
Co
Cu
F
Ph
Mn
Hg
Mo
Ni
Se
Te
Th
Sn
U
V
Zn
Xr
Average
12,000
1.67
0.33
1.08
11.67
1.42
0.25
1.55
0.06
0.16
2.62
0.04
0.04
0.42
25
83.33
2.08
0.08
41.67
12.5
0.33
1250.0
11.67
3.33
10.83
66.67
7.50
41.67
0.17
3.33
11.67
2.50
0.25
0.08
0.83
12.50
25.00
6.67
41.67
Minimum
10,500
0.58
2.50
0.83
4.17
0.44
0.10
0.29
0.01
0.04
0.69
0.03
0.01
2.50
< 33.33
0.50
3.33
3.33
0.42
2.50
8.33
3.33
3.33
0.06
0.33
1.67
8.33
1.67
< 0.83
Maximum
14,500
3.75
15.0
1.33
20.83
4.31
5.33
6.42
0.50
0.69
6.66
0.46
0.62
50.00
> 150
6.67
166.67
41.67
8.33
33.33
158.33
11.67
75.00
0.42
7.50
33.33
66.67
38.33
41.67
"Worst case"
emission factor
(no emission control)
4.29
17.14
1.52
23.81
4.92
6.09
7.33
0.57
0.79
7.6
0.53
0.70
57.14
171.43
7.62
190.48
47.62
9.52
38.09
180.95
13.33
85.71
0.48
8.57
38.09
76.19
66.67
47.62
Values taken from references 4 through 11.
32
-------
Table 3. ESTIMATED TRACE ELEMENT "WORST CASE" EMISSION FACTORS
FOR LIGNITE3
llo;it concent, Btu/lh
Sulfur, U>/)0(' Btu
MolHturi!, l.b/1.0f' Btu
Nitrogen, lb/10fl Btu
Ash, Ib/I0r> Btu
Minor elements, lb/106 Btu
Al
Cn
Fe
Mg
K
SI
Nn
Tl
Trace, elements.
Amount x 10~ ' lb/1.06 Btu
Sb
As
Bfi
Be
Bi
Bo
Br
Cd
Cl
Cr
Cn
Cu
F
Pb
Mn
Hg
Mo
Ni
Se
Te
Th
Sn
U
V
Y.n
Zr
Average
6,900
1.01
50.72
1.45
14.49
1.15
3.31
0.92
0.78
0.08
1.55
1.61
0.04
0.58
11.59
405.79
2.17
0.14
173.91
0.29
1449 28
10.14
4.35
21.74
86.96
10.14
55.07
0.16
2.46
10.74
1.88
0.16
< 0.14
1.3
217.39
23.19
17.39
14.49
Minimum
6,300
0.29
28.99
0.72
7.25
0.46
1.85
0.15
0.39
0.017
0.61
0.03
376.81
0.14
115.94
72.46
4.35
1.01
4.35
43.98
0.10
0.14
2.17
0.14
72.46
7.25
0
Maximum
7,500
4.35
57.97
2.17
21.74
3.0
8.0
5.17
1.83
0.23
4.09
4.83
434.78
5.80
289.86
2898.55
28.99
10.1
23.19
66.67
0.13
4.93
21.74
8.12
347.83
43.48
"Worst case"
emission factor
(no emission control)
4.76
63.49
2.38
23.81
3.28
8.79
5.67
2.0
0.26
4.48
5.21
476.19
6.35
317.46
3174.60
31.75
11.3
25.40
73.02
0.14
5.40
23.81
8.89
380.95
47.62
V;iJuc.s taken from references 4 through 11.
33
-------
The use of limestone or dolomite also adds to the trace element loadings
in FBC. However, there are very few analyses available of trace elements
contained in the sorbents used in FBC. Table 4 contains data for repre-
sentative types of dolomite and limestone. Also given in Table 4 is the
average trace element content of the fuels. The data show that the trace
element concentration of limestone is generally equal to or less than that
of the coal feed. The mole ratio Ca:S for most FBC processes will be
about 2. Because the coal sulfur content will be approximately 3 percent
by weight, one is dealing with weight ratios of coal to limestone on the
order of 13 to 1. Therefore, trace element loadings from the limestone
sorbent should be small compared to the fuel. Furthermore, because trace
elements in the sorbent are contained in a limestone matrix as the fairly
unreactive oxide or carbonate, they will probably have much lower emis-
sion factors than the more volatile forms of trace elements (such as sul-
fides) encountered in coal.
Geochemical Classification of Elements in Coal - There have been very few
studies performed of trace element emissions from FBC of coal. Therefore,
to estimate these emissions, a comparison with trace element behavior in
conventional combustion is useful. The primary concern is to identify
which trace elements will be emitted as vapors and which will be enriched
on small particulates. One can use as a basis for these predictions a geo-
chemical classification of elements.12 This classification scheme has been
used successfully in predicting the emissions from the Allen Steam Plant.2
Element volatilities and enrichment behavior have also been determined on
the basis of elemental or oxide boiling points.
In the geochemical scheme, trace elements in coal are separated into four
classes: I. lithophile, II. chalcophile, III. volatile elements, and
IV. unclassed elements exhibiting the properties of either Class I or II.
Trace elements in each class are listed in Table 5.
34
-------
Table A. TYPICAL VALUES OF TRACE ELEMENTS
IN LIMESTONE AND COAL
(ppm)
Element
As
R/i
Be
Br
Cd
Ce
Cu
Cr
Cs
Dy
Eu
Fe
Hf
Hg
K
La
Mn
Na
Ni
Rb
Pb
Sb
Sc
Se
Sm
Sr
Ta
Te
Tb
Th
Yb
Zn
U
V
Argonne
dolomite3
1.9h
5h
2C
2C
14b
0.9C
5.(> x 103 3
4.6 x 103 b
3.4a
55a
368a
1.5a
Tymochtee
dolomiteb
0.566 ± 0.17
6.75 ± 1.4
1.03 ± 0.21
4.23 ± 0.85
0.439 ± 0.091
0.0598 ± 0.013
3240 ± 650
2180 ± 440
42 ± 8.4
303 ± 61
12.2 ± 2.5
0.0527 ± 0.015
0.952 ± 0.19
0.658 ± 0.13
130 ± 29
2:81 ± 0.63
0.58 ± 0.12
2.23 ± 0.45
Limestone0
< 6
30-300
< 2
< 0.3
< 0.3
< 3
< 2
< 20
< 0.06
< 1
200-2000
100-1000
0.3-3
6-60
10-100
< 6
< 2
< 3
< 0.3
< 0.3
< 3
< 1
100-1000
. < 0.3
< 0.2
< 30
< 0.6
0.06-0.6
Llgnited
8
280
1.5
0.2
3
7
6344
0.1
551
38
1 x 104
7
7
0.4
1.3
0.11
< 0.1
12
150
16
Average
or typical
bituminous^
30
100
2.5
15
0.4
4
14
1.86 x 10*
0.2
1927
50
481
14
9
0.5
3
0.3
0.1
8
15
30
Reference 13.
Reference 14.
'Kefercnce 15.
References 4 through 11.
35
-------
Table 5. THE SEPARATION OF ELEMENTS IN THE GEOCHEMICAL
CLASSIFICATION SCHEME12
Class I
Al Mn
Ba Rb
Ce Sc
Co Si
Eu Sm
Fe Sr
Hf Tu
K Th
La Ti
Mg
Class II
As
Cd
Cu
Ga
Pb
Sb
. Se
Zn
Class III
Hg
Cl
Br
F
Class IV
Cr
Cs
Na
Ni
U
V
Trace elements listed in Class I are lithophiles and are associated with
aluminosilicate minerals in coal. As such, they are high boiling com-
pounds and do not decompose on combustion. They usually melt and coalesce
to form the fly ash and slag. Elements in this class are not enriched
during combustion.
Class II elements are generally present in coal as sulfides. These sul-
fides themselves may be fairly volatile or, upon combustion, the sulfides
decompose and the elements themselves are produced in the vapor phase.
These volatile sulfides or elements can then condense on the extensive
surface area presented by particulates thus leading to a surface enrich-
ment. This enrichment is usually most prevalent in the fine particle
fraction (i <_ 3 urn) of the total particulate loading. Generally, elements
could be placed in Class II if:
Enrichment factor = (x) fly ash/(x) fuel > 3
(EF)
where (x) is the concentration in weight percent.
Class III elements boil below the furnace and flue gas temperatures and
can exit from the stack as vapors.
36
-------
Of the Class IV elements, only Cr and Ni tend to show chalcophile (or
volatile) characteristics.
Fate of Trace Elements in FBC - There have been several studies of the
behavior of trace elements in FBC. The most complete study has been
performed on Argonne National Laboratory's bench scale pressurized com-
bustor. ' ' Trace element studies have also been initiated at
Exxon's pressurized bench scale combustor.ll+ Table 6 is a comparison of
Exxon's and Argonne's results, and the agreement is encouraging.
Table 6. COMPARISON OF EXXON AND ARGONNE DATA
ON TRACE ELEMENT RECOVERIES3
Element
As
Br
Fe
K
Mn
Na
Sc
Recovery , %
Exxon
86
no data
80
75
96
88
85
Argonne
85
18
100
90
130
96
97
Recovery = percentage of element entering
combustor that can be accounted for in solids
leaving combustor.
Based on their bench scale tests, workers at Argonne as shown in Table 7,
have indicated that FBC, compared to conventional combustion, has a pro-
pensity for reducing trace element emissions.16
Argonne has also performed several experiments to determine the vola-
tility of trace elements during coal ashing. These experiments involve
subjecting a previously formed low temperature ash to elemental analysis
after exposure to successively higher temperatures. Their results
37
-------
indicate that Fe, Al, Na, K, Mg, Ca, Ti, Zn, Mn, Ni, Co, Cu, Cr, Li,
and V all remain in the ash at FBC temperatures which suggests that,
if enrichment or volatilization of these elements does occur, it must
result from reactions of compounds in the coal and not the ash. Caution
is required, however, in extrapolating these results to larger systems
because the heating rates may not be typical of those encountered in
commercial combustion systems.
Table 7. PROJECTED ATMOSPHERIC EMISSIONS OF TRACE ELEMENTS
FROM CONVENTIONAL AND FLUIDIZED BED COMBUSTORS
EXPRESSED AS A PERCENTAGE OF THE ELEMENT ENTERING
THE SYSTEM16
Element
Hg
F
Br
As
Pb
Be
Sc
Cr
Co
Na
K
Fe, La, Mn
Conventional combustion3
90
90-100
(estimated)
100
(estimated)
50-60
0-60
Not available
10
0
10-20
20
30
0
Fluidized bed combustion
80
40
65
15
0-20
20-40
0
25
0-20
5
10
0
Projected from data in the literature on trace element emis-
sions from conventional power plants - see reference 16 for
further references.
"Worst Case" Emission Factors - The preceding discussions indicate that
elements in Class I should not be enriched or volatized during FBC or
conventional combustion. Therefore, using the "worst case" emission
factors (i.e., all of the trace element in the feed is emitted to the
38
-------
stack as particulate) from Tables 2 and 3 and an assumed collection effi-
ciency of 99 percent for a particulate control device (e.g., an electro-
static precipitator or fabric filter), pollutant loadings at the top of a
stack can be calculated for the trace elements in Class I. The results
of this calculation are presented in Table 8.
The emission rates in Table 8 have then been divided by 1000 to account
for atmospheric dilution. To assess the environmental impact of these
estimated ambient concentrations, occupational hygiene threshold limiting
*
values (TLV) are used. As shown in Table 8, these are arbitrarily divided
by 100 to provide an environmental index which accounts for long-term
exposure. While these cannot be used to assess the absolute environmental
impact of pollutants, they do provide a useful framework in which pollu-
tants can be rank ordered according to their degree of toxicity. The
minor elements present in coal, with the exception of Na, are all in
Class I and therefore are not enriched or vaporized in FBC; hence, it can
be concluded that FBC of coal should present no problems for atmospheric
trace element emissions of Class I elements.
Trace element emissions for elements in Classes II, III, and IV are more
difficult to predict because of their possible volatility which could lead
to vapor phase emission which escape through a particulate control device
or to enrichment on fine particulates which are less efficiently collected.
Table 9, for example, which provides cut-off data on the boiling points of a
number of compounds which could either be contained in coal, or formed as
combustion intermediates, can be used to provide some insight on the par-
titioning of elements between the solid (ash) and vapor phase. Table 10
presents "worst case" emission estimates for Class II, III, and IV elements
calculated in the same manner as the Class I elements shown earlier in
Table 8. Because of the potential volatility of these Class II, III, and
*
American Conference of Governmental Industrial Hygienists Threshold
Limiting Values.18
39
-------
Table 8. COMPARISON OF ESTIMATED TRACE ELEMENT CONCENTRATIONS
(CLASS I ELEMENTS) WITH AN ENVIRONMENTAL INDEX BASED
ON THRESHOLD LIMITING VALUES
Element
Al
Ba
Ca
Ce
Co
Eu
Fe
Hf
K
La
Mg
Mn
Rb
Sc
SI
Sn
Sr
Ta
Th
Ti
A
Emission factor after
control device
(assuming 992 control
of particulates)
Bituminous3
72.4
0.25
89
0.04
0.01
1.4 x 10"3
108
5.6 x 10"3
11.6
0.052
8.4
0.1
0.21
0.03
112
0.003
0.03
0.0003
0.0001
10.3
Lignite0
48.31
0.70
129
0.02
0.01
2.8 x 10"4
84
5 x 10"4
3.8
0.004
29.5
0.1
0.002
0.01
66
0.01
0.66
0.0002
1.6
B
Estimated ambient
concentration :
(A/1000)
Bituminous
0.075
2.5 x 10"4
0.089
_C
4 x 10 3
1 x 10"5
1.4 x 10"5
0.108
5.6 x 10"5
11.6 x 10"3
5.2 x 10"5
0.008
0.001
2.1 x ID'4
3 x 10"5
0.11
3 x 10"6
3 x 10~5
_7
3 x 10 '
1 x KT7
0.01
Lignite
0.048
7.0 x 10"4
0.129
_5
2 x 10
1 x 10"5
2.8 x 10"6
0.084
5 x 10"6
3.8 x 10~3
4 x 10'6
0.03
0.001
2 x 10'6
1 x 10"5
0.06
1 x 10~5
6.6 x 10~4
2 x 10"7
0.001
C
Environmental
index
(TLV/1000)
5 x 103
0.05
1 x 10"3
- .
0.15
0.005
-
0.10
0.05
-
-
0.1
0.02
-
0.05
1 x 10"3
0.1
D
Ambient concentration/
(D >, 1.0 indicates a potential
environmental problem)
Bituminous
_
0.05
1.8
0.01
-
0.72
0.01
_
-
0.08
0.02
-
1.0
0.0002
-
-fi
6 x 10 °
1 x 10~4
0.1
Lignite
. _
0.14
2.6
0.01
-
0.56
0.001
_
-
0.3
0.02
-
1.6
0.0005
_
2 x 10~4
0.01
''Based on References 4 through 11.
40
-------
Table 9. BOILING POINTS OF COMPOUNDS OFTEN FOUND IN COAL
Boiling or sublimation points
< 1000°C
Boiling or sublimation points
> 1000°C
A1C1
Sb2o5
BeCl2
Cr(CO)6
Co(CO),
o
CuS
FeCl3, Fe(CO)5
PbCl0
Hg, HgCl3
MoS,,
Ni(CO)4, NiCl2
Se02> SeCl4, Se,
Sb203, Sb2E
BeO
CrCl3
CoCl2
Cu-O, CuCl
FeCl , FeO
Pb.p,, PbS
NiO
BaO, BaCl2
CdS, CdO
CaO,
MgO,
MnCl
KC1,
NaCl
V2°5
-------
Table 10. COMPARISON OF ESTIMATED TRACE ELEMENT CONCENTRATIONS (CLASS II ELEMENTS) WITH AN
ENVIRONMENTAL INDEX BASED ON THRESHOLD LIMITING VALUES
Element
Class II
As
Cd
Cu
Pb
Sb
Se
Zn
Be
Class III
Hg
Cl
Br
F
Cr
Ni
U
V
A
Emission factor without controls
(rae/m3)8
(combined vapor and particulate)
Bituminous
8.42
0.04
5.61
2.0
0.06
0.4
7.0
1.1
0.07
184
1.8
27
7.0
5.6
11 .'2
9.8
Lignite
1.70
. 0.04
3.74
1.5
0.02
0.3
5.4
1.0
0.02
476
-
13
4.7
' 3.5
56.1
7.0
15
Ambient concentration :
(A/1000)
Bituminous
8.42 x Uf 3
0.04 x 10"3
5.6 x 10" 3
i
2 x 10 J
6 x 10"5
0.4 x 10"3
\
7.0 x 10 J
1 x 10~3
\
0.07 x 10 J
0.18
1.8 x Kf3
0.027
7.0 x 10"3
5.6 x 10~3
0.01
9 x 10~3
Lignite
1.70 x 10"3
0.04 x 10"3
3.8 x 10"3
_Q
1.5 x 10
2 x 10"5
0.3 x 10"5
_!
5.4 x 10 J
1 x 10~3
i
0.02 x 10 J
0.48
-
0.013
4.7 x 10"3
3.5 x Kf3
0.06
7 x 10"3
C
Environmental
Index frog/in-')
(TLV/103)
0.005
0.0005
0.01
0.0015
0.005
0.2
0.05
2 x 10"5
*,
5 x 10 *
0.03
0.007
0.02
0.01
0.01
0.002
0.005
D
Ambient concentration/
environmental Index
D ^ 1 indicates potential problem
Bituminous
1.7
0.08 .
0.6
1.3
0.01
0.2
0.1
50
0.04
16
0.2
1.35 '
0.7
0.5
5
2
Lignite
0.3
0.08
0.4
1.0
0.004
0.2
0.1
50
0.04
16
-
0.65
0.5
0.4
30
1.4
E
Degree of control required
to make D <_ 1.0
Bituminous
60%
0
0
20%
0
0
0
98%
0
85%
0
26%
0
0
80%
50%
Lignite
0
0
0
0
0
0
0
98%
0
94%
-
0
0
0
97%
29%
For comparison, 1m of air equals approximately 10 mg.
-------
IV elements, no degree of control can be suggested a priori based on total
particulate. Accordingly, we have indicated the degree of control that
would be necessary to reach an acceptable environmental index as defined
in the table.
Based on the "worst case" analysis, the elements listed below could be of
concern. The key question is in what chemical form will these elements
appear in either the combustion bed or in the flue gas. Where information
of this type is available, it has been indicated.
Arsenic (As)
The volatility of As depends on the Ca content of the
coal. With a large Ca content, As may be bound as
the arsenate/arsenite and not volatized as AS20-J.1
This is the reason for the high retention of As when
using a limestone/dolomite sorbent. On the basis
of the emission factor for As in Table 10, however,
As could still be emitted in harmful quantities. For
example, in the case of bituminous coal, the uncon-
trolled emission factor is equivalent to approximately
10 ppm As (by weight).
Beryllium (Be)
Be is highly toxic (TLV = 0.002 mg/m3). Its behavior
in FBC is not yet understood. Argonne data suggest
that beryllium is not enriched;16 however, as shown
in Table 10, there is some evidence that some Be
could exist in the gas phase. BeCl2 boils at 519°C;18
hence, if Be is present as the chloride, it could
vaporize. Therefore, mass balances of Be should be
of high priority in FBC systems. Uncontrolled emission
factors could be as high as 1 ppm Be by weight as
indicated in Table 10.
Lead (Pb)
In conventional combustion lead is definitely enriched
in fine particulates.23 Pb02 is not stable at combus-
tion temperatures (decomposes at 288°C). PbO is stable
to 882°C, but its vapor pressure is low (< 10 mm Hg).20
PbC03 decomposes at 316°C.20'22 Pb may exit as elemental
lead, PbS, PbCl2, or
43
-------
Nickel (Ni)
Ashing experiments suggest that nickel is not volatized
at FBC temperatures.1' The presence of highly toxic
nickel carbonyl is possible because of the high CO con-
tent in FBC flue gas. Its presence has been postulated
in conventional combustion.21* Because the suggested
atmospheric limit for the control of exposure to nickel
carbonyl is quite low, 0.3 ppb (2.1 yg/m3),25 nickel
carbonyl should be studied experimentally.
In fluidized bed gasification experiments, it has been
found that 75 percent of the Ni in the fuel is tied up
in the stone.2° Similar data are not available for coal
combustion.
Uranium (U)
Thermodynamic data show the oxide to be the stable form.22
Uranium is not volatized in conventional combustion but
there are no data on enrichment factors. Because of the
concentrations of U in lignite coal, its pathways in FBC
should be checked experimentally. As indicated in Table 10,
uncontrolled emission rates could be as high as 11 and 56 ppm
in bituminous and lignite coals respectively.
Vanadium (V)
The enrichment of V is small for conventional combustion,
and hence should not be of concern in FBC. Thermodynamic
data show that the oxide form is favored over the sulfate.22
In gasification experiments, Westinghouse has found 100 per-
cent retention of V on the spent limestone. This V concen-
tration in the stone can range up to 1 weight percent.26
This phenomenon should be studied for coal combustion.
Halogens; Fluorine, Chlorine, Bromine
Argonne has shown that F is captured by the limestone/
dolomite bed by demonstrating that F retention was 5 to
23 percent with sorbent present. It is probably captured
as CaF2 (m.p. 1360°C).20
Cl may be trapped as CaCl2 (bp 1593°C). Chlorine will
be emitted in the exhaust gas as HC11*3 and possibly in the
form of NaCl. However, HC1 emissions have not been noted
at high concentrations. British studies show that Cl~
content of the exhaust gas is 20 ppm (W/W).2^
44
-------
Br may be captured in the bed as CaBr2 (bp 806°C). Its
lower boiling point could explain the higher emission
factor noted by Argonne for Br than F.
Influence of Selected Process Options on the Fate of Trace Elements -
This section discusses process variations and their possible effect on
trace element emissions. Because this is not a well documented area,
most of the discussion comprises recommendations for further research.
Pressure and Temperature
Pressurized FBC could modify trace element behavior.
The vaporization of various elements or compounds
could change significantly as pressure is increased.
These changes could result from phenomena such as
boiling point suppression, or shifts in chemical
equilibrium concentrations. The difference in potassium
loadings from the Argonne and British experiments may
be a manifestation of the effect of pressure.
Carbon Burn-Up Cell (CBC)
Fly ash from the fluidized bed can contain as much as
20 percent unburned carbon. In some FBC designs, fly
ash from the cyclones in the flue gas system will be
returned to a carbon burn-up cell (CBC). The CBC can
affect trace metal emissions because, it operates at a
higher temperature than the fluidized bed (1093°C ver-
sus 816°C).
At the higher temperature it is expected that some of
the more active trace elements (Hg, Cl, Se, etc.) will
be revolatilized or those in the unburned fly ash
volatilized.
Gaseous Organic and Inorganic Compounds
Data on the specific organic or inorganic compounds formed during coal com-
bustion are scarce. Analysis of combustion gases is usually limited to
species such as C0> C09 , S09, NO and, in some cases, total hydrocarbons.
^ £. X
In addition to these combustion "end products," however, an extremely wide
variety of other organic compounds could also form - especially during
-------
transient operating conditions which often foster incomplete combustion.
Predicting these .products in the case of coal combustion is a difficult
task. Detailed thennodynamic or kinetic calculations are of limited value
because, for the most part, the actual reacting species are a matter of
speculation and the extent to which true equilibrium is attained is often
questionable. Some insight into potential organic pollutants, however,
can be gained on the basis of a simple coal combustion model, the present
understanding of chemical reactions in fluidized beds, and some simple
thermodynamic calculations.
Simple Combustion Model - Conceptually, the combustion of a coal particle
can be viewed in two steps as shown in Figure 4.
VOLATILE
HYDROCARBONS
COMBUSTION OF
VOLATILE SPECIES
(0.1-0.3 sec.)
COMBUSTION OF
SOLID CHAR
(1-3 sec)
Figure 4. Schematic representation of coal combustion
46
-------
In step I, volatile hydrocarbons are ejected from the coal particle;
they mix with oxygen and burn in a cloud surrounding the particle. Both
31 32
theoretical and experimental evidence indicate that this first step
is completed in several tenths of a second or less. After devolatiliza-
tion is complete, oxygen molecules attack the remaining char in step II,
with burning here usually completed in times on the order of several
seconds. The solid char in step II is predominantly carbon, although
33
Sternling and Wendt indicate that much of the chemically bound nitrogen
in coal also winds up in the char. This char nitrogen probably burns to
form NO, although the combustion mechanisms for heterogeneous combustion
of nitrogen are not nearly as well studied as those for carbon. The
main reaction product from heterogeneous carbon combustion is CO. The
CO subsequently burns within the bed or in the freeboard to form C0«.
Some of these char particles are ejected from the bed but they are
captured by the flue gas cyclones and returned for combustion in the
carbon burn-up cell (CBC). Consequently, the crucial step for forming
the more complicated organic species would be step I.
Volatile Products From Coal Decomposition - Potential organic pollutants
can form because some of the products from step I could pass through the
bed either completely or partially unburned. To estimate the extent to
which this can occur, one must (1) determine the chemicals released from
coal devolatilization, and (2) estimate the extent to which they will
survive in a hot fluidized bed.
Figure 5 provides a convenient summary of the types of reactions that
occur during coal decomposition. Coal has no unique structure; generally,
it is viewed as a network of aromatic carbon compounds interspersed with
various heterocyclic compounds containing oxygen, nitrogen, or sulfur.
These heterocyclic compounds are less stable than aromatics and during
pyrolysis these bonds tend to break first, as shown in Figure 5.
47
-------
oH
Figure 5. Schematic representation of coal pyrolysis
. 34
-------
The product distribution in coal pyrolysis is temperature dependent. At
temperatures on the order of 900°C (similar to those proposed for fluid-
ized bed combustion) the predominant reactions are ring closures, con-
densation, and aromatization reactions. The main products tend to be
polynuclear ring compounds with occasional nitrogen, oxygen, or sulfur
34
substitution and simple compounds such as H?, H~S, NH~,
CH4, etc.
The overall synthesis of polycyclic organic compounds is shown schemat-
ically in Figure 6.35 Coal combustion can be a source of these com-
pounds36*37 since, as seen previously in Figure 5, many of the products
of coal decomposition are equivalent to the advanced stages of pyrene
synthesis, shown below. (The extent to which these compounds might escape
unaltered from the hot reaction zone of a fluidized bed will be discussed
in the next section.)
NAPHTHALENE
ICNZO(I) PTRCNE
Figure 6. Pyrolytic synthesis of B(a)P35
49
-------
During periods of start-up or shut-down, products from low temperature
pyrolysis might also be encountered in a fluidized bed. These compounds
tend to be single aromatic rings or heterocyclic compounds with alkyl
34
side chains. Examples shown below are substituted benzenes, phenols,
pyridines, thiophenes, quinolines, where R = CH
etc.
Using the above chemicals as starting materials, estimates can be made
of which classes of compounds might survive in the reactive environment
of a fluidized bed.
Combustion of Hydrocarbons - The predominant reaction of the volatile
hydrocarbons, of course, will be combustion; the main question is to
what extent combustion will be complete. As mentioned previously, both
theoretical and experimental evidence indicate that combustion of vola-
tiles will occur on the order of 100 ms. This is more than an order of
magnitude less than the residence time in the bed; hence, there is cer-
tainly ample time for complete combustion. However, phenomena such as
bubbling, slugging, uneven gas distribution, or localized reducing areas
near the points of fuel injection could produce oxygen deficient zones
from which unburned or partially burned hydrocarbons could escape. The
extent to which this will occur will depend on the boiler design and
could vary from reactor to reactor. Experimental tests indicate that
the amount of unburned hydrocarbon in the flue gas has a strong depen-
18
dence on the amount of 02 present. Some of the experiments are sum-
marized in Figure 7. Note that at 1 percent 0_ in the flue gas (5 percent
excess air), hydrocarbon concentrations are greater than 2000 ppm. With
50
-------
3000
E
o.
Q.
< 2500
o
UJ
ID
- 2000
z
a:
»-
£
z
o
o
UJ
z
1500
1000
O
CD
-------
0» flue gas concentrations on the order of 3 percent (17 percent excess
air), hydrocarbon concentrations are reduced to 50 ppm. It is important
to note, however, that these experiments were performed on a fluidized
bed module (FBM) designed primarily for investigating heat transfer
phenomena. The unit had a limited freeboard and was not necessarily
designed for optimum combustion conditions. Hence, the results may be
upper limits, but they do provide some insight into the generation of un-
burned hydrocarbons in FBC.
Products of incomplete combustion - Some insight as to the chemical com-
position of the products of incomplete combustion is provided below; the
next section indicates methods which can be used to estimate concentra-
tions of potential compounds.
Hydrocarbons
Fluidized bed reactors have long been used in the petroleum
industry to "crack" or thermally decompose high molecular
weight hydrocarbons. The process is shown schematically
below:
HOT SURFACE
(700-850°C)
In these reactors, sand is often used as the bed
material, sometimes with added catalysts such as
oxides of V, Ni, and Co. In some respects, a coal-
fired fluidized bed combustor may be similar to a com-
mercial cracker (including trace metals present as
catalysts) ; hence one might expect that most unburned
hydrocarbons would be extensively "cracked" by the
time they leave the bed. Theoretical estimates of
the first order rate constant for the cracking of a
hydrocarbon of molecular weight 225 indicate that
half the material will be cracked in 30 ms at 727°C.35
In some respects, this could be a significant advantage .
of fluidized bed coal combustion versus conventional
coal combustion. Coal-fired units (particularly small
industrial or residential units) are significant sources
of polycyclic organic compounds. In a fluidized bed, the
increased gas-solids contact may enhance the tendency for
these species "crack" to form compounds such as CH^, C2HA,
C2H6, etc. If, in fact, this is so, the probability of finding or-
ganic sulfur and nitrogen compounds such as thiophenes, mercaptans,
52
-------
carbazoles, etc. should also be very small. These
species will most likely decompose to form small
hydrocarbons and species such as t^S, HCN, and COS.
Pyridine, for example, decomposes readily at tempera-
tures on the order of 900°C to form HCN and hydrocarbons.33
Oxygenated Hydrocarbons
Organic chemicals, such as ethylene oxide, phthalic an-
hydride, naphthaquinones and aromatic carboxylic acids,
can also form via partial oxidation of hydrocarbons.
An example is shown below:
v2o
naphthalene
phthalic anhydride
These reactions, which are often used in organic syn-
theses, usually proceed only under very controlled
process conditions and at temperatures on the order of
200 to 400°C; hence, their occurrence in a combustor
operating around 900°C seems very unlikely. There could
be some possibility of their occurrence during start-up
and shut-down when temperatures are lower, but it seems
unlikely. A tentative identification of diphenylene
oxide in particulates from acetylene-oxygen and ethylene-
oxygen flames, however, has been recently reported.^0
Carbon Monoxide (CO)
Carbon monoxide forms in the bed, but it usually burns
there or in the freeboard to form C02. At 10 percent ex-
cess air, CO usually drops below 1000 ppm in atmospheric
pressure fluidized bed units and below 200 ppm in pres-
surized units. High CO levels usually indicate signi-
ficant gas-bypassing within the bed.
Soot
Fuel-rich conditions lasting for only a short period
of time can lead to the formation of a fairly signifi-
cant quantity of soot which can take a long time to
burn away again.1*1 Soot particles tend to be exceed-
ingly small and would not be collected by the cyclones
or the electrostatic precipitator.
53
-------
Carbides
It is also conceivable that metal carbides could
form in a fluidized bed combustor. Calcium carbide
(CaC2), in particular, is formed by heating lime
and carbon. Most carbides would not be volatile
at the prevailing temperatures; hence, they should
remain in the bed. If formed, they could present
problems upon disposal of the stone since carbides
release ^2^-2 uPon hydrolysis.
Halogenated Hydrocarbons
There is considerable chlorine content in coal itself
plus there are some indications that NaCl may be added
to fluidized beds to enhance SC>2 scrubbing;^ hence,
the possible halogenation of hydrocarbons must be con-
sidered. At temperatures encountered in a fluidized
bed combustor, however, chlorinated hydrocarbons most
likely will not be stable. The effect of chlorination
on the pyrolysis products of British coals has been
investigated^ and it has been found that at high tem-
peratures, chlorinated tars are not produced. Practi-
cally all of the chlorine appears as HC1.
Concentration Estimates of Organic and Inorganic Compounds - Equilibrium
calculations can be used to predict the composition of the combustion gases.
The most commonly used method is the minimization of the chemical system's
44
free energy. This method can provide useful concentration estimates
but is probably most useful for predicting trends or concentration
ratios. In the case of fossil fuel, one usually uses the elemental
composition as the starting material and the combustion products are
usually limited to simple molecules (3 atoms or less). Calculations
of this type have not been extensively applied to coal combustion, al-
45
though they have been used in coal gasification analyses. Because
gasification is essentially incomplete combustion of coal, these analy-
ses can be used to provide very conservative upper limits for the con-
centrations of "reduced" species such as COS, NH_, and H S which may be
present in combustion gases. Estimates based on gasification equilib-
rium calculations are shown in Table 11.
54
-------
Table 11. CALCULATED EQUILIBRIUM CONCENTRATION FOR
SELECTED SPECIES PRODUCED BY INCOMPLETE
COMBUSTION OF COAL45
Coal analysis: C - 68.5%, H - 5.3%, 0 - 8.5%,
N - 1.4%, S - 4.1%
Oxygen present: 59% of stoichiometric requirements
Temperature: 760°C
Species Mole fraction
N2 0.36
CO 0.28
H2 0.15
H20 0.06
co2 o.io
CH^ 0.06
H S C.008
COS 0.0005
NH3 0.0007
C(g), HCN, CS < lO'5
Crttirt 9 Crti
s2, so2,
NO, N02
V (CN)2
so3
As the amount of oxygen in the combustor is increased, the concentration
of "reduced" species decreases. The equilibrium calculations include a
mass balance for each of the elements; hence, an extrapolation of the
calculations to excess air levels on the order of 20 percent, where S0_
is approximately 500 ppm, indicates that compounds such as H-S, COS, and
CS2 should decrease by about two orders of magnitude. Similar considera-
tion sould apply to "reduced" nitrogen compounds; hence, a conservative
upper limit for the concentration of compounds such as H S, COS, CS^, S0»,
£» £3
HCN, (CN)9, and NHo» under typical combustion conditions, is 1 ppm, which
does not pose significant environmental problems.
55
-------
Free energy minimization calculations for the more complicated hydrocarbons
(e.g., polynuclear aromatics) are impractical because of the complexity
of the chemicals involved. To estimate the concentrations at which
these types of compounds might exist in the FBC flue gas, one can use
empirical correlations between benzo(a)pyrene and CH, concentrations
from measurements in conventional coal-fired combustion systems. Fig-
ure 7 indicates the variation of total hydrocarbons (as CH,) as a func-
tion of 0 concentration from one set of fluidized bed combustion ex-
38
periments. Under normal operating conditions, about 3 percent CL in
the flue gas (20 percent excess air), the concentration of hydrocarbons
(as CH,) is about 100 ppm (volume/volume - V/V). Although emissions
can often vary between different fluidized bed systems, 100 ppm provides
a convenient reference value. Previous measurements with conventional
coal-fired systems indicate that compounds such as benzo(a)pyrene are
typically 10 times less than the concentration of total hydrocarbons
46 47
as CH,, ' Using our reference value of 100 ppm (CH,), this implies
that in a fluidized bed system polynuclear aromatic hydrocarbons (PAH)
could exist in the flue gas at concentrations (V/V) on the order of
1 part per billion (ppb). Considering that flue gases are typically
diluted by about a factor of a thousand when they are emitted from the
stack, this implies that ambient concentrations of PAH near FBC facili-
ties would be on the order of 1 part per trillion. This corresponds to
about 0.6 ng/m which is roughly comparable to the natural background
46 47
concentration ranges found in rural areas. ' Accordingly, it seems
that polynuclear aromatic hydrocarbon concentrations should not be high
enough to cause problems.
Particulate Emissions
Only limited data on particulate emissions from fluidized bed combustion
are currently available.48"50 Preliminary data, using more sensitive
particle sizing techniques than used previously, indicate that the mass
median diameter of the flue gas particles (50 percent of the mass of the
56
-------
particles are above that size) is about 7 ym in a pressurized system. ***
This means that significant concentrations of fine particles could exist
in the flue gas. Further experiments on particle size distribution and
chemical composition as a function of particle size should receive high
priority. The following discussion summarizes currently available data on
particulate loadings in FBC.
Atmospheric Pressure Fluidized Bed Combustion (AFBC) - For the process
parameters shown below, Argonne Laboratories measured an average dust
loading leaving the secondary cyclone of 0.06 grains/scf and a maximum
loading of 0.22 grains/scf.
Flue gas flow rate: 8-14 cfm
Coal feed rate: 4-7.8 Ib/hr
Additive feed rate: 1.1-2.3 Ib/hr
Primary cyclone: 6-5/8 in. diameter
Secondary cyclone: 4-1/2 in. diameter
Dust loading (combustor exit): 0.16-1.78 grains/scf
Combined cyclone efficiency: Approx. 90%.
Figure 8 shows the particle size distribution obtained from these
experiments.
Experiments at the National Coal Board in England indicated dust loadings
of 0.1 to 0.6 grains/scf when using primary and secondary cyclones having
collection efficiencies of 90 percent at 10 ym.1*9 These experiments also
indicated that the particulate contained 5 to 15 percent carbon and
85 to 95 percent ash and additive.
Pope, Evans and Robbins made initial investigations of particle size dis-
tributions in FBC, as shown in Figure 9. In some of their experiments,
Nad (salt) was used as an additive to enhance S02 removal; the addition
of NaCl also affected the particle size distribution as shown in Figure 9.
No mechanism explaining the influence of NaCl on particle formation was
postulated.
57
-------
co
100
90
80
70
Ul u. - rt
o. < 60
Q.
ui < 50
5
ui z
li*°
SS 30
UJ
a:
o
20
10
PRIMARY CYCLONE
SECONDARY
CYCLONE
FILTER BAG
I l I I I I I I
I I I I I I I I
1000
100 10
PARTICLE SIZE , pm
Figure 8. Typical particle size distribution of elutriated material
collected in primary cyclone, secondary cyclone, and fil-
ter bag during period of additive injection48
-------
iooo
TEST 511 (NO SALT)
100
(A
w
O>
"S
o
u
i
LJ
N
V)
O
10
COLLECTED BY CYCLONE
IN EXHAUST
(UNDATED)
5 10 15 20 30 40 5060 70 8085 90 95
WEIGHT PERCENT SMALLER THAN STATED SIZE
98
Figure 9. Fly ash size distribution for Pope, Evans and
Robbins, Inc., atmospheric pressure fluidized
bed combustion (AFBC)1**
59
-------
At the FBC demonstration plant currently under construction in Rivesville,
West Virginia, Pope, Evans and Robbins will use a hot electrostatic pre-
cipitator to reduce particulate loading below the EPA limit of 0.04 grains
per scf (0.1 lb/10 Btu). A hot (approximately 316°C) electrostatic pre-
cipitator is used because the high carbon content (as high as 20 percent)
of the fly ash causes a high resistivity which makes operation of a cold
precipitator inefficient.
Pressurized Fluidized Bed Combustion (PFBC) - A comprehensive study of
the influence of selected process parameters on grain loadings in pres-
surized fluidized bed combustion was performed by workers at Argonne
National Laboratories.51 Their results for particulate loading as a
function of fluidizing gas velocity and as a function of Ca/S mole ratio
are shown in Figure 10.
The Argonne experiments indicated that, after passage through two cyclones,
the solids loading in the flue gas ranged from 0.3 to 2.1 grains/scf. By
adding a final filter, flue gas loadings were brought below 0.04 grains/
scf the EPA emission limit.
The above results suggest that particulate removal devices, in addition
to the process cyclones, normally used, will be required in order for
fluidized bed combustion to meet EPA particulate emissions standards.
As noted earlier, Pope, Evans and Robbins will use a hot electrostatic
precipitator at their demonstration plant in Rivesville, West Virginia.
Exxon is incorporating a granular bed filter in the pressurized mini-
plant which shows promise of reducing fine particulate loadings
substantially.
60
-------
ro
OC
o
CO
3
m
O
o
o
z
Ul
(9
UJ
O
o
28
26
24
22
20
18
16
14
12
10
8
? 6
o
<
o
2
0
TEMPERATURE : 788-899°C
EXCESS AIR :~I5% ( 3% 02 IN FLUE GAS )
FLUIDIZED - BED HEIGHT: 3ft
GAS VELOCITY , ft/sec:
O~2.0
D~ 3.5
A~ 5.0
I 2
Co/S MOLE RATIO
Figure 10. Solids loading of flue gas leaving the combustor
in Argonne National Laboratories pressurized
fluidized bed combustion (PFBC)13
61
-------
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zation. Environ Sci Technol. 8:441, 1974.
46. Hangebrauck, R. P., D. J. von Lehmden, J. E. Meeker. Emissions of
Polynuclear Aromatic Hydrocarbons and Other Pollutants from Heat
Generation and Incineration Processes. J Air Pollut Control Assoc.
14:267, 1964.
47. Hangebrauck, R. P., D. J. Von Lehmden, J. E. Meeker. Sources of
Polynuclear Hydrocarbons in the Atmosphere. U.S. Department of
Health, Education and Welfare. Publication Number PHS 999-AP-33.
1967.
65
-------
48. Vogel, G. J. et al. Fluidized Bed Combustion. Annual Report.
: Argonne National Laboratories. Publication Number ANL/ES-CEW-1001.
July 1968 - July 1969.
49. Reduction of Atmospheric Pollution (Via Fluidized Bed Combustion).
Volumes I-III. Final Report. National Coal Board, London, England.
Submitted to U.S. Environmental Protection Agency, Office of Air
Programs. Publication Numbers APTD-1082-1084. September 1971.
50. Multicell Fluidized Bed Boiler Design, Construction and Test Program.
Pope, Evans and Robbins, Inc. Publication Number PB 236 254/AS,
Office of Coal Research, Washington, D.C. R&D Report No. 90 - In-
terim Report No. 1. August 1974.
51. Vogel, G. J. et al. Reduction of Atmospheric Pollution by the Appli-
cation of Fluidized Bed Combustion and Regeneration of Sulfur-Containing
Additives. Argonne National Laboratories (ANL/ES-1007.) . Prepared for
U.S. Environmental Protection Agency. Publication Number EPA-650/2-74-
104. September 1974.
66
-------
SECTION V
POTENTIAL POLLUTANTS FROM AUXILIARY PROCESSES ASSOCIATED WITH
FLUIDIZED BED BOILERS
LIMESTONE REGENERATION
The purpose of this discussion is: (1) to describe the methods of re-
generating sulfated limestone produced in coal-fired fluidized bed com-
bustion; and (2) to discuss the effects of regenerator operating vari-
ables on possible pollutant formation. At present, both one- and two-
step processes are being considered; the one-step process can operate
at either atmospheric or higher pressure, while the two-step system is
associated with high pressure operations. Effluents from the regeneration
process include flue gas, particulate matter in the flue gas, spent stone,
and any emissions from the associated sulfur recovery plant. Leachates
resulting from disposal of the spent stone could also be important.
One-Step Regeneration
Calcium sulfate is reduced by CO and H via the following reaction:
CaS04 +2 + CaO + S0 + | 2U | . (1)
T21
[coj
The reaction proceeds rapidly at temperatures of about 1100°C and atmo-
spheric pressure. (Regeneration is generally carried out at temperatures
above 1100°C if operated under pressure (10 atm).)
67
-------
The off gases from the regenerator can be sent to a Claus Plant to pro-
duce elemental sulfur, a sulfuric plant or a scrubber. The following
reaction occurs in the Claus Plant:
+ S02 -» 2 H20 + 3S (2)
A portion of the sulfur can then be reacted with methane to produce H»S
which is reused in reaction (2) . Figure 11 provides an example of the
overall process flow for a one-step regeneration scheme based on a design
by M. W. Kellog. 1 Westinghouse Research Laboratories have also designed
a one-step regeneration scheme which is similar to that of Kellog, except
coal is used as the source of reducing gas for the regenerator, instead of
natural gas.2 (Natural gas is a cleaner fuel than coal and would be
expected to reduce the impact of any possible pollutants from regenerator;
however, in the future it is expected to become increasingly scarce and
possibly be unavailable for such applications.)
Two-Step Regeneration
The first step of this scheme involves the reduction of CaSO, to CaS with
CO and H-:
CaSO. + 4 w + CaS + 4 ""2
4 I I I
+ 4rc°2
LH2C
(3)
The reaction is generally carried out in the temperature range of 870 to
930°C and under high pressure. Calcium sulfide
is reacted with C0» and steam to produce CaCO.,:
930°C and under high pressure. Calcium sulfide produced via reaction (3)
CaS + C02 + H20 -» CaC03 + H2S . (4)
68
-------
RECYCLE FROM
"SULFUR PLANT
TO STACK
272.85 MPH
LIMESTONE
166
C0C03 98.57%
INERT 1.43%
FLUE GAS: 5161.84 MPH
FLY ASH : 1026
Y
COMBUSTOR
927°C V
152 psid
COAL
TOTAL AIR
11539
4.50 % S
4729.8 MPH
13728
12322 #/\\r
TO
CLAUS PLANT
219.79 MPH
Y
REGENERATOR
I093°C
40 psio
(153)
I47I°C
191.31 MPH
REDUCING
GAS
94
C00 97.48%
INERT 2.52 %
SPENT
STONE
39.44 MPH
AIR
118 MPH
NAT. GAS
LEGEND'
# POUNDS
MPH: MOLES PER HOUR
Figure 11. M. W. Kellog one-step regeneration scheme1
-------
Reaction (4) is usually carried out under pressure at temperatures of
540 to 710°C. Hydrogen sulfide can be further oxidized to produce S07
and/or elemental sulfur:
H.S + 3/2 0, + S00 + H00 (5)
or
2H2S + S02 -» 2H20 + 3S (Claus reaction) . (6)
Figure 12.shows a process flowsheet for a two-stage regenerator designed
by M. W. Kellogg.1 It illustrates the material flows involved; a similar
design has also been proposed by Westinghouse Research Laboratories.2
Potential Pollutants From Limestone Regeneration
Because the regenerator is also a fluidized bed, it will behave in the
same manner as the combustor with respect to operating variables. The
main differences between the fluidized bed boiler and the regenerator
is both the chemical nature of the reactants and the reaction conditions;
i.e., chemical reduction as opposed to combustion. The feed to the re-
generator will consist of CaO, CaSO,, coal ash, and a reducing gas. Pro-
posed sources of reducing gas have been natural gas or a mixture of CO,
H- and CH, from gasified coal (i.e., incomplete combustion of coal). The
use of natural gas should pose no significant environmental problems, but
the future availability of natural gas for this type of operation is
questionable, because of projected fuel shortages. The use of a "coal gas"
for the regenerator could pose environmental problems. In using coal,
especially under conditions of incomplete combustion, one has to be con-
cerned about potential pollutants such as: trace elements, polycyclic
aromatic hydrocarbons, fine particulates and inorganic compounds such as
NH3, H2S, COS, HCN, CN, CS2.
Some insight to fate of trace elements can be gained from equilibrium free
energy calculations. Reactions of trace elements will be considerably
70
-------
519.57 MPH
749.25 MPH
SULFATEO
SORBENT
FROM
COMBUSTOR
C0S04 16.28%
C00 81.60%
INERT 2.12%
1st STAGE
REGENERATOR
727°C
153 psio
NG
AIR-
GAS
PRODUCER
749.08 MPH
749.25 MPH
46°C
144 psio
C02
ENRICHER
III.9 MPH
SOLIDS
12389
C00 88.39%
CaS 9.31 %
INERT 2.30 %
95.9 MPH
2nd STAGE
REGENERATOR
527°C
ISO psio
REGENERATED
SORBENT
TO *
12733 ^/hr
COMBUSTOR
CaC03 12.45%
C00 85.35%
STACK
5019.22 MPH
/LESS FLYASHN
\!027#/hr J
FLUE GAS
FROM
COMBUSTOR
AIM
CLAUS
PLANT
STEAM
131.36 MPH
COMBUSTOR
NG AIR
SPENT
STONE
LEGEND:
#: POUNDS
MPH : MOLES PER HOUR
Figure 12. M. W. Kellog two-stage regeneration scheme1
-------
different in the regenerator than those in the combustor. In the one-step
regenerator the higher temperatures may cause vaporization of elements that
did not vaporize in the combustor. Also, elements oxidized in the com-
bustor and carried into the regenerator could undergo vaporization or
further reaction.
Table 12 indicates possible chemical forms of trace elements based on free
energy minimization calculations performed using reactive conditions similar
to those in a limestone regenerator.3
Table 12. PROBABLE CHEMICAL FORM OF TRACE ELEMENTS IN THE REGEN-
ERATOR EXTRAPOLATED FROM FUEL GASIFICATION, FREE
ENERGY MINIMIZATION CALCULATIONS
Elements forming
oxides or carbonates
MgC03
MgO
Zr(C03)2
ZrO,
Cr2°3
Ce02
Na2C°3
Elements forming elemental
vapors or volatile sulfides
Elemental vapors
Cd
Sn
Pb
Bi
Volatile sulfides
Ba: Probably as BaS
Co: Forms CoS with ex-
cess CoO going to
the metal
Mn: Forms MnS and MnO
Mo : Forms MoS with ex-
cess MoO forming Mo
Sr: SrO and SrS
Zn: Forms ZnO, ZnS, and
elemental Zn vapor
72
-------
In Table 12, those elements which form oxides or carbonates should not
escape from the regenerator. Those forming elemental vapors, or volatile
sulfides could escape. Referring to the "worst case" emissions of trace
elements from combustion of coal discussed in Section IV, only Pb in
Table 12 might pose a potential environmental problem. Equilibrium calcu-
lations to indicate the chemical form of other elements of concern from
Section IV such as V, U, Be, Cl, and F, based on the "worst case" emission
estimates were not available; hence, for discussion purposes, we simply
assume those elements of concern with respect to direct combustion are
also of concern in regeneration. (Note - the "worst case" estimates from
direct coal combustion in Section IV do not strictly apply here because
we do not have complete combustion of coal, but for the order of magnitude
range of the estimates, they provide a useful reference.)
In addition to the information presented in Table 12, the following gen-
eral observations can be made concerning the fate of certain trace elements.
Arsenic
Arsenic probably enters the REG in the form of calcium
arsenate. In the REG it is reduced and volatized as
arsenious oxide fume.1* AS203 vapor can enter the sulfur
recovery unit and condense on small particulates. The
As2^2 could also poison catalysts in the sulfur recovery
plant or be leached from particulate collected by the
cyclone.
Vanadium
Westinghouse has discovered, in their FB gasification
studies, that V is completely trapped on the sorbent,
probably as the oxide.4 It is expected that the V will
remain trapped on the sorbent in the REG.
There is no data available regarding the content of unburned organic com-
pounds, polycyclic aromatic compounds and fine particulates which would
be contained in the "coal gas" fed to the Regenerator. These species could
conceivably escape from the regenerator in significant quantities. Most
likely, they would pass into the sulfur recovery plant with the regenerator
off-gases. Their fate there is also unknown. Experimental measurements of
73
-------
the flow of these materials through the pilot regeneration process will
be necessary before further evaluations can be made.
SOLID WASTE DISPOSAL
Solid waste disposal could prove to be one of the most significant obstacles
to fluidized bed combustion simply because of the potentially large quan-
tities of waste produced. Waste disposal requirements for several fluid-
ized bed options have been investigated by workers at Battelle.5 Their
results are summarized in Table 13. The discussion here focuses mainly
on the leachate potential of the solid waste.
Table 13. VOLUME OF SPENT BED PLUS ASH PRODUCED PER YEAR BY
A 635-MW FBC PLANTa»5 (acre-feet)
Ca/S
mole ratio
Ca/S = 2
Ca/S = 1.2
Coal-sulfur content
1% sulfur
in coal
140
115
2% sulfur
in coal
200
150
3% sulfur
in coal
260
195
4% sulfur
in coal
320
235
Assumptions:
Coal feed rate = 430,000 pounds per hour;
Ash content = 12 percent;
90 percent S02 removal;
73 percent load factor;
Density of spent bed plus ash = 100 pounds per
cubic foot (65 percent of theoretical density
of spent bed mixture).
Experimental Studies
Leaching of the ash and stone from the combustor and regenerator poses a
possible environmental hazard. Solid residue from the fluidized bed pro-
cess consists of spent sorbent from the bed as well as a mixture of sorbent
and fly ash removed from the flue gas by the particulate control equipment.
If this material is placed in landfills, leaching by rainwater is
possible. The British Coal Utilization Research Administration (BCURA)6
74
-------
Pope, Evans and Robbins7 and Westinghouse8 have investigated the properties
of the leachate obtained from the coal ash/limestone waste. BCURA found
that, although CaO, MgO and CO contents of the leachate varied, all their
samples showed common features:
High pH (10.5 to 11.6)
High or complete extraction of sulfate
Negligible extraction of magnesium.
The exposed surface tends to form an impervious crust as a consequence of
carbonation/hydration. The preliminary BCURA tests indicated that dis-
posal of lime-containing ashes is unlikely to pose serious problems. It
is imperative, however, that tests using lysimeters and large field cells
be performed.
In an attempt to find uses for fluidized bed by-products, Pope, Evans, and
Robbins conducted leaching studies of the solids withdrawn from their
fluidized bed.8 The bulk of their withdrawn material, primarily lime
anhydrite, with about 3 percent coal ash and the feed limestone have the
composition shown in Table 14.
Pope, Evans and Robbins found pH values of 10.6 to 12.6 over a 4-day leach-
ing study.8 They also found that: less than 20 percent of the calcium
was leached, less than 15 percent of the sulfate was leached, less than
10 percent of the sample was water soluble, and magnesium did not leach
at all. Neither PER nor BCURA reported trace element concentrations in
their leachate samples.
Trace Metal Leaching
Theis, in a study on the potential trace metal contamination of water
through fly ash disposal, has made the following assertions:9
At the normal pH range of natural waters, the
hydroxide of some metals (Hg, Pb, Cu, Cr, Cd,
Zn) controls their solubility.
75
-------
Table 14. COAL ASH CONTAMINATION OF BENEFICATED LIME/ANHYDRITE
Element
Ca
Mg
Fe
Al
Si
Na
K
Ti
Zn
Cu
Ni
Co
Pb
As
P
Raw limestone no. 1359
38.8 percent
0.51 percent
0.101 percent
0.15 percent
0.23 percent
0.027 percent
0.08 percent
0.012 percent
4.0 ppm
10.0 ppm
36.0 ppm
28.0 ppm
43.0 ppm
70.0 ppm
1.6 ppm
Lime/anhydrite
39.0 percent
0.43 percent
0.42 percent
0.42 percent
1.14 percent
0.20 percent
0.34 percent
0.0380 percent
35.0 ppm
35.0 ppm
195.0 ppm
90.0 ppm
180.0 ppm
-
1.6 ppm
Sewickley coal ash =9.5 percent aluminum. On this basis, the
lime/anhydrite contains approximately 3 percent coal ash.
At elevated pH, carbonate may control solubility.
In general, trace metals display drastically de-
creased solubilities with increasing pH.
In the pH range of 7 to 8.5, only Zn and Cd
could be considered soluble.
Arsenic is generally very soluble.
Theis presented the relationship between solubility and pH as shown in
Figure 13.
76
-------
-4
c
o>
o
o
O
en
o
-6
-7
-8
-9
-10
HgOH*
7
PH
8
10 11 12 13 14
Figure 13. Solubilities of trace metals - free aqueous and
mono-hydroxo complexes only considered^
-------
The elements of major concern seem to be As, V, and Cd. However, since
complexes may form which would increase the solubility of the metals,
Pb and Hg, at least, may also be of concern in leachates. Theis found,
for example, that addition of EDTA to his ash samples increased the
solubility of all elements but mercury.^
Rossoff and Rossi have investigated the fate of trace elements in scrubber
sludges.10 Although the composition of a scrubber sludge is different
than that of the spent stone from a regenerator or from the combustor,
in general, the same elements are present and should be affected by pH
and complexing agents in a similar manner. Table 15 lists metal solubility
as a function of species present in weakly alkaline solutions.
The studies done by BCURA and PER with partially sulfated lime (bed
material) and coal ash have shown that the leachate is highly alkaline
(high pH). Since metal solubility decreases with increasing pH, leaching
from the fluidized bed combustion ash may be suppressed. Increased solu-
bility may, however, occur by means of complex formation. No data were
available on complex"formation in the leachate from either spent stone or
bed material.
In general, data are lacking on the leaching properties of trace consti-
tuents of the residue. Substantial lysimeter and field cell testing has
not yet been conducted on residue from once-through and regenerative fluid-
ized bed combustion systems. Therefore, much more data are needed before
conclusions can be drawn regarding the environmental impact of FBC residue
disposal.
EPA is continuing their program to assess the environmental impact of FBC
solid residue disposal. Projects in this program are being conducted by
Westinghouse, Ralph Stone and Co., and TVA..
78
-------
Table 15. RELATIVE SOLUBILITIES IN WEAKLY ALKALINE SOLUTIONS10
VO
Cations
Major
Ca2+
Mg2+
Toxic
Be2+
Cd2+
Cr2+
Cu+
Hg"1"
Pb2+
Zn2+
Toxic anions
As°3
Slightly
soluble
a
Se0;
Insoluble
Insoluble
Major anions
C°3
Soluble
Insoluble
a
Insoluble
Insoluble
Insoluble
Very slightly
soluble
OH
Insoluble
Insoluble
Insoluble
Insoluble
Insoluble
Slightly
soluble
Insoluble
S°3
Slightly
soluble
a
Slightly
soluble
Insoluble
Insoluble
Slightly
soluble
so'
Insoluble
Soluble
Insoluble
Soluble
Slightly
soluble
Insoluble
Soluble
Data to be determined.
-------
FUEL STORAGE AND HANDLING
Electric utility plants and other intensive consumers of coal store large
quantities in outdoor piles. Storage practices for fluidized bed combus-
tion systems will be similar. Air emissions of particulates occur from
wind erosion and handling operations. Air emissions of carbon monoxide
and hydrocarbons will result during spontaneous combustion of reactive
coals. Rain water draining through storage piles will also leach certain
elements, creating potential ground and surface water pollution problems.
Coal Storage Requirements
Coal-fired electric utility plants maintain a 75- to 90-day coal supply
on-site.n>12 Typically, a 90-day coal supply amounts to 810 tons per
megawatt (MW) of generating capacity for a plant with an average load
factor of 90 percent. Normal height of a storage pile is 30 feet, and
the land area required is 0.04 acres/MW. ^
Coal Pile Drainage and Leachates
Rain and snow cause water to drain through coal piles. Therefore, the
magnitude of this problem will vary widely depending on plant location.
o
The national coal pile drainage volume is reported to be 7.9 x 10 gal-
lons (30 x io6 m3) per year based on average rainfall14 indicating a typi-
cal value of 40,000 gallons per year per MW. Available data on pollutant
concentrations are presented in Table 16. The wide ranges are attribut-
able to variations in coal properties as well as rainfall and drainage
*
MW as used in this report represents the electrical output of the system.
The term "heat rate" - British Thermal Units of fuel per kilowatt hour of
electricity (Btu/kWh) - is commonly used in the utility industry to denote
plant performance. The 1974 average heat rate was 10,400 Btu/kWh, and the
average coal heat content was 24 x 10^ Btu/ton. New conventional coal-
fired power plants, combined cycle plants and fluidized bed combustion
systems may achieve heat rates below 9,500 Btu/kWh range.
80
-------
rates. Although the drainage volumes discussed above were yearly rates,
this does not imply constant flows. Actually, the drainage flow rate may
vary greatly from day to day depending on rainfall. The highest pollu-
tant concentrations and lowest pH will be associated with low drainage
rates.
Table 16. COMPOSITION OF DRAINAGE FROM COAL PILES14
Alkalinity
BOD
COD
Total solids
Total suspended solids
Total dissolved solids
Ammonia
Nitrate
Phosphorus
Turbidity
Acidity
Total hardness
Sulfate
Chloride
Aluminum
Chromium
Copper
Iron
Magnesium
Sodium
a
Concentration, mg/£
15 -
3 -
100 -
1,500 -
20 -
700 -
0.4 -
0.3 -
0.2 -
6 -
10 -
130 -
20 -
825 -
0 -
1.6 -
0.4 -
90 -
160 -
2.2 -
80
10
1,000
45,000
3,300
44,000
1.8
2.3
1.2
505
27,800
20,000
480
1,200
16
3.9
2.0
180
1,260
8.0
Appropriate for all values except pH. Using the
volumes and conditions discussed in the text,
1 mg/Jl is equivalent to 0.33 Ib/yr/MW.
81
-------
Coal pile drainage can be controlled. Ground water contamination can be
minimized by storing the coal on an impervious base of clay or plastic
liner. Surface water runoff from coal piles can be collected by a drain-
age system and treated before discharge. Treatment often includes neu-
tralization with lime, soda ash or alkaline waste streams from other
processes. Clarification involves extended retention time and addition
of coagulants if necessary.
Air Emissions From Coal Storage and Handling
Air emissions from coal storage include fugitive dust, carbon monoxide
and hydrocarbons. Carbon monoxide and hydrocarbon emissions are a result
of spontaneous combustion and have not been quantified. Particulate emis-
sions consist of coal dust and are affected by wind speed, precipitation-
evaporation, coal characteristics and coal pile geometry. Available data
indicate an emission factor of 0.0012 lb/ton/year. ^ Transport and hand-
ling operations represent two-thirds of the emissions from aggregate
storage piles.16 Therefore, total particulate emissions from coal storage
and handling may reach 0.0036 lb/ton/year. Based on the previously dis-
cussed storage requirement, particulate emissions will be 3 tons/year/MW.
COAL DRYING
Hot air is used to remove the surface moisture from coal prior to
crushing or pulverizing.17 The inherent moisture in the coal is not
usually affected by drying. Usually the coal is cleaned and dried at
the mine, not at the consuming facility. Drying air temperatures of
316°C may be used. Particulate emissions from coal drying, before the
application of control equipment, are in the range of 16 to 25 Ib/ton,
depending on the type of dryer used.18 Control equipment efficiency
commonly ranges from 70 to 99 percent.
82
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COOLING SYSTEMS
The cooling requirements for electric power plants vary widely depending
on the type of plant and the design efficiency. Lower efficiencies usu-
ally mean more heat losses to cooling water. The primary factor affect-
ing the efficiency of a steam electric plant is the steam turbine effi-
ciency which increases as the steam pressure and temperature increase.
Gas turbine plants do not require cooling water as all the waste heat
is rejected through the flue gas directly to the atmosphere.
The average steam electric plant operates at a fuel-to-electricity effi-
ciency of 33 percent, requiring 10,400 Btu of fuel per kilowatt-hour (kWh)
of electricity produced. Waste heat amounts to 67 percent (7,100 Btu/kWh)
of the input, with 15 percent (1,600 Btu/kWh) attributable to inplant and
flue gas losses and 52 percent (5,500 Btu/kWh) lost to the condenser cool-
ing.19 The steam turbine in the above case operates at about 40 percent
efficiency based on a total heat input of 8,900 Btu/kWh and conversion of
3,400 Btu/kWh to electricity and 5,500 Btu/kWh rejected to the condenser.19'20
The cooling requirement for plants using gas turbines and steam turbines
in the same cycle (combined cycle plants and pressurized fluidized bed
systems) will depend on the heat input to each turbine. Cooling water
losses equivalent to 60 percent of the energy input to the steam turbine
will be required for high pressure steam turbines.
Cooling can be provided by once-through or recirculative systems. Most
large new steam electric plants will be required to use recirculative
systems.21 An average plant using once-through cooling with a normal
temperature rise of 8°C requires a water flow of 10 gal/day/MW and dis-
o
charges 1.3 x 10 Btu/day/MW of added heat to the receiving waters.
Recirculative systems are used to minimize the heat discharged to surface
waters. The following discussion is directed primarily to wet cooling
83
-------
towers, although dry cooling towers, spray ponds and canals are also
used or under development. A cooling tower recirculates a large volume
of water (about 10 gal/day/MW) through the condenser and discharges
the heat acquired to the ambient air by evaporation (75 percent) and
direct heat transfer (25 percent). Therefore, for the present example,
o
10 Btu/day/MW must be discharged
12,000 gal/day/MW of evaporation.
o
10 Btu/day/MW must be discharged through evaporation equivalent to
Cooling tower make-up water for the water lost through evaporation,
drift, and blowdown must be provided. Drift ranges from 0.005 to 0.02
percent of the flow for a well-designed tower.21'22 The amount of blow-
down (B) depends on the allowable cycles of concentration (C = the
number of times the concentration of any constituent is multiplied
from its original value in the make-up water), the evaporation (Ev),
and the drift (D) as follows:
C = (B + Ev + D)/B + D .
For typical make-up water quality, C averages from 4 to 6, although the
total range is 1.2 to 15. Continuing the above example for C = 5,
Ev = 12,000 gal/day/MW, and D = 0.000125 x 106 gal/day/MW, then
B = 29,000 gal/day/MW. Total make-up water required is then
15,000 gal/day/MW compared to 10" gal/day/MW for once-through cooling.
Heat discharge can be eliminated by cold side blowdown and is greatly
reduced compared to once-through cooling even when hot side blowdown
is practiced.
Many chemicals have been used and are continuing to be used in recircu-
lative cooling systems. Table 17 is a list of some common chemicals
used in recirculative cooling systems.2^ Table 18 presents concentra-
tions of corrosion inhibitors that are found in recirculative cooling
systems.2t| Blowdown treatment is used to limit pollutant discharges. Addi-
tional potential pollutants include fogging and noise, as well as make-up
water treatment wastes. Further information is available through many
sources including references 26 through 36.
84
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Table 17. CHEMICALS USED IN RECIRCULATIVE COOLING WATER SYSTEMS24
Use
Chemical
Corrosion inhibition or scale
prevention in cooling towers
Biocides in cooling towers
pH control in cooling towers
Dispersing agents in cooling
towers
Biocides in condenser cooling
water systems
Organic phosphates
Sodium phosphate
Chromates
Zinc salts
Synthetic organics
Chlorine
Hydrochlorous acid
Sodium hypochlorite
Calcium hypochlorite
Organic chromates
Organic zinc compounds
Chlorophenates
Thiocyanates
Organic sulfurs
Sulfuric acid
Hydrochloric acid
Lignins
Tannins
Polyacrylonitrile
Polyacrylamide
Polyacrylic acids
Polyacrylic acid salts
Chlorine
Hypochlorites
Sodium pentachlorophenate
85
-------
Table 18. COOLING TOWER CORROSION AND SCALE INHIBITOR SYSTEMS25
Inhibitor system
Concentration
of chemical additives
in recirculating water,
1. Chromate
2. Chromate 4- Zinc
Chromate + Zinc
+ Phosphate (inorganic)
4. Zinc + Phosphate
(inorganic)
5. Phosphate (inorganic)
6. Phosphate (organic)
7. Organic Biocide
200 - 500 mg/£
17 - 65 mg/£
8-35 mg/£
10 - 15 mg/£
8-35 mg/£
30 - 45 mg/£
8-35 mg/4
15 - 60 mg/£
15 - 60 mg/£
15 - 60
3-10 mg/£ organics
30 mg/£ chlorophenol
5 mg/£ sulfone
1 mg/£ thiocyanate
86
-------
REFERENCES
1. Johnson, T. E. et al. Evaluation of the Regenerative Pressurized
Fluidized Bed Combustion Process. M. W. Kellog Company. Prepared
for U.S. Environmental Protection Agency. Publication Number
EPA-650/2-74-012. February 1974.
2. Archer, D. H. et al. Evaluation of the Fluidized Bed Combustion
Process. Westinghouse Research Laboratories. Prepared for U.S.
Environmental Protection Agency. Publication Number NTIS-PB-211-494.
November 1971.
3. Harrison, D. P. Department of Chemical Engineering, Louisiana
State University, Baton Rouge, Louisiana. Private Communication.
4. Newby, R. A., D. L. Keairns, and E. J. Vidt. Residual Oil Gasifica-
tion/Desulfurization at Atmospheric Pressure - Clean Power From
Existing Boilers. (Presented at 67th Annual AIChE Meeting. Wash-
ington, B.C. December 1974.)
5. Murthy, K. S. et al. Battelle Memorial Research Institute, Columbus,
Ohio. Private Communication.
6. Pressurized Fluidized Bed Combustion. British Coal Utilization
Research Agency (BCURA), National Research Development Corporation,
London. Prepared for Office of Coal Research. R&D Report No. 85.
7. Keairns, D. L. et al. Fluidized Bed Combustion Process Evaluation:
Phase II - Pressurized Fluidized-Bed Coal Combustion Development.
Westinghouse Research Laboratories. Prepared for U.S. Environmental
Protection Agency. EPA Report No. EPA-650/2-75-027c. September 1975.
8. Multicell Fluidized Bed Boiler Design, Construction and Test Program.
Pope, Evans and Robbins, Inc. Publication Number PB 236 254/AS,
Office of Coal Research, Washington, D.C. R&D Report No. 90 - In-
terim Report No. 1. August 1974.
9. Theis, T. L. The Potential Trace Metal Contamination of Water Re-
sources Through the Disposal of Fly Ash. Department of Civil Engi-
neering, University of Notre Dame. (Presented at 2nd National Con-
ference on Complete Water Reuse. Chicago. May 4-8, 1975.)
10. Rossoff, J. and R. C. Rossi. Disposal of By-Products From Non-
Regenerable Flue Gas Desulfurization Systems: Initial Report.
Prepared for U.S. Environmental Protection Agency. Publication
Number EPA-650/2-74-037a. May 1974.
11. A Summary of the Processes Involved and the Chemical Discharges
Associated with the Electric Utility Industry. Edison Electric
Institute, New York, New York.
87
-------
12. Electric Power Statistics. Federal Power Commission, Washington,
B.C. January 1974.
13. Surprenant, N. , R. Hall, S. Slater, T. Susa, M. Sussman, and C. Young.
Preliminary Emissions Assessment of Conventional Stationary Combustion
Systems. Volume II - Final Report. GCA/Technology Division, Bedford,
Massachusetts. Prepared for U.S. Environmental Protection Agency.
Publication Number EPA-600/2-76-046b. March 1976.
14. Nichols, C. R. Development Document for Effluent Limitations
Guidelines and New Source Performance Standards for the Steam
Electric Power Generating Point Source Category. U.S. Environ-
mental Protection Agency, Washington, D.C. Publication Number
EPA-440/l-74-029a. October 1974.
15. Blackwood, T. R. and A. W. Wachter. Source Assessment of Coal
Storage Piles. Monsanto Research Corporation, Dayton, Ohio.
Prepared for U.S. Environmental Protection Agency under Contract
No. 68-02-1874. Unpublished results.
16. Cowherd, C., Jr., K. Axtell, Jr., C. M. Guenther, G. A. Jutze.
Development of Emission Factors From Fugitive Dust Sources.
Midwest Research Institute. Prepared for U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina.
Publication Number EPA-450/3-74-037; PB 238 262/OGA. 1974.
17. Steam. New York, Babcock and Wilcox, 1973.
18. Compilation of Air Pollutant Emission Factors. Second Edition.
U.S. Environmental Protection Agency, Research Triangle Park,
North Carolina. Publication Number EPA-AP-42. April 1973.
19. A Summary of Cooling Technology. Draft Report. Edison Electric
Institute, New York, New York. May 1973.
20. Blackwood, T. R. and W. H. Hedley. Efficiencies in Power Generation.
Monsanto Research Corporation, Dayton, Ohio. Prepared for U.S. En-
vironmental Protection Agency, Research Triangle Park, North Carolina.
Publication Number EPA-650/2-74-021. March 1974.
21. Effluent Guidelines and Standards for Steam Electric Power Generating.
Fed Regist. 135:0541. From Environment Reporter, July 11, 1975.
22. Reviewing Environmental Impact Statements - Power Plant Cooling Sys-
tems, Engineering Aspects. U.S. Environmental Protection Agency,
Corvallis, Oregon. Publication Number EPA-660/2-73-016. October 1973.
23. Aynsley, E. and M..R. Jackson. Industrial Waste Studies: Steam Gen-
erating Plants. Draft Final Report. Prepared for U.S. Environmental
Protection Agency under Contract No. WQO 68-01-0032. May 1971.
88
-------
24. Steam Electric Plant Air and Water Quality Control Data for the Year
Ended December 31, 1971. U.S. Federal Power Commission. Publication
Number FPC-S-239. June 1974.
25. Surprenant, N., R. Hall, S. Slater, T. Susa, M. Sussman, and C. Young.
Preliminary Emissions Assessment of Conventional Stationary Combustion
Systems. Volume II - Final Report. CCA/Technology Division, Bedford,
Massachusetts. Prepared for U.S. Environmental Protection Agency.
Publication Number EPA-600/2-76-046b. March 1976.
26. Roffman, A. Environmental, Economic, and Social Considerations in
Selecting a Cooling System for a Steam Electric Generating Plant.
In: Cooling Tower Environment 1974. Published by U.S. Energy Re-
search and Development Administration. Publication No. CONF-740-302.
1975.
27. A Summary of the Processes Involved in the Chemical Discharges
Associated with the Electric Utility Industry. Edison Electric
Institute.
28. The Water Pollution Control Act Amendments of 1972. 86 Stat.
816 et seq. Public Law 92-500.
29. Rosen, R. H., V. Bennett, J. Edwards, R. Elgin. Environmental
Assessment of Alternative Thermal Control Strategies for the
Electric Power Industry. Energy Resources Co., Cambridge, Massa-
chusetts. Prepared for U.S. Environmental Protection Agency under
Contract No. 68-01-2477. 1974.
30. Schwieger, R. G. Power Data Sheet No. 501: Find Cooling Tower
Slowdown and Make-up. Power. 119(2):12, February 1975.
31. Roffman, A. and R. E. Grimble. Drift Deposition Rates from Wet
Cooling Systems. In: Cooling Tower Environment 1974. Published
by U.S. Energy Research and Development Administration. Publica-
tion No. CONF-740-302. 1975.
32. Roffman, A. and L. D. Van Vleck. The State-of-the-Art of Measuring :
and Predicting Cooling Tower Drift and Its Deposition. J Air Pollut
Control Assoc. 24(9):855-859, 1974.
33. Furlong, D. The Cooling Tower Business Today. Environ Sci Technol.
8:712, August 1974.
34. Comparison of Evaporative Losses in Various Condenser Cooling Water
Systems. Proceedings of the American Power Conference. Volume 32.
1970.
89
-------
35. Daugard, S. J. and T. R. Sundaram. Review of the Engineering Aspects
of Power. Hydronautics, Inc., Laurel, Maryland. Prepared for U.S.
Environmental Protection Agency. NTIS Publication Number 235 783.
October 1973.
36. Potential Environmental Modifications Produced by Large Evaporative
Cooling Towers. EG&G, Inc., Boulder, Colorado. Prepared for U.S.
Environmental Protection Agency. Publication Number EPA-16130
DNH 01/71; PB 210 702. January 1971.
90
-------
SECTION VI
SUGGESTED CONTROL TECHNOLOGY FOR FBC SYSTEMS
INTRODUCTION
Flue gas emissions and solid waste disposal are the two major aspects of
fluidized bed combustion (FBC) of coal which may require special control
technology. If sulfur recovery techniques are employed in processing
spent stone, tail gases from the recovery unit may also require pollution
control devices.
Flue gas emissions will include both gases and particulates, and the rela-
tive concentrations may vary from unit to unit. In addition, different
control options may be available depending upon whether or not one is
dealing with an atmospheric or a pressurized combustion system.
Control technologies for flue gases and solid waste are discussed below.
FLUE GAS TREATMENT: AND-ON CONTROL TECHNOLOGY
The discussion here is broken down into gaseous emissions and particulates.
Primary emphasis is given to particulate control, because this seems,
at this time, to be the major area in which problems may arise. Some
gaseous emissions could be troublesome but control techniques for those
gaseous pollutants that have been defined seem straightforward; hence,
they are discussed only briefly here. The discussion on particulate con-
trol is subdivided into options for atmospheric or pressurized operation.
Because FBC systems are being designed to operate in the post-1980 era
91
-------
when emissions standards may be stricter, control equipment capable of col-
lecting fine particles (< 3 microns diameter) at high efficiency has been
emphasized.
Particulate Control Equipment for Atmospheric Pressure Combustion
The major source of particulate emissions from a FBC system will be the
combustor (including the optional carbon burn-up cell). Schematic dia-
grams of the important system components for particulate control are
shown in Figures 14 and 15. Much of the elutriated bed material will
be in the form of large particles, 100 to 1000 ym, and will be collected
by the cyclones. Particulate loadings after the cyclones, however, will
still be high enough to warrant additional control. As discussed earlier,
one problem in the current analysis is that data on particulate emissions
from FBC, particularly fine particulates (< 3 ym) are very limited at
this time, so that the actual degree of control needed even to meet current
standards is not known precisely.
General Comments on Control Devices - The performance of a cyclone depends
on a variety of factors including the particle shape and size, the cyclone
dimensions, gas velocity and gas viscosity. Multiple small diameter cy-
clones are most effective, but, as illustrated by the data in Table 19,
2
cyclone efficiency decreases rapidly as particle size decreases.
Cyclone efficiencies decrease rapidly for particle sizes below 5 microns,
dropping to about 20 percent for a 2-micron particle and a 6-inch diameter
cyclone. For effective control of fine particles, more sophisticated
equipment must be used.
Three control devices are now commercially available for controlling fine
particulates (< 3 microns): electrostatic precipitators, scrubbers, and
fabric filters. Choosing an appropriate control device requires considera-
tion of a number of variables; e.g., aerosol properties, available space,
efficiency objectives, water pollution regulations, energy costs, etc.
92
-------
CO
OPTION I
ATMOSPHERIC >
PRESSURE
FLUIDIZEO BED
BOILta
SOLID
WASTE
OPTION 2
ATMOSPHERIC
PRESSURE
FLUIDIZCO BED
BOILER
SOLID
WASTE
Figure 14. Control of flue gas emissions from an atmospheric pressure FBC boiler
-------
OPTION
PRIMARY AND SECONDARY
PARTICULATE REMOVAL
OPTION 2
CYCLONES
PRIMARY AND SECONDARY
PARTICULATE REMOVAL
TERTIARY
FLUE GAS CONTROL
DEVICE
FINAL FLUE GAS
CONTROL
DEVICE
200-300° F
I AIM
(BEFORE OR AFTER
HEAT RECOVERY AS
DEPICTED IN FIGURE IB)
STACK
SOLID
WASTE
Figure 15. Control of flue gas emissions from a pressurized FBC boiler
-------
Table 19. DISTRIBUTION BY PARTICLE SIZE OF AVERAGE
COLLECTION EFFICIENCIES FOR VARIOUS
PARTICIPATE CONTROL EQUIPMENT
Type of collector
Simple cyclone
Multiple cyclone
(12-in. diameter)
Multiple cyclone
(6-in. diameter)
Collection efficiency, %
Particle size range, ym
<5
7.5
25
63
5 to 10
22
54
95
10 to 20
43
74
98
20 to 44
80
95
99.5
>44
90
98
100
For electric utility coal-fired boilers, electrostatic precipitators
3
(ESP) are the most common final control device. ESP's have proved to
be reliable, have a low operating cost, and perform at reasonably high
efficiencies. Venturi scrubbers are used much less frequently because
the efficiency tends to be low for fine particles, unless high pressure
drops and thus large amounts of energy are used. Fabric filters have
4 5
been used in only two utility coal boilers over the past 2 to 3 years, '
with a third larger unit scheduled to be installed on a 350-MW boiler.
Fabric filters are attractive because of very high efficiencies (99.8
45 7
to 99.9 percent) ' at competitive costs. In the past, however, fabric
filters were not used on coal-fired boilers because of questionable re-
liability as a result of fabric deterioration. In addition, particulate
control devices with maximum efficiencies of 99.9 percent were not needed
and are still not required in many cases. New power plants are now being
designed to achieve particulate control efficiencies in the 99 to 99.5
percent range; hence, a reasonable goal for FBC systems would be control
efficiencies of at least 99 percent and probably 99.5 percent.
In FBC, the most important coal ash properties affecting fine particulate
control are the particle size distribution, the mass concentration,
the S02 concentration, and the particle resistivity (for ESP). Generally
95
-------
the smaller the particle, the more difficult it is to collect. The depen-
dence of collection efficiency on particle size is most pronounced for
scrubbers; it tends to be less restrictive for fabric filters and elec-
trostatic precipitators. Figure 16 presents the predicted particle size
Q Q
distribution at the inlet to the final control device ' of an overall
fluidized bed combustion system (shown previously in Figure 14).
Large variations in size distribution may result from coal ash properties
and the design of the cyclone precollectors. A composite of the particle
size distribution from many conventional pulverized coal systems having
only cyclone or similar mechanical control systems is also presented in
Figure 16. Because the particle size data are extremely limited for
fluidized bed systems, one can conclude only tentatively from Figure 16 that
the particle size distribution in FBC is not radically different from a
conventional system, although there could be more fine particles in atmos-
pheric FBC emissions. The FBC data should be considered tentative because
it is taken from relatively small test systems compared with the size of
conventional systems.
Particulate mass emissions reaching the final control device of a FBC
system will probably be lower than in a conventional system. However,
this concentration will depend on both the amount and size distribution
of the particulates reaching the cyclone precollectors as well as the
design of those precollectors. The amount of fine particulates reaching
the cyclones can only be determined experimentally, and care should be
exercised to distinguish between particle mass and particle number. The
design plan for the Pope, Evans and Robbins - FBC system indicates an
3
expected mass concentration of 0.7 grains/ft reaching the final control
device. Particulate emissions reaching the final control device in a
3
conventional system are higher - typically 2 to 3 grains/ft .
96
-------
CO
cr
UJ
O
-------
The concentration of SO,, SO- and water vapor in the flue gases can also
affect the selection of particulate control equipment. Water in flue
gases from combustion is primarily a result of the fuel hydrogen content
and it produces a dew point of 50 to 65°C at normal excess air. However,
as illustrated in Figure 17, the SO concentration (usually 1 to 2 per-
cent of the SOo concentration) in a conventional coal-fired boiler raises
the flue gas dew point. Equipment designed to collect dry particulate
(fabric filters and dry electrostatic precipitators) must operate above
the acid dew point. Most conventional coal-fired plants maintain flue
gas temperatures between 150 and 180°C to avoid corrosion problems.
12
Robinson et al. found that the Pope, Evans and Robbins - FBC system
produced an S0_ concentration of 39 ppm when sorbent was not used, and no
measurable SO- when sorbent was used. (Note: These early S0_ results
represent limited data and must be confirmed by further SO- analyses on
other fluidized bed combustors.) Such a very low SO, concentration in
the presence of sorbent, if confirmed, means that flue gases might be
cooled to 95 C or below for dry particulate collection and increased heat
recovery. The major problem in using fabric filters on coal-fired boilers
has been SO- and H-SO, induced deterioration of the fabric. Therefore,
fabric filter technology may also be readily applicable to fluidized bed
combustion systems if the low SO- concentrations are confirmed.
The concentration of SO- and the acid dew point will also affect the
performance of electrostatic precipitators. Burning low sulfur western
coal has resulted in decreased electrostatic precipitator performance,
13
and SO, has been added to the flue gas as a conditioning agent.
Electrostatic Precipitators - An electrostatic precipitator can be applied
before or after the final flue gas heat recovery unit as previously illus-
trated in Figure 14. In the design of the Pope, Evans and Robbins 30-MW
demonstration plant, an electrostatic precipitator was selected to oper-
ate at 315 to 370°C before the final heat recovery (a hot side precipita-
tor) because of the high resistivity of the particulates at low tempera-
tures. Therefore, the unit must handle a larger gas volume than if low
98
-------
330
z
o
Q.
£
310
290
270
250
230
210
190
0.01
A.A. TAYLOR DEWPOINT METER
P. MULLER CALCULATED
EXPERIMENTAL
PARTIAL PRESSURE MEASUREMENT
(REF. II)
/
,1
O.I 1.0 10
S03 (H2S04) IN FLUE GAS.ppm
100
Figure 17. Dew point elevation as a function of
SO., concentration^
99
-------
temperature operation were possible. With good design and operation, hot
side electrostatic precipitation can collect fine participates at high
efficiencies as illustrated in Figure 18.1** Similar performance can be
attained with cold side precipitation when the aerosol properties are
suitable. However, there have been some problems in designing precipi-
tators to operate at high efficiencies. Data published by Benson and
Corn show that among 14 large electrostatic precipitators, having an
average design efficiency of 98.2 percent, the actual average operating
efficiency was only 89.0 percent. Accurate data on particle size distri-
bution, mass concentration, and in situ resistivity are needed for proper
electrostatic precipitator design for FBC systems. Designing precipita-
tors for FBC systems based on analogies with previous operating experi-
ence in conventional combustion systems can be very risky. There have
been many examples of precipitators designed to operated at 95 to 99 per-
cent efficiency which actually operated at 50 to 90 percent efficiency.
Electrostatic precipitators have been very widely accepted by the utility
industry because they have been applied over many years with minimal main-
tenance problems. However, the size and capital cost rise sharply as
design efficiencies are increased to 99 percent and above. Fly ash re-
sistivity is a very important factor in ESP performance and may need more
study with respect to fluidized bed combustion. However, methods to com-
bat resistivity problems are being studied, including the use of hot side
precipitators, and fly ash conditioning with SO,, ammonia, and sulfamic
acid. If resistivity problems require operating temperatures of 370°C
instead of 95 to 150°C, then many normally condensable organics and con-
densable trace metal compounds will not be collected. Nevertheless, one
significant advantage of electrostatic precipitators is that the power
requirements are lower than other control devices.
Wet Scrubbers - Most wet scrubbers that are commonly used collect par-
ticulates primarily through inertial mechanisms and thus require large
amounts of power to collect fine particulates at high efficiencies.
Venturi scrubbers are used with very high pressure drops to collect fine
100
-------
o
o
CD
Q.
O
2
LU
99.98
99.9
99.S
99.5
99
98
z
o
(~
o
UJ
8
r* 95
90
60
30
0.05
A
O
I
MEASUREMENT METHOD:
& CASCADE IMPACTORS
O OPTICAL PARTICLE COUNTERS
+ DIFFUSIONAL
PRECIPITATOR CHARACTERISTICS:
TEMPERATURE - 335°C
SCA - 85 M2/(M3/Sec)
CURRENT DENSITY- 35 nA/CM2
O.I
0.5 1.0
PARTICLE SIZE, MICRONS
5.0
10.0
Figure 18. Measured fractional efficiencies for a hot side electrostatic precipitator,
with the operating parameters as indicated, installed on a pulverized coal
boiler
14
-------
particulates. Figure 19 presents calculated particle penetrations for
a venturi scrubber as a function of pressure drop, particle size, and
f factor. The f factor is an empirically determined constant and is a
function of particle wettability, venturi throat liquid distribution,
and other factors.17 Figure 19 shows that for an f factor of 0.25, a
98 percent collection efficiency for 2-micron particles requires a pres-
sure drop of 8 inches of H20. To collect 1.0- and 0.5-micron particles
at the same collection efficiency and same f factor, pressure drops of
35 and 135 inches of H20, respectively, are required. Clearly the per-
formance of a scrubber decreases sharply as the particle size decreases.
Wet scrubbers present certain advantages when used on an FBC system. They
typically operate at the water saturation temperature of the gas (below
95°C); therefore, organic compounds and volatile trace metal compounds
could be condensed and separated from the flue gas. By scrubbing with an
alkaline solution, acid gases such as HCl could be collected, if necessary.
The disadvantages of a wet scrubber for FBC systems, however, appear
to be severe. To achieve high efficiencies, present designs require very
large pressure drops and thus high power consumption and operating costs.
Disposal of the scrubber water may create a potential water pollution
problem. In addition, stack gases must usually be reheated (an expensive
operation) to avoid plume formation.
Fabric Filters - Only recently have fabric filters been used on conven-
tional coal-fired utility boilers because of the questionable life span
of fabrics exposed to S02> SO and moist flue gases. Of the filter
materials commonly used, glass fabrics are the most acid resistant and
the most cost competitive. The very low S09 concentration and the
apparently small amount of SO, in the flue gases of an FBC system
may provide the impetus for the use of fabric filters. Moderately acid
resistant fabrics18 such as NOMEX, orlon, and dacron can be used. A fab-
ric filter would necessarily be used after the final heat recovery unit.
102
-------
O.I i I I I
5 15 20 30 40 50 60 7O 80 90 100 110 120 130
AP, inches HgO
Figure 19. Penetration calculated from a venturi scrubber
model as a function of pressure drop and par-
ticle aerodynamic diameter-'-'
99.8
99.9
c
0>
u
k_
-------
The possibility of operating at temperatures near 95°C (as acid dew point
elevation is not a factor) also favors a fabric filter control device.
The fractional efficiency of a fabric filter installed on a coal-fired
boiler in Nucla, Colorado, is shown in Figure 20.^ Although there was
considerable scatter in the original data, efficiencies for particles 1 to
10 ym diameter were high, ranging from 99.4 to 99.8 percent. Similar test
data for a boiler burning pulverized anthracite showed higher efficiencies,
ranging from 99.75 to 99.87 percent in the 1 to 10 um range.5 Overall
mass efficiencies at the two test sites were 99.8 and 99.9 percent over
test periods of a couple of months. The bags at the Sunbury steam station
had been in use for 2 years when the field test was conducted.
I.V
OJ9
0.6
0.7
0.6
£ 0.5
o
! 0.4
Z
2 oj
i
^
<£
tr
L
UJ 0.2
2
UJ
Q,
0.1
- 0
\\ n n
N.
ci -
N.
- X) -
1 1 1 1 1 1 1 1 1 1 1 1 1
99.O
99.1
99.2
99.3
99.4
99.5
99.6
99.7
99.6
AQ Q
I 234567 8 9 10 II 12 13 14
PARTICLE SIZE,/i m
Figure 20. Median fractional collection efficiency for 22 tests'*
o
o
0>
Q.
O
z
UJ
O
UJ
LU
104
-------
Fabric filters have several advantages over other control systems. Col-
lection efficiency does not depend on particle resistivity. Very high
efficiencies of 99.4 to 99.9 percent for fine particulates can be
routinely achieved by fabric filters. These efficiencies are out of
the range of venturi scrubbers and can only be achieved by ESP through
enlarged precipitators and sharply increased costs.
One disadvantage of suggesting fabric filters for particulate control
in FBC systems is that fabric filters have only recently been used on
utility boilers and some operators may doubt their reliability and may
be unwilling to use them.
Particulate Control for Pressurized Combustion Systems
There are two pressurized FBC systems under consideration. One operates
at 15 to 25 percent excess air, while the other, the adiabatic system,
operates at 300 percent excess air. Because the cost of large scale
particulate control equipment is proportional to the actual gas volume
handled, the capital and operating cost of particulate control equipment
for an adiabatic system would be approximately triple the cost for a
normal excess air system to achieve the same number of lb/105 Btu of
emissions.
Control devices for pressurized fluidized bed systems should operate at
high temperature as well as high pressure if placed upstream of the gas
turbine, in order to maximize energy recovery from the turbine. A par-
ticulate control system operating at 800°C would fail to collect condensable
materials in the flue gas that could be collected at temperatures of
375°C by hot electrostatic precipitators or at 95 to 150°C by other con-
trol devices. Thus, it may be necessary to place a control device for
particulates or other pollutants in the low temperature ducting downstream
of the gas turbine in order to meet environmental requirements.
105
-------
Particulate control equipment for high temperature and pressure operation
is not yet commercially available and considerable development is required
before any such equipment will be available.19 The problem of controlling
particulates at high temperature had led to a preliminary review of con-
cepts for cooling, cleaning, and reheating the flue gases before applica-
tion of the gas turbine.20 Table 20 is a summary of potential high tem-
perature particulate removal systems. Molten salt scrubbers cannot be
applied to pressurized FBC systems because the alkali metal vapors would
cause gas turbine corrosion.
The Aerodyne Tornado cyclone has been seriously considered for applica-
tion of FBC systems. Figure 21 depicts the operation of the Aerodyne
Tornado cyclone which is claimed to have unusually good collection effi-
19
ciency for fine particulates compared to conventional cyclones. It
appears unlikely, however, that cyclones even of advanced design will
be able to achieve the high efficiencies for fine particulates that may
be needed for operation in the mid 1980's era. Some type of device in
addition to cyclones will be needed even to meet the current New Source
Performance Standards for particulates from large coal boilers.
Electrostatic precipitators could encounter severe operating problems at
high temperatures and pressures, particularly in maintaining stable
coronas.
Fabric filters are also an option for high pressure operation, but there
is still a great deal of development work needed. A basic problem is
the need for a fabric capable of maintaining its physical integrity under
fabric filter cleaning procedures, hence there is now considerable research
underway to develop "advanced" fibers. Some of the most efficient fabrics
are composed of very fine fibers similar to Brunswick Metal fibers
(~ 8 to 12 microns in diameter). However, corrosion and oxidation of these
metals is greatly enhanced at high temperatures.
106
-------
Table 20. SUMMARY OF POTENTIAL PARTICIPATE REMOVAL SYSTEMS19
System
I. Cyclones
Aerodyne
Tornado
Cyclone
Tan-Jet
Cyclone
II. Gravel bed
filters
III. Electrostatic
precipitators
IV. Molten salt
scrubbers
V. Fabric filters
Silica Fibers
Silica Fibers
Metal Fabrics
VI. Porous metal
and porous
ceramic
filters
Developer
Aerodyne
Development
Corporation
Donaldson
Company
Combustion Power
Ducon
Lurgi-MB-Filter
Rexnord
Squires, CCNY
Battelle
Memorial
Institute
Rockwell
International
Corporation
J.P. Stevens
Company
3M Company
Brunswick
Corporation
(Data not yet ava
Operating conditions
Operated,
°C/atm
900/high
500/30
300/1
> 500/high
150/1
250/1
350/1
500/1
550/1
400/1
900/1
400/1
800/-
1000/-
800/-
llable for 1
Projected,
°C/atm
> 1100/high
900/30
> 1100/20+
950/5+
1100/5+
800/high
icluslon in tl
Particulate
removal
efficiency
for < 1 go
Low
Moderate
High
High
High
High
is report.)
Potential
for
sulfur
removal
None
None
High
None
High
None
Energy penalty/
operating costs
Low/moderate
Moderate/high
Moderate
Low
Moderate
Low
Potential
operat-ing
problems
Low
Low/moderate
Moderate
High
Moderate
Moderate
Comments
Relatively insensitive to variations in tem-
perature and pressure. The cyclone tech-
nology is well developed.
Secondary air requirements and performance at
high temperature and pressure should be
investigated.
Relatively insensitive to fluctuations in tem-
perature, pressure, particle size and gas
composition. Theoretical and experimental
studies are limited. Needs further study in
bed material selection and cleanup.
Sensitive to changes in temperature, pressure,
and gas composition. Needs considerable
developmental work before reliable unit can
be developed. Materials of construction,
alignment, and thermal creep of corona wires
may cause problems.
Particulate entrainment poses additional
cleanup problems. The potential for par-
ticulate removal and desulfurlzatlon may be
attractive in some applications.
Needs considerable developmental work. Casing
material, fabric life, removal of collected
material and other fabric filtration prob-
lems have to be investigated.
-------
Exhaust (Clean Gas)
Secondary
Gas Inlet
Inlet (Dirty Gas
Secondary Air Pressure
Maintains High
Centrifugal Action
.Secondary Airflow
Creates Downward
Spiral of Dust and
Protects Outer Walls
From Abrasion
Dust is Separated From
Gas By Centrifugal
Force, is Thrown
Toward Outer Wall and
into Downward Spiral
Falling Dust is
Deposited in Hopper
Figure 21. Schematic representation of Aerodyne particulate separator
19
108
-------
Gravel bed filter technology is promising, but further development is
also needed here. Exxon is in the process of acquiring a Ducon granular
21
bed filter for their FBC miniplant. The filter should be placed in
operation during 1976. Data on gravel filters are very limited, and the
results of the Exxon studies will be needed for a reasonably accurate
assessment of particulate control efficiency.
Control of Gaseous Emissions
Some of the gases (other than SO and NO ) which could be present in quan-
tities possibly high enough (e'.g. > 10 ppm) to require some sort of control
measures include: HC1, CO, unburned hydrocarbons (HC), and possibly COS-
Each is discussed briefly below.
HC1 - HC1 could be troublesome, especially if Nad is used to enhance SO
sorbent performance as proposed by some workers. If could also be a
problem with high chlorine content coals. Aside from restricting the use
of the above materials, the best control option for HC1 seems to be scrub-
bing with an alkaline spray. Such sprays are sometimes used in solid
waste incinerators; candidate scrubbing solutions are carbonates and bi-
carbonates. For maximum economy, the spray device would also have to be
useful for particulate removal (as discussed more fully in the previous
section).
CO - High CO levels should not be routinely encountered based on available
data from existing FBC units. High CO levels, if they do occur, should
be able to be brought under control by increasing the extent of combustion
within the burner. This can be accomplished in several ways: increasing
excess air, increasing bed residence time, or by addition of secondary air.
The choice between these options is not necessarily straightforward and
will depend on the economics and design features of specific units.
109
-------
Hydrocarbons - Hydrocarbons (HC) are also products of incomplete combus-
tion and their emissions should be able to be reduced by the same techniques
listed above for CO. Studies on HC levels as a function of excess air
indicate very low emissions (< 50 ppm) provided excess air levels are kept
above 15 to 20 percent. Should special circumstances warrant air levels
below 20 percent, one also has the option of collecting some of these
compounds as particulates after cooling the flue gas. Most of the high
molecular weight compounds (especially polycyclic compounds) condense
below 315°C.
COS - COS emissions could conceivably be a problem; if present. COS can
be removed via conventional H S scrubbing techniques such as the Rectisol
process (a methanol scrubbing solution at -55°c), but these are not prac-
tical for combustion gases. Alternate control methods, such as catalytic
destruction, should be investigated. Zinc oxide is very effective in
removing trace quantities of sulfur compounds from hydrocarbon gases at
high temperature. Treatment with zinc oxide in the temperature range
215 to 425 C can produce a product gas having less than 0.1 ppm sulfur,
as COS, H2S, or CS2.22
POLLUTION CONTROL VIA PROCESS MODIFICATIONS: SOME CONSIDERATION BASED
UPON FLUIDIZATION FUNDAMENTALS
The following design and operating parameters can influence pollutant
formation in fluidized bed combustion:
Bed depth
Bed and boiler tube geometry
Fluidizing grid design
Particle size
Fluidization velocity
Excess air
Mechanism of coal injection
Pressure.
110
-------
Most of the above factors are interrelated; e.g., fluidization velocity
and bed geometry affect the quality of fluidization, thus affecting gas-
solid contact, heat transfer, and temperature distribution. The purpose
here is to discuss the manner in which these parameters may affect pollu-
tant formation. This information can then possibly serve as a starting
point for pollution control via modification of appropriate process
parameters.
It is important to note that much of the discussion here is based on exist-
ing models for low temperature fluidized bed systems. There may be diffi-
culties in extrapolating some of the conclusions to the higher temperature
regime of combustion; nevertheless, the discussion provides a useful
starting point for considering some basic problems.
Bed Depth
Bed depth will influence gas residence time, bed pressure drop, and the
quality of fluidization. Its most important influence on pollutant
formation, if any, will probably be in terms of its effect on the residence
23
time of gas within the bed. Zenz has indicated the fraction of gas by-
passing the bed decreases as bed depth is increased and attributed this to
increases in the gas residence time. Because a bubble remains in the bed
for a longer time as the bed depth is increased, it has more time in which
to interchange gas with the emulsion phase. As gas exchange increases,
bypassing is reduced. Increased gas exchange, should increase combustion;
hence, it should tend to reduce the formation of compounds such as CO and
unburned hydrocarbons. Increased gas exchange will enhance in situ cap-
ture of SO
As mentioned above, bed depth will also affect the quality of fluidiza-
tion. Poor fluidization, such as slugging or bubbling, can increase
particle elutriation and emissions of unburned hydrocarbons. According
O /
to the relationship of Broadhurst and Becker the minimum slugging
111
-------
velocity varies inversely as the bed height to 0.9 power for settled bed-
height to diameter ratios less than 3. For height to diameter ratios
greater than 3, Steward predicts the minimum slugging velocity will be
2 S
independent of bed height.
Bed and Boiler Tube Geometry
Bed diameter and boiler tube configuration can influence gas mixing,
slugging characteristics, and bubble flow. Zenz and Othmer report a
twentyfold increase in mixing length (or intensity of mixing) due to
26
an increase in diameter from 1 to 6 inches. An approximately equivalent
effect on eddy diffusivity was noted when diameter increased from 6 to
18 inches. Studies by the National Coal Board (London), however, have
shown that bed cross-sectional geometry had little effect on their re-
27
suits. The effect of geometry most likely will vary from unit to unit;
but, in general, the quality of fluidization increases with increasing
bed diameter, which is encouraging since it implies that full-scale units
may be better behaved than their bench-scale predecessors as far as
potential pollutant generation via phenomena such as bypassing or elu-
triation are concerned.
The boiler tubes can serve to break up bubbles, providing smoother fluid-
ization. However, if they are too densely packed, the tubes can prevent
good mixing in the bed. The influence of boiler tube configuration on
solids-gas mixing (or quality of fluidization) was observed by Exxon
Research and Engineering.28 They noticed flatter temperature profiles,
an indication of good mixing, when the tubes were oriented vertically
rather than horizontally. The configuration of the boiler tubes could
present a problem in scale-up. Tube spacing, pitch, and size affect the
mixing characteristics in the bed and thus affect the temperature profile.29
Packing tubes too closely will cause large temperature gradients.
Exxon noted channeling after installing vertical tube bundles.29 Upon
examination of their tubes, they noticed distinct areas of corrosion.
112
-------
This was attributed to impingement of high velocity gas (channels). They
indicated, however, that channeling could be eliminated by proper design
and operation.
Fluidizing Grid Design
Grid design is an extremely important factor in providing good fluidiza-
tion. Unevenly distributed gas can cause channeling and subsequent de-
activation of portions of the bed, causing potential release of substances
such as S00, NO and hydrocarbons. It is generally recommended that the
z. x
grid pressure drop be 40 percent of the bed pressure drop to ensure uniform
distribution. A better quality fluidization can also be obtained by
30
decreasing hole size and increasing their number. The effect of grid
design is illustrated in Figure 22.31 Sintered plate distributors, al-
though providing the best fluidization, are generally not used in large
commercial operations because of their fragility. However, the combina-
tion of a sintered disk and a sturdy support presents an attractive option.
Bottom has found that a large portion of the chemical reactions occurring
32
in a fluidized bed takes place in the grid region. Between 30 and 50
percent of the fast first order reaction which he studied took place in
that zone. Cooke et al. noticed a rapid reaction between oxygen and coal
in the first 9 inches of a fluidized bed carbonizer and very little above
33
this height. Behie and Kehoe also found the grid zone to be of major
34
importance for fast reactions. Several studies have shown that NO
formation in fluidized beds occurs mainly near the distributor. '
Very little additional chemical change occurs in the rest of the bed.
Accordingly, changes in operating variables such as fuel/air ratio, which
affect the chemistry in the distributor zone, strongly influence the com-
bustion chemistry; hence, this magnifies the importance of grid design.
113
-------
Poor quality; much
fluctuation in density
with channelling ~
and slugging
Single orifice
plate
3'bQdar:
Multiorifice
plate
Better quality; less
fluctuation in density,
~" less channelling
and slugging
Sintered
plate
Figure 22. Quality of fluidization as influenced
by type of gas distributor31
Particle Size
The particle size distribution within the bed can influence not only
the physical characteristics but also the chemical nature of the bed.
It will influence the velocity needed for fluidization, the height of
the dense and dilute phases, elutriation, the quality of mixing, com-
bustion, and channeling and slugging phenomena. The size distribution
may thus affect emissions of SO , NO and hydrocarbons.
tm X
In general, the quality of fluidization is better for smaller average
particle sizes and larger particle size distributions. For high per-
formance chemical reactors (reactors not necessarily designed for com-
bustion reactions), the optimum diameter ratio of the largest to smallest
oy
particle should be between 12 and 21.
114
-------
Elutriation is a function of both velocity and particle size. If the
fluidizing gas travels above the terminal velocity of a given particle,
any decrease in size of the particle will cause it to be carried out
of the bed. This is assuming that there is no particle/particle inter-
action which would cause the minimum fluidization velocity to differ
from the particle's terminal velocity. Due to the complex nature of
a fluidized system, however, particles whose terminal velocities are
greater than the fluidizing velocity can be carried out of the bed.
(A further description of elutriation is presented later in this section.)
Vogel et al. studied the effect of coal feed particle size on SO- reten-
38
tion. They observed similar retentions (about 78 percent) for coal
feeds ground to -12, +50, -50, and -14 mesh. Retention was found to be
better (81 percent) for the coarsest feed. They also found that addi-
tive particle size had only a moderate effect on sulfur retention.
27
Wright has found that decreasing limestone size increases SO- reduction.
A similar decrease in dolomite size had no effect on SO- reduction, which
suggested that access to internal surface was not a limiting factor for
dolomite. An additive too finely ground may have too short a residence
time to achieve a high degree of SO removal. Thus, at high velocity,
the effect of increased surface area may be counteracted by a decrease
27
in residence time. Data obtained from British Studies support this claim.
As mentioned earlier, particle size will influence phenomena such as
bubbling, slugging, and channeling. The minimum slugging height is pre-
39
dieted to change with the -0.3 power of particle diameter. The velocity
at incipient slugging increases as the square root of particle diameter
for height to diameter ratios less than 3. For height to diameter ratios
greater than 3, the minimum slugging velocity increases with an increase
in minimum fluidizing velocity (and thus particle size).
115
-------
Fluidization Velocity
The fluidization velocity will influence gas and particle residence time,
quality of fluidization, elutriation, temperature distribution, arid
chemistry. The quantity, size, and velocity of bubbles, as well as the
amount of gas bypassing as bubbles, is influenced by the superficial ve-
locity. (The fluidization velocity is often expressed in terms of the
superficial velocity, which is the velocity the fluid would have if the
reaction chamber were empty.)
The fluid residence time can be easily determined if plug flow conditions
are assumed and the volumetric flow rate and free volume (total volume
less particle and tube volume) are known. However, due to the turbulent
nature of fluidized bed, a great deal of backmixing occurs. Also, bubbles
pass through the bed at velocities greater than those of the fluid in the
emulsion phase. The fluid, therefore, cannot be characterized by a single
residence time. In the absence of residence time distribution data, a
residence time could be calculated for each phase within the bed; i.e.,
emulsion, bubble, and dilute. In the case of the emulsion and dilute
phases, the residence time can be found by dividing the height of the
phase by actual velocity (superficial velocity/void fraction). Bubble
residence time can be calculated in the same manner; however, the bubble
velocity must be known. Davidson and Harrison have presented a relation
to determine bubble velocity as a function of bubble diameter and super-
AO
ficial and minimum fluidizing velocities. In the absence of any other
information, the maximum stable bubble diameter can be used to determine
the bubble velocity. The maximum stable bubble diameter can be found
40
from knowledge of particle size, particle density, and fluid density.
In general, an increase in velocity causes a corresponding decrease in
residence time.
In some pilot plant experiments, it has been noted that by increasing
the superficial velocity, the primary combustion zone moved from an
116
-------
area near the coal injection point to a zone near the top of the bed.28
Increasing the velocity also had the effect of slightly increasing
temperatures within the bed (presumably because increased velocity also
meant an increase in excess air; hence, better combustion).
Estimating the fraction of gas bypassing the bed is a relatively simple
procedure if the bubble velocity and size are known. Relationships have
been developed for calculating both bubble velocity and bubble size.140'41
However, experimental verifications of these models were performed under
conditions very dissimilar to those in a fluidized bed coal combustion
unit. Hence, although methods are available for estimating the maximum
stable bubble size, which in turn could be used to determine the fraction
of gas bypassing, the results at best should be viewed as upper limits.
Studies of heat transfer coefficients in fluidized beds indicate that the
fraction of gas bypassing can sometimes range between 40 and 70 percent.
The extent of gas and solid mixing is also affected by superficial veloc-
ity. Internal solids circulation is extremely rapid and increases with
velocity. During experiments in a 5-foot diameter, 32-foot deep bed of
catalysts fluidized at 0.8 fps to determine mixing rates, it was found
that 50 grams of powder was essentially completely mixed into 15 tons of
/ o
powder in less than 1 minute.
Excess Air
The amount of excess air will have a direct effect on the chemistry of the
bed; a change in excess air will also affect the bed's physical properties
indirectly at a given coal feed rate by changing the superficial velocity,
the effects of which have been discussed previously. The effect of excess
air on S0~ reduction with limestone, at constant superficial velocity,
has been studied at Argonne National Laboratories. Sulfur reduction
117
-------
increased from 67 to 75 percent when the oxygen level in the flue gas in-
creased from 0.7 to 5.6 percent, which corresponds approximately to an
increase in excess air from 5 to 35 percent. (As discussed previously in
Section III, total hydrocarbon emissions can be reduced to less than
50 ppm provided excess air levels of 15 to 20 percent are maintained.)
An increase in excess air increases the amount of energy leaving the com-
bustor as the sensible heat of the off gases. At low levels, this in-
crease is compensated by the increase in combustion efficiency. At higher
levels, however, the heat removed by the flue gases exceeds that produced
by higher combustion efficiencies. To maintain constant bed temperature,
some heat transfer surface must be removed. If this is not possible,
the bed temperature will drop. Increasing excess air levels even further
(to about 300 percent) will result in a situation where all the heat
transfer surface must be removed to maintain a constant bed temperature.
At this point, the bed becomes an adiabatic combustor. Any increase
beyond this point will lower the bed temperature.
The elutriation rate from a fluidized bed will determine the load on any
particle collection equipment (cyclones) and also the amount of particu-
late emissions. It is affected by such factors as particle size distribu-
tion, particle density, bed cross section, and terminal and superficial
velocity.
The entrainment rate decreases as freeboard height increases. If the
height is increased sufficiently, a height will be reached at which the
entrainment rate is constant. This height is termed the transport dis-
engaging height (TDH) and is defined as the point at which steady flow
conditions are established.
Merrick and Highley have developed both an analytical and numerical model
44
for particle size reduction and elutriation for a fluidized bed process.
118
-------
Data to obtain empirical constants for their relation were taken from the
results of the British Coal Utilization Research Authority's 3- by 3-foot
combustor.
Mechanism of Coal Injection
The manner in which coal is injected into the bed has an effect on combus-
tion efficiency, temperature distribution, and particle residence time.
In some experiments with their batch combustor, Exxon Research and Engi-
28
neering noted burning in the freeboard zone. Although velocity also had
an effect on the degree of combustion in the freeboard, it was determined
that the mechanism of coal feeding was the major source of the problem.
Combustion above the bed was eliminated by changing the position and ori-
entation of the coal feed probe from a position 25 cm above the fluidizing
grid and a 45° angle upward to a position just above the grid and a 45°
angle downward. The observed combustion in the freeboard was attributed
to a reduced particle residence time, resulting from the original coal
feed orientation. Also of interest was the fact that no hot spots were
observed with the new orientation.
Pressure
Pressure will influence gaseous equilibrium concentrations and will also
influence the potential vaporization of various mineral compounds. Pres-
sure will also influence the degree of slugging via fluid density changes.
For height to diameter ratios greater than 3, the minimum slugging veloc-
ity decreases with decreasing minimum fluidization velocity. Because the
velocity at incipient fluidization decreases with increasing fluid den-
sity and thus pressure, the minimum slugging velocity should decrease with
increasing pressure. Viscosity also changes with pressure; for a change
in pressure from 1 to 10 atm, the velocity at incipient fluidization de-
creases by about 0.3 percent. Thus, the change in minimum slugging
119
-------
velocity due to the contribution from the viscosity effects should be
negligible for height to diameter ratios greater than 3. The minimum
slugging velocity increases with pressure at values of height to diameter
less than 3. A tenfold increase in pressure produces an increase in
minimum slugging velocity of about 10 percent.
Pressure also has an effect on entrainment via fluid density changes.
A tenfold increase in pressure causes approximately a tenfold increase
in density (for gases). The terminal velocity of a particle decreases
with increasing fluid density. Therefore, at constant superficial veloc-
ity an increase in pressure will cause larger particles to be elutriated.
This effect is shown in Figure 23. ^
CONTROL OF POLLUTANTS FROM SPENT STONE DISPOSAL
Solid waste could prove to be one of the most significant pollutants
associated with fluidlzed bed combustion simply because of the poten-
tially large quantities of waste produced by once-through sorbent oper-
ation. Table 21 presents estimates of the solid waste disposal require-
ments for a once-through fluidized bed combustion system as a function
of the Ca/S mole ratio and the coal sulfur content.
Table 21.
SPENT BED PLUS ASH PRODUCED BY A 635-MW ONCE-THROUGH
SORBENT FBC PLANT3>46
tons/year)
Ca/S = 2
Ca/S =1.2
1% sulfur
in coal
300
251
2% sulfur
in coal
433
337
3% sulfur
in coal
569
424
4% sulfur
in coal
704
510
Assumptions: Coal feed rate = 430,000 pounds per hour;
Ash content = 12 percent, 165 x 10^ tons/year;
90 percent S0£ removal;
73 percent load factor.
120
-------
3X10"-
V)
to
E
V.
E
2XIO'3
o
3
Q
LJ
h-
CE
O
a
en
tr
*~ I X IO'3
_
o
CO
14.6 ATM
4.4 ATM
I ATM
©
20
40
u0, cm /sec
60
80
Figure 23. Comparison between calculated and experimental entrainment
at various pressures^ (solid lines are calculated)
121
-------
The amount of solids produced at low Ca/S ratios would be similar to that
from limestone scrubbing systems but the total mass of waste would be
50 percent less because the scrubber sludge contains 50 percent water
while the FBC spent stone is dry.
Potential pollution from solid waste disposal includes leachates (trace
elements and organic compounds) and possibly unsightly and large-scale
land fills. As indicated earlier in Table 14 based on an assumed density
of 100 lb/ft3 (65 percent of the theoretical spent stone density), a
635-MW plant burning coal with 3 percent sulfur and 12 percent ash, and
using a Ca/S ratio of 2, would require 260 acre-feet per year for spent
stone disposal. Over a 30-year plant life, a landfill area of 260 acres
would have to be 30 feet deep to accommodate this one plant.
Solid Waste Control Methods
The most effective method to reduce the volume of solid waste and the
overall solid waste problem is to regenerate and recycle the sorbent.
As previously discussed, several regeneration options are being actively
investigated. Keairns et al. have found from laboratory thermogravimetric
testing that the chemistry of regeneration appears to be favorable but
cautioned that other factors such as attrition, coal-ash sorbent agglomera-
tion, tar deposition on the sorbent or eutectic formation could limit the
number of regeneration cycles in a commercial system.47 Based on regenera-
tion kinetics experiments, they suggest that 0.18 moles of Ca may effect-
ively remove one mole of sulfur by being recycled 20 times. Therefore,
compared to a once-through system, the solid waste burden attributable
to sulfur removal would be reduced by 85 percent at a 1.2/1 ratio and
by 91 percent if a 2/1 ratio were required for a once-through system.
Very little experimental information specific to FBC systems is available
with respect to stone disposal or its utilization. However, some insight
to the problem can be gained from a discussion of current methods for
coal ash or scrubber sludge disposal. Due to its high water content
122
-------
(over 50 percent), sludge from limestone scrubbing will almost always be
ponded, either temporarily or permanently. Ponding presents the maximum
potential for ground and surface water contamination, as large quantities
of saturated water are present. Materials including PVC, Hypalon, con-
crete, clay, and asphalt are available for lining ponds to prevent ground-
48
water pollution. Most electric power plants transfer coal ash as a
wet slurry for convenience and for the same reason wet transfer of spent
FBC stone may be considered.
If disposal will occur via landfilling techniques, a landfill site should
be selected and managed to minimize water pollution through leachates or
surface runoff. Geological and hydrological evaluations are particularly
important in selecting a site to minimize water pollution. Typical leach-
ate migration rates range from 0.5 to 30 meters/yr and ground water pollu-
49
tion problems may take several years to develop. Therefore, initial
site selection and immediate pollutant monitoring are very important in
developing new landfill sites and preventing difficult to correct future
pollution problems. The landfill should be located above the natural
water table.and groundwater flows including springs should be rerouted
around the landfill areas.
A hydrogeological investigation is an essential part of selecting a land-
fill site in all areas. ' Boring is required to obtain soil samples
52
and determine water table levels. The purpose of the survey is to de-
termine the potential for leachates to reach the groundwater.
A general recommendation that landfills be located at least 3 to 10 feet
above the water table is based on the natural containment concept. Natu-
ral containment depends on the ability of the soil to attenuate pollutants
contained in the leachate. The best soils for pollutant attenuation,
those which are fine grained; these are usually clays, silts or granular
soils with high clay content. Physical properties of soils meeting
the requirements for natural attenuation are typically: permeability
10~ cm/sec or less, at least 30 percent passing a 200 mesh sieve, a
123
-------
liquid limit greater than 30 percent and a plasticity index greater than
15. Mechanisms causing pollutant attenuation include dispersion, dilu-
tion, filtration, retention, ion exchange and biological breakdown. In
a study of four landfills in Illinois it was observed that chlorides mi-
grated farthest from the landfill site; similar results have been obtained
53 54
by other investigators. ' Soil attenuation of selenium and boron was
reported to be poor.
Semi-artificial containment can be accomplished by selecting a disposal
site where extensive clay deposits are present and the soil is relatively
impervious. Pond liners can be used to artificially contain leachate.
In either case the leachate should be collected and treated with at least
conventional water treatment techniques.
Commercial Uses for Solid Waste By-Products
Commercial uses for the spent stone material are also being investi-
gated. The major obstacles to using the spent stone will be the very
large volumes generated (market saturation), transport costs and
availability of competitive raw materials. As illustrated in Table 22,
fly ash and bottom ash from conventional boilers are used in a number of
products but only about 20 percent of the total is utilized.57 This
indicates that the market in this area for spent stone may be limited.
New uses that have been considered for spent stone include autoclaved
products bricks, hot press sintering-pipes and metal coatings; gypsum
products wallboard and plaster; and mineral recovery. Gypsum from SO
scrubbing is used extensively in Japan,5^ but no large markets exist in
the United States because of an abundant supply of natural deposits.
Treatment of acid mine drainage is also a potential use for spent stone.
Spent stone is also being considered as an agricultural supplement; pilot
studies have shown successful application in peanut farming.
124
-------
Table 22. ASH COLLECTION AND UTILIZATION, 1971
57
Ash utilized:
Mixed with raw material
before forming cement
clinker
Mixed with cement clinker
or mixed with cement
(pozzolan cement)
Partial replacement of
cement in :
Concrete products
Structural concrete
Dams and other
massive concrete
Lightweight aggregate
Fill material for roads,
construction sites, etc.
Stabilizer for road bases,
parking areas, etc.
Filler in asphalt mix
Miscellaneous
Total ash utilized
Ash removed from plant site
at no cost to utility but
not covered in categories
listed under Ash utilized
Ash removed to disposal
areas at company expense
Total ash collected
Fly ash,
tons
104,222
16,536
177,166
185,467
71,411
178,895
363,385
36,939
147,655
98,802
1,380,478
1,872,728
24,497,848
27,751,054
Bottom ash,
tons
NA
NA
35,377
NA
NA
13,942
533,682
7,880
2,833
475,417
1,069,131
542,895
8,446,941
10,058,967
Boiler slag
(if separated
from bottom ash) ,
tons
91,975
NA
76,563
NA
NA
NA
2,628,885
49,564
81,700
428,026
3,356,713
381,775
1,232,298
4,970,786
NOTE: NA - Not applicable.
125
-------
If stone regeneration is used, the final amount of spent stone might be
reduced by 85 to 90 percent. In addition, a low sulfur (0.5 percent)
lime product could be produced if the waste stone is bled out of the
circulation loop after regeneration. This low sulfur lime product could
sell for $20/ton, and at that price would be an economically attractive
by-product.
Several projects funded by ERDA and by EPA are underway to investigate
means for utilization of FBC solid residue. Among the larger utilization
projects aimed specifically at FBC residues are two being funded by ERDA,
one with the U.S. Department of Agriculture (agricultural uses) and one
with IU Conversion Systems, Inc. (nonagricultural uses).
126
-------
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Protection Agency, Research Triangle Park, North Carolina. Publi-
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3. Cowherd, C. et al. Hazardous Emission Characterization of Utility
Boilers. Midwest Research Institute. Prepared for U.S. Environ-
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Publication Number EPA-650/2-75-066. July 1975.
4. Bradway, R. M. and R. W. Cass. Fractional Efficiency of a Utility
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EPA-600/2-75-013a. August 1975.
5. Cass, R. W., R. M. Bradway, and N. F. Surprenant. Fractional Effi-
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GCA/Technology Division, Bedford, Massachusetts. Prepared for U.S.
Environmental Protection Agency. Publication Number EPA-600/2-76-
077a. March 1976.
6. Business Briefs. J Air Pollut Control Assoc. 25(11):1163,
November 1975.
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2-75-020. August 1975.
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(Available from NTIS.) November 1974.
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26. Zenz and Othmer. Op cit. p. 301.
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28. Hoke, R. C. Exxon Research and Engineering Co., Linden, New Jersey.
Private Communication. 1975.
29. Hoke, R. C. Exxon Research and Engineering Co., Linden, New Jersey.
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AIChE J. 19(5):1070-1072, September 1973.
35. Parks, D. J. and E. A. Fletcher. Formation and Emission of NO in
Fluidized Bed Combustion. Environ Sci and Technol. 9:749, 1975.
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38. Vogel, G. J. et al. Bench Scale Development of Combustion and Addi-
tive Regeneration in Fluidized Beds. Proceedings of 3rd International
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Agency. Publication Number EPA-650/2-73-053. December 1973.
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40. Davidson, J. F. and D. Harrison. Fluidized Particles. Cambridge,
University Press, 1963.
41. Zenz and Othmer. Op cit. p. 278.
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Cell. Pope, Evans and Robbins, Inc. Prepared for U.S. Environmental
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in a Fluidized Bed Process. AIChE Symposium Series. 137(70):366-378,
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Control With Limestone/Dolomite in Advanced Fossil Fuel Processing
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version Technology. U.S. Environmental Protection Agency, Research
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48. Rossoff, J. and R. C. Rossi. Disposal of By-Products From Non-
Regenerable Flue Gas Desulfurization Systems: Initial Report.
Prepared for U.S. Environmental Protection Agency. Publication
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Used for Measuring Pollution Parameters of Sanitary Landfill Leachate
(Preliminary Report). Environmental Engineering Section, Department
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for Sanitary Landfills. Waste Age. 5:21, January/February 1974.
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geological Investigation. Waste Age, 1975. p. 16.
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From Solid Waste Land Disposal Sites. Waste Age. 6:50, 1975.
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of By-Products From Nonregenerable Flue Gas Desulfurization Systems.
Proceedings: Symposium on Flue Gas Desulfurization. U.S. Environ-
mental Protection Agency. Publication Number EPA-650/2-74-126a.
December 1974. p. 399.
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Effluent From a Sanitary Landfill. J Water Pollut Control Fed.
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131
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APPENDIX
PRELIMINARY LIST OF CONCEIVABLE POLLUTANTS
Based on preliminary considerations of the prevailing temperatures and
the chemical make-up of a coal-fired fluidized bed combustion system
(coal, limestone, combustion or scrubbing additives, etc.)> a list of
potential pollutants has been prepared and is shown in Table 23.
This list is based on the major elements, C, H, 0, S, N and the principal
trace elements commonly found in American coals. The organic compounds
(including sulfur and nitrogen compounds) are those which could result
from incomplete combustion of coal. Only classes of organic compounds
are listed since further detail would make the list too unwieldy. The
trace element compounds are representative of species expected in the coal
or limestone as well as in the combustion products. Chlorine compounds
of these elements are included since, in some cases, Nad is used to
increase the efficiency of the sorbent bed.
132
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Table 23. PRELIMINARY LIST OF POSSIBLE POLLUTANTS FROM FLUIDIZED BED
COMBUSTION OF COAL
ACIDS AND ACID ANHYDRIDES
1. Organic Acids 0
ii
a. Carboxylic acids: R-C-OH e.g., formic acid, benzoic acid,
etc.
0 0
ii tt
b. Dicarboxylic acids: HO-C-R-C-OH e.g., phthalic acid,
succinic acid
0
t
c. Sulfonic acids: R-S-OH e.g., benzenesulfonic acid
2. Inorganic Acids
a. Sulfuric:. H-SO,
b. Sulfurous: H?SO,
c. Nitric: HN03
d. Nitrous: HNO-
e. Phosphoric: HPO.,
f. Hydrofluoric: HF
g. Hydrochloric: HC1
HALOCARBONS
1. Chlorinated Aliphatics: R - X e.g., chloromethane, chlorobenzene
XVV"X.
2. Chlorinated Biphenyls: I 0 [ 0 1 Cl
133
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Table 23 (continued)
PRELIMINARY LIST OF POSSIBLE POLLUTANTS FROM
FLUIDIZED BED COMBUSTION OF COAL
HYDROCARBONS
1.
2.
3.
4.
Alkynes:
Diolefins:
Olefins:
Aromatics:
-C-C- e.g., acetylene, butyne, propyne,
etc.
-C-C-C-C- e.g., butadiene, pentadiene,
octadiene, etc.
-C-C- e.g., ethylene, propylene, butene,
etc.
0 e.g.,
benzene, toluene, etc.
5. Polynuclear Aromatics:
6. Cyclic Hydrocarbons: I I
i i
7. Aliphatic Hydrocarbons: -C - C-
t «
e.g., anthracene, pyrene,
phenanthrene, etc.
e.g., cyclopentane, cyclo-
pentadiene, etc.
e.g., methane, ethane, propane,
etc.
NITROGEN COMPOUNDS
1.
2.
3.
4.
5.
6.
NO
N02
HCN
(CN)2
NH3
Amines :
7. Pyridines:
R-N e.g., methylamine, ethylamine, aniline, etc.
e.g., pyridine, quinoline
N
134
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Table 23 (continued). PRELIMINARY LIST OF POSSIBLE POLLUTANTS FROM
FLUIDIZED BED COMBUSTION OF COAL
8. Pyrroles:
o
9. Nitrate Salts: MNO (where M is any cation)
10. Nitrite Salts: MN02 (where M is any cation)
11. Nitrosamines: R - N - N = 0
12. Azoarenes: en - N = N
OXYGEN COMPOUNDS
1. Furan:
2. Ethers: R-O-R e.g., phenyl ether, anisole, etc.
0
3. Esters: R-C-OR e.g., phenylacetate, benzylacetate, etc.
A. Epoxides: -C-C- e.g., ethylene oxide, propylene oxide, etc.
V
5. Alcohols: R-OH e.g., methanol, phenol, etc.
0
6. Aldehydes: R-C- e.g., formaldehyde, benzaldehyde, etc.
0
7. Ketones: R-C-R e.g., acetone, benzophenone, acetophenone
PARTICULATES
1. Size Distribution
a. < 2 ym
b. 2 ym < > 20 ym
c. > 20 ym
135
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Table 23 (continued). PRELIMINARY LIST OF POSSIBLE POLLUTANTS FROM
FLUIDIZED BED COMBUSTION OF COAL
RADIOACTIVE ISOTOPES
1. Uranium-235, Polonium-210, Lead-210, Radium-226, Bismuth-210,
Thorium-227, Radon-222.
SULFUR COMPOUNDS
2. S03
3. H2S
4. COS
5. CS2
6. S
x
7 . Thiophenes : fj jl
S
8. Mercaptans: R-SH e.g., methyl mercaptan, phenyl mercaptan
9. Sulfates: MSO, (where M is a metal ion) e.g., FeSO,, PbSO, , etc.
10. Sulfites: MSO. (where M is a metal ion) e.g., CaSO
TRACE ELEMENTS AND THEIR COMPOUNDS
1. Nickel: NiS, NiO, Ni^, Ni(CO)4, NiSO^, NiCOg, NiCl2,
Ni(CN)2, Ni(OH)2
2. Cadmium: CdS, CdO, CdS04, CdCOj, Cd(CN)2, CdCl2, Cd(OH)2
3. Mercury: HgS, HgO, Hg20, Hg(CN)2> HgSO^, Hg2S04, HgC03>
HgCl, HgCl2
136
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5. Lead:
6. Sodium:
, Pb(CN)2,
Table 23 (continued). PRELIMINARY LIST OF POSSIBLE POLLUTANTS FROM
FLUIDIZED BED COMBUSTION OF COAL
4. Zinc: ZnS, ZnO, Zn02> Zn(SO)4, ZnCO.,, Znd2, Zn(CN)2>
Zn3N2, Zn(OH)2
PbS, PbO, Pb?0~, Pb~0,, PbC
PbCl2, PbN6, Pb(OH)2, PbOH
Nad, Na~0, Na~S04, Na?CO~, NaNH?, NaN.,, NaCN, NaH,
NaHSO , NaHSO , NaHCO , NaOH
7. Potassium: KC1, K00, K.SO., K0CO_, KCNO, KCN, KHS, K0S000,
/ Z 4 Z J Z 2 o
Kr* c v c r\ LTU f^r\ T^UCO v c % r\ v c -j ^ v
rtV-'OQ ) iXrtO L^« 9 r^novj 9 ixnovj. 9 R._OJ.,-.V^ 9 ix oi^u 9 ^.
8.
9.
10.
11.
12.
13.
14.
Vanadium:
Cobalt:
Molybdenum:
Copper :
Beryllium:
Selenium:
Arsenic :
V2°5> V2°3> V2°4
CoS, Co 0 CoO,
Co (CO). , Co(CN)
4 2
MoS», Mo«0_, MoO
2' 2 3'
CuS, Cu2S, Cu20,
CuCN, Cu N, CuOH
BeO, Be0C, Be(SO
z
c^jC QoQ QoA
OCO^^, OCiJ, OCW^^,
As S As S As
, V2S3, VOS04, Na20 - V^
Co203, CoS04, CoC03, CoCl2,
, Co (OH)
2
3, Mo (OH) 2
CuO, CuCO , CuSO CuCl, CuCl ,
, Cu(OH)2
4)2, BeC03, BeCl2, BeH2 , Be^
H2Se03, H2Se04, Se^l^ SeCl4 ,
S As 0 As 0 H AsO AsH
AsCl
15. Antimony:
16. Fluorine:
SbCl5, Sb(OH)3
F 0 , F 0, F , NO F, HSO F, fluorinated hydrocarbons
137
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Table 23 (continued). PRELIMINARY LIST OF POSSIBLE POLLUTANTS FROM
FLUIDIZED BED COMBUSTION OF COAL
17. Chlorine:
18. Thallium:
19. Manganese:
20. Iron:
21. Barium:
22. Tellurium:
23. Titanium:
24. Silicon:
25. Aluminum:
26. Magnesium:
27. Calcium:
C120, C102, HC103, HC1, C12, C120?, MCIO^ (where M
is a metal) , chlorinated hydrocarbons
T12S, T120, T1203, T12S04, T12C03, T1C1, T10H
MnS, MnS2, Mn^, Mh^, Mn02> MnS04> MnC03> MnCl2>
Mn(CO)3, MnSi03, Mn(OH)2
FeS, FeO, Fe.O-, Fe3°4» FeSOA> FeCOo> FeCl~, Fed-,
Fe(CO)5, H2Fe(CO)4, Fe(OH)2
BaS, BaO, Ba02, BaC03, BaSO,, BaS03, Ba(N03)2,
BaCl2, Ba(CN)2,
TeS2, Te02, H
Ti02, TiH2, TiCl2, TiOS04,
Si02, H2Si03, SiC, SiH4, SiO,
A12S3, A12(S04)3, A1203 3Si02,
A1N, A10, A1(OH)
Mg(OH)2>
MgO, Mg02, Mg2Si3Og, Mg2Si, MgS04,
MgS203, MgCl2, Mg(NH2)2, MgH2
CaS, CaC2, CaCO.., CaCl2> CaNCN, Ca(CN)2> CaH2> CaO,
Ca02, Ca2Si04, Ca3Si207, Ca-jSi-jOg, Ca4(H2Si40, 3) ,
CaS04, CaS203, Ca(OH)2
MISCELLANEOUS POLLUTANTS
1. Biological Oxygen Demand (BOD) 4.
2. Chemical Oxygen Demand (COD) 5.
3. Thermal Discharge 6.
Noise
Odor
Biological Agents - bacteria,
virus, spores, etc.
138
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-77-054
2.
3. RECIPIENTS ACCESSION-NO.
4. Tl
LE AND SUBTITLE PRELIMINARY ENVIRONMENTAL
ASSESSMENT OF COAL-FIRED FLUIDIZED-BED
COMBUSTION SYSTEMS
5. REPORT DATE
Mavl977
6. PERFORMING ORGANIZATION CODE
7.AUTHOR
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