Health and Environmental
Effects of Coal
Technologies
Background Information on
Processes and Pollutants
Sponsored by the
Federal Interagency Committee on
the Health and Environmental Effects
of Energy Technologies
Department of Energy
Department of Health,
Education, and Welfare
Environmental
Protection Agency
Executive Secretariat
The MITRE Corporation/ Metrek Division
McLean, Virginia 22102
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DOE/HEW/EPA-04
MTR-79W0015901
Health and Environmental
Effects of Coal
Technologies
Background Information on
Processes and Pollutants
Sponsored by the
Federal Interagency Committee on
the Health and Environmental Effects
of Energy Technologies
Edited by:
Richard Brown
August 1979
Prepared by:
The MITRE Corporation
Metrek Division
Executive Secretariat
The MITRE Corporation /Metrek Division
1820 Dolley Madison Boulevard
McLean, Virginia 22102
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FOREWORD
In his 1977 Environmental Message, President Carter directed the
Secretary of Energy, the Secretary of Health, Education, and Welfare,
and the Administrator of the Environmental Protection Agency to estab-
lish a joint program to identify the health and environmental problems
associated with advanced energy technologies and to review the adequacy
of present research programs. In response to the President's directive,
representatives of the three agencies formed the Federal Interagency
Committee on the Health and Environmental Effects of Energy Technologies.
The MITRE Corporation, Metrek Division, is the Executive Secretariat
for the Committee.
The goals of this Committee are to review and identify specific
health and environmental issues and potential problems associated with
the development and commercialization of conventional and advanced
energy technologies, to identify the information required to resolve
the uncertainties of relevant impacts, to specify research projects to
provide such information, and to review the adequacy of current Federal
research with respect to these projects. To attain these goals, the
Committee is sponsoring a series of workshops, establishing working
groups, and initiating other approaches to address the health and
environmental consequences of energy technologies.
This report provides technology descriptions and characterization
of air emissions, water effluents, and physical disturbances associated
with coal-based technologies. The material was prepared as background
information for use by the working groups for conventional and advanced
coal technologies.
The coal-based technologies addressed in this document are
conventional coal, chemical coal cleaning, fluidized bed combustion,
magnetohydrodynamics, coal-oil mixtures, cocombustion with municipal
solid waste, and in situ coal gasification. Because the subject
of underground coal conversion is being reevaluated, it has been
included within this compilation of background information. Background
information on other technologies associated with coal gasification and
liquefaction, as well as related information on health and environmental
problems and research needs,may be found in documents previously released
by the Committee and listed within the appendix. Although every effort
has been made to provide up-to-date information on technology descriptions
and source characterization in these documents, including an extensive
review by scientists involved in technology development, the reader is
cautioned that such information rapidly becomes dated as these technologies
are refined.
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A report relating to the health and environmental effects and
research needs associated with conventional and advanced coal technologies
will be a product of current activities of the Committee's coal working
groups. The results of these and other activities sponsored by the
Committee should provide a basis for strengthening the Federal Program
for ensuring safe and timely development of our energy resources.
THE FEDERAL INTERAGENCY COMMITTEE
ON THE HEALTH AND ENVIRONMENTAL
EFFECTS OF ENERGY TECHNOLOGIES
lv
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FEDERAL INTERAGENCY COMMITTEE ON THE
HEALTH AND ENVIRONMENTAL EFFECTS OF ENERGY TECHNOLOGIES*
DEPARTMENT OF ENERGY
Murray Schulman
DEPARTMENT OF HEALTH, EDUCATION, AND WELFARE
National Institute of Environmental Health Sciences:
Philip E. Schambra
National Institute for Occupational Safety and Health:
A. W. Thomas
William Wagner
ENVIRONMENTAL PROTECTION AGENCY
William Frietsch
Committee Membership as of August 1979
v
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CONTRIBUTORS
PROJECT MANAGER
Richard Brown
TECHNICAL ASSISTANT
Ruth Cooke
COPY EDITOR
Marion Meader
SECTION AUTHORS
Conventional Coal
Richard Brown
Marion Meader
Chemical Coal Cleaning
Marvin Drabkin
Vanessa Fong
Fluidized Bed Combustion
Ernest Robison
Magnetohydrodynamics
George Mouchahoir
Coal-Oil Mixtures
Albert Sabadell
In Situ Coal Gasification
Richard Brown
Cocombustion with Municipal Solid Waste
Ramabhadran Narayanan
vi
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TABLE OF CONTENTS
Page
PART 1 - CONVENTIONAL COAL 1
PART 2 - CHEMICAL COAL CLEANING 77
PART 3 - FLUIDIZED BED COMBUSTION 149
PART 4 - MAGNETOHYDRODYNAMICS 199
PART 5 - COAL-OIL MIXTURES 237
PART 6 - COCOMBUSTION WITH MUNICIPAL SOLID WASTE 263
PART 7 - IN SITU GASIFICATION 371
APPENDIX A - CONVENTIONAL COAL 401
APPENDIX B - CHEMICAL COAL CLEANING 439
APPENDIX C - FLUIDIZED BED COMBUSTION 465
APPENDIX D - COAL-OIL MIXTURES 471
APPENDIX E - IN SITU GASIFICATION 481
APPENDIX F - OTHER COMMITTEE REPORTS 509
vii
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Part 1
Conventional Coal
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TABLE OF CONTENTS
Page
LIST OF ILLUSTRATIONS 3
LIST OF TABLES 4
SECTION I - TECHNOLOGY DESCRIPTION 7
CHARACTERISTICS OF COAL 7
EXPLORATION AND DEVELOPMENT 8
EXTRACTION 10
Underground Mining 11
Underground Atmospheres 14
Surface Mining 14
COAL PREPARATION 17
TRANSPORTATION 18
END USE 19
SECTION II - POLLUTANTS AND DISTURBANCES 22
INTRODUCTION 22
EXTRACTION 27
Solid Wastes 27
Erosion 38
Subsidence 39
Water Effluents 43
Air Emissions 44
Accidents 50
PREPARATION/PHYSICAL COAL CLEANING 51
Trace Element Leaching 53
Accidents 54
TRANSPORTATION 54
Rail and Truck 56
Water 56
Pipeline 56
Accidents 58
1
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TABLE OF CONTENTS (Continued)
page
COAL STORAGE 58
END USE 60
Air Emissions 61
Water Emissions 64
Solid Wastes 67
Accidents 68
REFERENCES 71
2
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LIST OF ILLUSTRATIONS
Figure Number Page
1
Means of Entry to Underground Bituminous
Coal Mines
12
2
Area Surface Mining Method
15
3
Coal Slurry Pipelines
20
4
Potential Organic Contaminants from Coals
24
5
Balance of Environmental Contamination for
Coal Processing and Utilization
36
6
Thermal Effluent Control Systems
65
3
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1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
LIST OF TABLES
Page
Coal Ranks and Typical Characteristics 9
Major Pollutants Associated with the
Conventional Coal Energy Cycle 23
Major Inorganic Elements in Coal 25
Major Minerals in Coal 26
Iron Sulfides Cause Major Environmental
Problems 28
Trace Elements of Environmental Concern in Coal 29
Summary of Potential Air Contaminants in Coals 30
Summary of Potential Water Contaminants in
Coal 31
Environmental Contamination from Coal Mining 32
Environmental Contamination from Coal
Preparation 33
Environmental Contamination from Coal Storage
and Transport 34
Environmental Contamination from Coal
Combustion 35
Representative Rates of Erosion from Various
Land Uses 40
Land Disturbed per Million Tons of Surface
Coal Mined 41
Typical Acid Mine Drainage 45
Emission Factors for Coal Refuse Fire
Emissions 48
Polycyclic Organic Materials Emitted from
Coal Refuse Fires, and Their Carcinogencity 49
Injury Rates in Selected Industries, 1973 52
Quality of Surface and Ground Water in a
Pennsylvania Coal-Mining Region 55
Environmental Considerationa Associated with
Various Coal Transportation Scenarios 57
Diluted and Undiluted Effluent Concentrations
from a Representative Coal Stockpile 59
Comparison of Emissions from Conventional
Coal and Other Energy Technologies 62
4
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Table Number
23
24
LIST OF TABLES (Concluded)
Page
Percentage of Trace Elements in Input
Coal Discharged in Flue Gas 63
Range of Concentrations of Chemical Con-
stituents in Flue Gas Desulfurization 69
Sludges
5
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SECTION I - TECHNOLOGY DESCRIPTION
CHARACTERISTICS OF COAL
Coal is a combustible, rocklike substance formed from plant
remains that have undergone physical and chemical changes through
geological processes. In early geological times a warm, moist climate
prevailed and swamps covered large parts of the world. Ferns, reeds,
mosses, and other plants grew in great numbers, sometimes reaching as
much as 200 feet in height. After the plants died and sank to the
bottom of the swamps, water and new layers of plant material sealed
them off from the air, preventing them from decaying completely. Some
of this mass was covered by the sea, which deposited layers of in-
organic sediment, sand, and dirt, forming the overburden now found
over coal seams. Thus, coal lies in giant subterranean sandwiches,
shallow or deep, flat or pitched. Most coalbeds are broad and thin,
and are within 3,000 feet of the surface.
The plant materials from which coal is formed consist primarily
of carbon, hydrogen, and oxygen. Under heat and pressure, the hydro-
gen and oxygen are driven off in the form of water and gases, such as
carbon dioxide and methane. The material remaining is composed mostly
of carbon. The more heat and pressure that were applied, the greater
the percentage of carbon and the harder the coal.
Coal also contains varying amounts of water, combustible gases
and other volatile materials, and mineral impurities, such as sulfur,
silica, iron sulfide, calcium and magnesium carbonates, phosphates,
and clay. During the formation of coal, movement of the earth's crust
caused cracks and crevices which were filled by mud deposits of shales
and pyrites. Intrinsic within coal is ash, largely withdrawn from
soil and incorporated into biomass by the original vegetation. There-
fore, coal has no fixed chemical composition but varies widely accord-
ing to the amount of inorganic impurities, its basic carbon content,
and its stage of development (see Appendix A, Figure A-l). Most of
the environmental contamination associated with coal is a direct
result of these components of coal and substances in the ash.
Depending on coalbed formation and the extraction procedures em-
ployed, the relative amount of extraneous minerals in mined coal can
range up to 40 percent, with even higher percentages occurring as a
result of partings, roof falls, and other unplanned events. Recently
developed automatic mining techniques have increased the amount of
adulteration of mined coal over coal mined by manual labor. Thirty
years ago, a typical mine produced 10 tons of refuse for every 100
tons of raw coal. In 1975, about 29 percent of raw coal was refuse
(Bureau of Mines 1977).
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Coals are divided into classes: anthracite, bituminous, sub-
bituminous, and lignite. Heat and pressure force moisture and hydro-
carbons from peat (which is the earliest stage in the formation of
coal) until progressively higher ranks of coal are formed. Thus,
anthracite contains the highest percentage of carbon and the lowest of
moisture. The chemical and physical properties of other types are
between lignite and anthracite.
The variability in the properties of coal requires a classifica-
tion system to supply data for end uses, methods of burning, and
selection of equipment. Classification by rank is fundamental in coal
description and in the United States is based on the degree of meta-
morphism in the natural series from lignite to anthracite and upon
values for volatile matter, fixed carbon, moisture, and ash obtained
from standard face samples. The American Society of Testing Materials
standards and locales of various typical ranks of coals are shown in
Table 1 .
About 5 million tons of anthracite (found mostly in Pennsylvania)
were produced in 1975 (in 1975, 29 percent was used by electric utili-
ties). On the other extreme of ranking, lignites, which are low in
caloric value and normally (up to 70 percent in Alabama lignites) low
in sulfur content, contain 30 to 50 percent moisture and 5 to 10 per-
cent ash. In 1975, production of lignite from the northern Great
Plains and Texas surface mines (no significant underground production)
totalled 20 million tons, of which two-thirds was consumed by mine-
mouth generating plants. The balance was shipped short distances by
rail or truck. Next higher in ranking above lignites are subbitumin-
ous coals, which are generally surface mined from thick seams in
highly accessible areas at relatively low costs. They are compara-
tively low in moisture, ash, and sulfur content and most are located
in Montana, Wyoming, Colorado, New Mexico, Arizona, and Washington.
Bituminous coals, high in caloric value and ranging in sulfur from
less than 0.4 percent to as high as 10 percent are found in Eastern
(Appalachia), Central, and Southern states and in Colorado, Utah, and
Montana (see Appendix A, Figure A-2 (Gibbs and Hill 1978; The Science
and Public Policy Program 1975; Bureau of Mines 1977; Palowitch 1979).
EXPLORATION AND DEVELOPMENT
Producing coal in sufficient quantities at a competitive cost
and processing it to the proper grade for market demand is the science
of the coal industry. The pick-and-shovel miner has all but dis-
appeared from the American scene. Today's miner is a skilled techni-
cian who handles complex, costly, and highly efficient machines.
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TABLE I
COAL RANKS AND TYPICAL CHARACTERISTICS
Coal rank Coal analysis, bed moisture basis
Class
Group
State
County
M
VM
FC
A
S
Btu
1. Anthracitic
1.
Meta-anthracite
Pa.
Schuylkill
4.5
1.7
84.1
9.7
0.77
12,745
2.
Anthracite
Pa.
Lackawanna
2.5
6.2
79.4
11.9
0.60
12,925
3.
l
5
1
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Before a mine can be opened, a considerable amount of capital
must be committed, and it must be certain that the appropriate man-
power, material, and equipment can be obtained by the operator. Costs
vary significantly from site to site. A 1976 estimate gave the fol-
lowing results in dollars per annual ton capacity (Land 1976).
Appalachia
Illinois
Basin
Western
Surface
Underground
47
66
50
48
18
48
After a prospective coal deposit is identified, usually through
quantitative estimates of reserves based on assumed continuity of
known coal beds, core holes are drilled to determine the spatial ex-
tent of the deposit, bed thickness and anomalies, character and thick-
ness of overburden, hydrology, number of minable beds, and for chemi-
cal analyses to determine the ash, sulfur, and caloric content of the
coal. Thorough mapping of each coal bed is essential for planning the
efficient operation of a specific mine. Available delineation tech-
niques include a review of geophysical and geochemical data, drilling
and core sampling of strata, and the use of seismic measurements.
Despite the availability of an array of exploratory tools, drilling
remains the primary method for locating and mapping coal deposits.
Production requirements and the extent of coal reserves generally
determine the method of mining and the type and capacity of equipment
to be used. Amortization and an adequate return on the investment are
also factors to be considered. Development is commonly planned for
the life of the property. Mine development includes selecting the
type of mining equipment to be used; the planning of transportation
and water drainage patterns; the layout and construction of access
roads, rail siding, preparation facilities, storage facilities, and
buildings for various support functions; roof supports, lighting and
methane liberation systems, equipment access and coal conveyance tun-
nels, ventilation systems; and the designing and building of shafts,
drifts, or slopes to the coalbed (for underground mining).
EXTRACTION
Coal is mined either by surface (i.e., strip) or underground
methods. The choice of particular method depends upon: the thickness
and type of cover over the coalbed; the thickness, rank, sulfur con-
tent and purity of the coalbed; the pitch, uniformity, and presence of
geologic discontinuities in the coalbed; the quantity of water and gas
10
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likely to be encountered; the nature and strength of the strata en-
closing the coalbed; the washability characteristics of the coal; and
the proximity of previous or current raining in adjacent coalbeds. The
method finally selected is the one which will provide: the maximum
degree of safety and health for mine personnel; the lowest investment
and operating cost per ton of product; maximum recovery of resource;
maximum salable product (with or without preparation); and minimum
adverse environmental impacts (Palowitch 1979). A comparison of coal
mining methods is given in Appendix A, Table A-l. A report by the
Office of Technology Assessment, The Direct Use of Coal (1979), was
utilized for much of the following description of mining methods.
Underground Mining
When the factors listed above warrant underground removal, the
mining is considerably more complex than surface excavation. Instead
of removing the overburden, extracting and transporting the coal away
from the mine, the underground miners work with the thick overburden
above them, connected to the surface by shafts and passageways
sometimes thousands of feet long. A portal (passageway to the seam)
must be constructed. The location and type (generally shaft, slope or
duct) depends on the site (Figure 1). From the portal, parallel
entries are driven into the coal to provide corridors for haulage,
ventilation, power, etc. Cross-corridors then reach to the sides of
the mine, leaving pillars to support the roof — the deeper the mine,
the bigger the pillars. The systems of underground mining generally
in use in the United States are room-and-pillar and longwall.
In the room-and-pillar system, sometimes less than 50 percent of
the coal can be removed; in such cases the pillars may be removed in
subsequent mining. As the equipment retreats back toward the main cor-
ridors, the roof must be supported by other means or the overlying
strata allowed to collapse. About 90 percent of the coal can be mined
in this second mining and low-cost coal is produced.
The type of equipment used ranges from the relatively simple to
highly automated and productive machinery. Selection of equipment de-
pends on a complex of factors, the most important of which are the
relative difficulties of supporting the immediate roof, the height of
the seam, grades of coal, maintenance required on machinery, and the
productivity of manpower relative to types of machines. The oldest
method, in occasional use in very small mines, is primarily hand
labor. The coal is undercut at the face, and blasting holes are
drilled into its face. Explosives shear the coal loose by forcing it
down into the cut. It is then hand loaded into shuttle cars. This
method has been almost entirely replaced by conventional mining in
which several machines are used in a cycle of operation: mechanized
undercutting, drilling, loading, and transporting by shuttle car or
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DRIFT MINE
SLOPE MINE
SOURCE: U.S. Environmental Protection Agency 1974.
FIGURE 1
MEANS OF ENTRY TO UNDERGROUND BITUMINOUS COAL MINES
12
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conveyor. Huge chain saws protruding from the bottom of self-
propelled vehicles are used for undercutting. The saws cut a slot
about 4- to 8-inches high and 10 feet deep into the coal and then
perhaps 20 feet across the face. This machine then moves to the next
face while a drilling machine takes its place. The coal drill is a
self-propelled vehicle with a long auger attached to a movable boom.
It drills holes above and as deep as the cut. For a face area 3 to 4
feet high and 4 to 5 feet wide, one hole is required. If there is rock
in the coal, more holes may be needed. Chemical explosives or com-
pressed gas are used for blasting (shooting).
Compressed gas is considered safer but is slower, as only one
hole at a time can be shot. A machine slides the coal onto a conveyor
belt that dumps it into a shuttle car. The cars either take the coal
directly out of the mine or, at a change point, the coal is trans-
ferred to conveyor belt or mine car. Roof bolting also is an integral
part of the operation. A bolting machine drills holes into the roof,
and anchor bolts held by expansion devices or resin firmly attach the
roof to stronger overlying layers of rock. A 4-by-4-foot array of
bolts is generally required. These operations, among the most
dangerous in the mine, produce a large amount of dust and liberate
methane from the coal. Exposed areas are rock-dusted to prevent coal
dust explosions. Frequent methane testing is required at the face.
Continuous monitoring is required under some conditions. To prevent
water from entering and to eliminate it from the mine are the aims of
mine drainage systems. In extreme cases over 30 tons of water have to
be removed for each ton of coal mined.
To increase productivity, continuous mining machines were devel-
oped. These bore or rip to dislodge the coal from the face without
blasting, then load the coal into the transportation system.
Longwall mining is a significantly different approach than con-
ventional or continuous mining. The demand for metallurgical coal has
necessitated mining deeper into the earth. Mechanical plows and
shearers have made it economically feasible to use this system.
Corridors 300 to 600 feet apart are driven into the coal and inter-
connected. The longwall of the interconnection is then mined in
slices by the plow or shearer which is pulled back and forth across
this working face, several hundred feet long. Self-advancing
hydraulic jacks support the roof as the shearer makes a pass across
the face and the coal is removed by conveyor. The roof collapses in
the mined-out area behind the jacks. Almost all the coal can be
extracted by this process. A variant of the longwall technique is
called the shortwall. This concept is similar, but the shorter side
of the rectangle (usually less than 200 feet) is mined.
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Underground Atmospheres
Large quantities of methane within coal seams and adjacent strata
represent a significant energy resource, but also pose a major safety
hazard in coal mining. The recent Scotia, and earlier mine disasters,
serve as constant reminders of the dangers related to methane libera-
tion in coal mines. Most of the extensive precautions taken regarding
ventilation, permissible equipment, and air quality monitoring are in
response to this specific hazard.
To keep mines at safe methane-concentration levels requires the
circulation of large amounts of air throughout the mine. Current
state and Federal regulations require the shutdown of equipment when
methane concentrations exceed 1 percent. Even with maximum allowable
air flow rates in production sections, coal cutting is often slowed or
halted due to high methane liberation, resulting in reduced efficiency
and increased costs. For example, the production potential of the
continuous miner, the basic mining machine presently used, is fre-
quently not achieved. Degasification, removing most of the methane
from the coalbed before mining, can alleviate methane-related mining
problems and also tap this important natural resource. In a program
begun several years ago, three basic degasification techniques are
being developed: vertical wells, directional drilling, and horizontal
drilling (U.S. Department of Energy 1978a).
Surface Mining
Until about 1965 underground methods were used unless the over-
burden to seam thickness ratio was 10 to 1 or less; that is, to remove
50 feet of overburden, the coal seam would have to be at least 5 feet
thick. This ratio has been increasing, and depending on the structure
and nature of the overburden, coal within 150 feet of the surface may
now be economically recoverable, even when the overburden-to-seam
thickness ratio is as much as 30 to 1 (University of Oklahoma 1975).
Based on the thickness of cover, topography of the coalbed, and topo-
graphy of the surface terrain, the deposit will be mined by either
area, open-pit, contour, or auger methods.
Area Method
Area mining is the primary surface-mining method used on Mid-
western and some Western coal fields. Where the coalbed is relatively
flat, lies under flat or gently lying terrain, and the depth of over-
burden does not exceed about 150 feet, the coalbed can be mined by
taking successive parallel cuts which may be as much as 100 feet wide
and several thousand feet long (Figure 2). For each cut, the over-
burden is removed by a dragline, power shovel, or bucket-wheel excava-
tor to expose the coalbed. Drilling and blasting is often needed to
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^ ^ A A >
A A A
JL ± ^ l
jC^ ^ ^ <£¦
X i>
RECLAIMED AREA -A ^ -
• __ — ^
SOURCE: U.S. Environmental Protection Agency 1974.
FIGURE2
AREA SURFACE MINING METHOD
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fracture the overburden and the coal seam. The exposed coalbed then is
drilled and blasted lightly and the shattered coal is loaded by a
small power shovel into dump trucks for transport to the preparation
plant or railhead.
After the coal from a cut is removed, the overburden from the
next successive cut is placed in the void left by the previous cut.
This succession of cuts is repeated until the coal lease is worked
out, the quality of the coal deteriorates, the overburden-to-seam
ratio increases and the costs become excessive.
Reclamation of the disturbed land follows closely after termina-
tion of the mining operation. Depending on local, state or Federal
regulations, this may include rough grading, final grading to essen-
tially the original contour, and the planting of trees or legumes.
Open-Pit Method
Open-pit mining is somewhat similar except that a larger area
perhaps 1,000 to 2,000 feet wide is prepared. The overburden is moved
around in the pit by truck and power shovel to uncover the coal seams.
This technique is used primarily for the very thick Western seams.
Contour Method
Contour strip mining is practiced most commonly where the coal
lies under hilly to mountainous terrain and outcrops on the hillsides.
The overburden is removed from over the outcropping coalbed by a
stripping shovel or bulldozers and high lifts to expose a 40- to
50-foot wide section of coal. This exposed coal then is drilled,
blasted, and loaded into trucks for hauling from the pit to a prep-
aration plant or railhead.
Depending on the steepness of the hillside, additional cuts may
be made parallel with the outcrop. The newly excavated overburden is
placed into the void left by the previous cut. Mining ceases when the
height of the highwall created exceeds the digging capacity of the ex-
cavation equipment. As in other surface mining methods, reclamation
follows coal extraction to meet regulating standards.
Auger Mining
For coal seams continuing under rising land too steep or high to
allow normal contour mining and where underground equipment cannot
burrow further because of the shallow and more treacherous roof con-
ditions, auger mining is used. Huge drills with cutting heads up to 7
feet in diameter are driven deep (up to 200 feet) into the coal seam.
Auger recovery gives additional tonnage at minimal cost and labor and
permits recovery of coal that might not be recovered by other methods.
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COAL PREPARATION
Impurities in coal can be divided into two general classifica-
tions inherent, and removable. The inherent impurities are chemically
combined with coal and require chemical coal cleaning methods. The
removable impurities are extraneous and can be eliminated by crushing
and separation to the extent economically justified. About 41 percent
of the bituminous coal and lignite produced in 1975 was mechanically
cleaned, but of the nearly 500 million tons of coal used by the util-
ity industry, only about 20 percent was cleaned (Bureau of Mines
1977).
From four carLoads of raw coal, roughly one carload of
impurities can be removed by physical coal cleaning.
The utility that uses clean coal can benefit from
lower shipping costs and reduced sulphur emissions,
and in some cases improved boiler reliability. As
coal prices rise, as run-of-mine quality diminishes,
the coal-cleaning option becomes more attractive.
(Electric Power Research Institute 1979).
The most common processes for achieving this separation are based
upon the difference between the specific gravities of the impurities
and that of the coal. Simply stated, coal has a specific gravity of
about 1.3, which is less than that of its impurities. Thus, when the
free particles of coal and impurities are distended in water or some
other heavy media intermediate between coal and rock, a separation
occurs as the heavier and undesirable particles settle at a faster
rate than the coal. In commercial-scale cleaning operations, it is
not uncommon to process 500 to 1,000 tons of coal per hour, using a
variety of equipment designed specifically for the makeup of the
particular raw coal being processed and the desired end product (U.S.
Environmental Protection Agency 1977b).
Generally, physical coal-cleaning processes are classified as
(1) gravity-based stratification or (2) nongravity processes.
Included in the first category are such wet processes as dense media
processes, pneumatic processes, launder washers, jigs, classifiers,
and tables; the nongravity category includes froth flotation. Some
other techniques being currently evaluated include thermal-magnetic
separation, immiscible liquid separation, selective flocculation,
electrokinetic separation and two-stage froth flotation (Kilgore
1976).
In conventional coal technology, the two fundamental objectives
in crushing coal are to reduce raw coal from the mine to sizes suit-
able for cleaning and to meet the market specifications for specific
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sizes. Traditionally, the production of fines has been considered
undesirable. Thus, crushers are designed to produce a minimum of
undersize material. Various types of crushers include rotary break-
ers, roll crushers, hammermills, and rin crushers (McCandless 1978).
Jigs are based on the process of particle stratification of the
range of specific gravities included in the raw coal. The stratifica-
tion results from repeated dilation and compaction of a bed of parti-
cles by a pulsating fluid, usually water. Similarly, concentrating
tables cause a flow of pulverized coal and water slurry over an
inclined riffled deck which shakes rapidly, effecting a separation of
the particles by size and specific gravity (McCandless 1978).
Dense media processes involve the separation of raw coal and its
impurities through its immersion into a fluid having a density inter-
mediate between clean coal and reject materials. By regulating the
specific gravity of the separating fluid, ash-forming impurities can
be removed.
Froth flotation is of longstanding importance for cleaning
minerals but has only recently been used for cleaning coal particles
smaller than 0.5 mm. In this process (which does not rely on differ-
ences in specific gravities) the preconditioned raw coal feed is
mechanically agitated in a water slurry containing controlled amounts
of air and chemical reagents. Suitable reagents to establish a
hydrophobic (air-adhering) surface on the coal particles and to render
the other solids hydrophilic (waterloving) are used. Thus, the
air-adhering coal particles separated from nonadhering particles are
floated to the surface of the slurry and removed as a concentrate (Sun
1968; Gibbs and Hill 1978).
To reduce the sulfur content of coal, improved and innovative
physical separation technologies are being developed to effectively
separate fine coal from pyrite. Desulfurization can be accomplished
through physical processes such as gravity separation, flotation, and
magnetic separation techniques or through varying chemical techniques
that can remove much of the pyrite sulfur. During FY 1979, a Federal-
ly funded oil agglomeration process demonstration for separating fine
rock from powdered coal will be completed. If successful, the agglom-
eration process will be integrated with a wet high-gradient magnetic
separation (HGMS) process to obtain a clean coal product low in mois-
ture, ash, and pyrite. Tests of dry HGMS using prototype equipment
will be continued (U.S. Department of Energy 1979).
TRANSPORTATION
After removal from the coal seam, coal must be transported to a
processing facility (if required) and eventually to the consumer.
18
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Underground mining operations generally use gathering and haulage con-
veyors, rubber-tired shuttle cars, and mine rail cars to haul the coal
to the surface. In 1975, 1,427 underground bituminous coal mines used
5,187 conveyor belts (average length of 1,750 feet) to move about
255.56 million tons or about 87 percent of underground coal (Bureau of
Mines 1977). Surface mine haulage is by large trucks and belt convey-
ors.
Coal is usually shipped by rail or water to the ultimate con-
sumer. In 1975, about 75 percent of all bituminous coal and lignite
was transported in this fashion, with rail accounting for about 65
percent and water for 10 percent (Bureau of Mines 1977). Other trans-
portation methods include truck and slurry pipeline. Table A-2 in
Appendix A indicates the most common methods of shipment of coal in
the U.S. and the quantities shipped during 1975.
Coal slurry pipelines are being considered as an alternative to
coal shipment by railroad in many locations. These pipelines would
extend from the coal source to the user. The coal would be pulver-
ized, mixed with water, and then pumped through the pipelines. The
availability of the necessary water supply at the slurry's source is
of primary importance. Coal slurry transport requires approximately 1
ton of water to transport 1 ton of coal. Approximately 1.3 acre-feet
of water are required to transport 1,400 tons of coal. Existing and
planned coal slurry pipelines are shown in Figure 3 (U.S. Environ-
mental Protection Agency 1978a; Wasp 1979).
END USE
This section will be limited to the use of coal in the production
of electrical power. Table A-3 in Appendix A is a comparison fuels
used for electric power generation. In 1975, electrical utilities
accounted for 73 percent of bituminous coal consumption. Industrial
uses, including coke production, accounted for another 26 percent.
Household and commercial uses accounted for about 44 percent of
anthracite production. The remainder was about equally divided
between electric utility power generation and industrial uses (Bureau
of Mines, 1977).
Conventional coal-fired boilers burn coal to create heat energy,
which is transferred to a fluid, normally water, to produce steam heat
which is then converted to mechanical energy by a turbine and finally
to electrical energy by a generator. A common type of steam power
plant accounts for approximately 78 percent of the U.S. generating
capacity. These systems transfer heat from conventional fossil fuels
19
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fo
O
Two coal slurry pipelines have been built (Ohio and Black Mesa) and six are currently proposed.
SOURCE: Wasp 1979.
ENERGY
TRANSPORTATION
SYSTEMS INC.
WYTEX
PIPELINE
Existing
In Progress
Planned
FIGURE 3
COAL SLURRY PIPELINES
-------
such as coal or oil to water to produce high-pressure, high-
temperature steam which drives a turbine. The steam is then con-
densed to water and recycled. To maximize efficiency, various types
of boiler and turbine equipment and techniques are utilized. With
coal-or high-sulfur-oil-fueled systems, additional stack gas cleaning
devices may be required.
Gas turbine plants often are used to accomodate peak loads
because of their fast start-up ability, low initial cost, and short
delivery time. They now represent approximately 8 percent of the
installed electrical generating capacity in the United States. In
this type of system, the gaseous or vaporized fuel is injected into a
combustion chamber together with compressed incoming air, the result-
ing high-pressure, high-temperature exhaust is used to drive the tur-
bine which in turn drives both the generator and the compressor. This
is similar to the type of engine which is used on jet aircraft. The
gas turbine, however, requires a clean gas stream, necessitating a
clean-burning fuel or a source of high-temperature thermal energy such
as a nuclear reactor.
The combined-cycle power plant is a combination of the conven-
tional and peaking systems. In this type, the hot exhaust of the gas
turbine is used to generate steam in an unfired boiler. The steam
then drives a conventional steam turbine. As an example, a 100 MWe
plant contains four gas turbines with their associated generators as
well as a steam turbine with its generator. These plants are present-
ly being used to serve intermediate system loads.
Three major factors determine the amount and character of the air
pollutants generated by a boiler: the type of fuel burned, boiler de-
sign, and boiler operating conditions. Sulfur oxide (S0X) emissions
are directly relatable to the sulfur content of the fuel (relatively
high in Eastern coals). There is little in the way of conventional
boiler design or operation that can affect this residual. Sulfur
oxides must be dealt with before burning (e.g., physical/chemical coal
cleaning), during burning (e.g., fluidized-bed combustion) or after
burning (e.g., stack gas cleaning). One of the more common methods of
removing sulfur oxides from the combustion flue gas (flue-gas desul-
furization or FGD) is by forcing the S0X in the flue gas to react
with a limestone slurry. Particulate matter may be removed from the
exhaust emissions by means of electric precipitators. Thus, the
tradeoff to decrease air pollution emissions might be through an
increase in wastewater contamination and solid wastes.
21
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SECTION II - POLLUTANTS AND DISTURBANCES
INTRODUCTION
All phases of the coal cycle—from extraction, through pro-
cessing, conversion, and power generation, to final disposition of
residual wastes—produce environmental impacts that could limit our
ability to utilize domestic coal resources. These environmental
problems can be controlled—but at a cost. Table 2 indicates some of
the environmental problems associated with major phases of the ex-
traction, processing and utilization of coal. A more complete over-
view of the pollutants released in various phases of conventional
coal technology is presented in Appendix A, Table A-4. Specific
elements and compounds released from coal-fired power plants with
respect to those released from other technologies are listed in
Appendix A, Tables A-5 and A-6.
The organic coal components contain mainly, carbon (C), hydrogen
(H), nitrogen (N), oxygen (0), and sulfur (S): however, there is
considerable variation in these elements in coals. Lower rank coals,
such as lignite, are typified by a lower percentage of C and H and a
relatively higher percentage of N, 0, and S, whereas the converse is
true for the higher rank coals. The organic matter in coals is pre-
dominately in the form of aromatic and hydroaromatic hydrocarbons.
The 0, S, and N atoms form various functional groups that are dis-
persed throughout the carbon skeleton. The prevalent functional
groups in coals are phenols, acids, ethers, and groups containing
sulfur and nitrogen. Thus, it is relatively easy to envision the
types or organic molecules that are released by coals during com-
bustion, oxidation, or weathering. Because of their preponderance,
valrious aromatic and aliphatic hydrocarbons are common contaminants.
Also, because heteroatom linkages are often susceptible to cleavage,
molecules containing N, 0, and S atoms are prevalent coal contami-
nants. Typical examples of the types of organic molecules in the
emissions or discharges from coals are pictured in Figure 4 (Wewerka
et al. 1976).
Most of the inorganic coal components were deposited either as
sediments in the original bed or as secondary materials during the
formation of the coal; however, some of the trace or minor elements
in coals were probably present originally in the plants. The most
abundant inorganic elements in coals (excluding S, N, and 0) are
listed in Table 3. These are the elements that, for the most part
form the major minerals found in coals. These minerals fall into the
four main classes listed in Table 4. They are the aluminosilicates
(Na, K, Al, Si), the sulfides (Fe), the carbonates (Ca, Mg, Fe), and
silica (Si). Generally, the aluminosilicates (clay minerals) and
22
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TABLE 2
MAJOR POLLUTANTS AND DISTURBANCES AND CONTROL TECHNOLOGIES
ASSOCIATED WITH THE CONVENTIONAL COAL ENERGY CYCLE
Extraction
Processing / Conversion
Coal
Underground Mining
Acid Drainage
Solid Waste
Surface Mining
Runoff Solids
Acid Drainage
Sediments
Air Particles
Solid Waste
-*• Contain /Neutralize
-*¦ Well-Mnnaged Landfill
Control/Treatment of Runoff
Well-Managed Mine
Restoration and Revegetation
Physical Coal Cleaning
Air Particles
High-sultur Solid Waste -
Runoff Solids
Acid Drainage
Dust Control
Recover Sulfur
Contain
Contain / Neutralize
Gasification/Liquefaction (?)
Runoff Solids
Organic Wastes
—Toxins
—Carcinogens
Solid Waste
Waste Heat
Fugitive/Accidental -
Release of Toxins.
Carcinogens
Phys.-Chem. Treatment
Phys.-Chem. /Biochem
Treatment
Landfill
Cooling/Reuse
Design to Eliminate
Generation
Power Plants (Conventional)
Sulfur Oxides
Nitrogen Oxides —
Flyash and Smoke -
Particles
Solid Waste (Ash) -
Industry
Sulfur Oxides
Nitrogen Oxides —
Flyash and Smoke
Particles
Solid Waste (Ash)
Scrubbers. FluidizedBed,
Clean/Cleaned Coal (?)
Scrubbers, Combustion Modifi-
cation, Flue Gas Treatment
Cyclones. Baghouses. Elec
trostatic Precipitators,
Scrubbers
-~ Well-Managed Landfill
Fluidized Bed, Clean/Cleaned
Coalt?), Scrubbers
Combustion Modification
Electrostatic Precipitators.
Baghouses, Cyclones.
Scrubbers
-+¦ Landfill
Commercial / Residential
Sulfur Oxides -—
Nitrogen Oxides —
Flyash and Air —
Particles
Solid Waste (Ash)
Low-Sulfur Fuel
Combustion Modification
Electrostatic Precipitators
Landfill
(?) = Technologies not yet available
SOURCE: U.S. Environmental Protection Agency 1978a.
-------
A
PHENOLS
A—A
OXYGEN
NITROGEN
HETEROCYCLICS
HETEROCYCLICS
SOLRCE: Wewerka et al. 1976
AROMATIC
HYDROCARBONS
POLYCYCLIC
HYDROCARBONS
CH'
ALICYCLIC
HYDROCARBONS
FIGURE4
POTENTIAL ORGANIC CONTAMINANTS FROM COALS
-------
TABLE 3
MAJOR INORGANIC ELEMENTS IN COALS
ELEMENT
RANGE (WT%)
SILICON
0.6 - 6.1
IRON
0.3 - 4.3
ALUMINUM
0.4 • 3.1
CALCIUM
0.1 - 2.7
POTASSIUM
0.1 - 0.4
MAGNESIUM
0.1 - 0.3
TITANIUM
0.0 - 0.3
SODIUM
0 - 0.2
SOURCE: Wewerka et al. 1976.
25
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TABLE 4
MAJOR MINERALS IN COALS
ALUMINOSILICATES
SULFIDES (0-40%)
(10-90 WT%)
PYRITE
MARCASITE
ILLITE
KAOLINITE
MIXED LAYER CLAYS
SILICA (0-20 WT%)
CARBONATES (0-10 WT%)
QUARTZ
CALCITE
DOLOMITE
SIDERITE
: Wewerka et al. 1976.
26
-------
quartz tend to be chemically stable. Neither is volatile or likely
to be leached from the coal. During combustion these minerals will
form ash and will fragment during burning to form small particles
(flyash) that mix with the stack gases. The carbonates also form ash
during combustion. In addition, they are partially water soluble
and may be leached out of coals or wastes (Wewerka et al. 1976).
Among all of the coal constituents, environmental contamination
caused by pyritic materials is the most severe. At ordinary tempera-
tures the sulfides are not particularly soluble or volatile per se,
but when pyrite (or marcasite) is exposed to atmospheric conditions,
it can interact with air and water at ambient temperature to produce
soluble iron sulfate and sulfuric acid. This reaction of the iron
sulfides in coals is, in fact, responsible for the formation of acid
mine drainage, a most serious water pollution problem. Also, at
combustion temperatures, the sulfur in the iron sulfides (along with
added amounts of organic sulfur) is oxidized to sulfur dioxide
(SO2), the most prevalent air contaminant associated with the
burning of coal. The chemical reactions for the formation of sul-
furic acid and sulfur dioxides from iron sulfides appear in Table 5
(Wewerka et al. 1976).
In addition to these major inorganic elements, coals also con-
tain a wide variety of trace or minor elements. A listing of some of
the trace elements of environmental concern in coals is given in
Table 6. The soluble forms of these elements may be released into
the environment by aqueous leaching of coals or their residues.
Also, some of the toxic trace elements assume volatile forms during
coal burning and can escape into the atmosphere along with the more
inert gaseous products.
In summary, most of the major environmental pollutants from
coals originate as impurities in the coal structure. These include
various organic compounds, minerals, and trace elements that may be
released into the air and water when coal is mined, processed, and
utilized. These substances can enter the environment either as gas-
eous or waterborne pollutants (Tables 7 and 8). Pollutants typically
associated with each phase of the coal energy cycle are shown in sum-
mary Tables 9, 10, 11, and 12 and Figure 5.
EXTRACTION
Solid Wastes
Mine wastes consist of undesirable materials, either as part of
the coalbed or added to the coal, during extraction. Other wastes,
27
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TABLE 5
IRON SULFIDES CAUSE MAJOR ENVIRONMENTAL PROBLEMS
SULFUR OXIDE EMISSIONS
4 FeS2 + 11 02 —>2 Fe203 + 8 S02 + A
ACID MINE DRAINAGE
2 FeS„ + 2 H„0 + 7 0„ -+ 2 FeSO. + 2 H„S0, + /\
ILL 4 2 4 *
/\ = Heat
SOURCE: Wewerka et al. 1976.
28
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TABLE 6
TRACE ELEMENTS OF ENVIRONMENTAL CONCERN IN COAL
K5
\£3
ELEMENT
RANGE
(ppm)
Arsenic
0.5 -
106
Beryllium
0 -
31
Cadmuim
0.1 -
65
Copper
2 -
185
Lead
4 -
218
Manganese
0 -
31
Mercury
.01 -
1.6
Nickel
0.4 -
8
Selenium
0.4 -
8
Yttrium
0.1 -
59
Zinc
0 -
6000
SOURCE: Wewerka et al. 1976,
-------
TABLE 7
SUMMARY OF POTENTIAL AIR CONTAMINANTS IN COALS
ATMOSPHERIC TRANSPORT MODE
• VOLATILE HYDROCARBONS
• PARTICULATES AND DUST
• VOLATILE TRACE ELEMENTS
• OXIDES OF SULFUR, NITROGEN AND CARBON
SOURCE: Wewerka et al. 1976.
30
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TABLE 8
SUMMARY OF POTENTIAL WATER CONTAMINANTS IN COALS
AQUATIC TRANSPORT MODE
• SOLUBLE ORGANIC MOLECULES
• POLYAROMATIC HYDROCARBONS
• LEACHABLE MINERALS AND TRACE ELEMENTS
• ACID DRAINAGE
SOURCE: Wewerka et al. 1976.
31
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TABLE 9
ENVIRONMENTAL CONTAMINATION FROM COAL MINING
MINING
\
/
\
/
ATMOSPHERIC
POLLUTION
AQUATIC/
TERRESTRIAL
POLLUTION
• HYDROCARBON
• SPOIL leaching/
GASES
BURNING
• Dust
• ACID DRAINAGE
SOURCE: Wewerka et al. 1976
32
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TABLE 10
ENVIRONMENTAL CONTAMINATION FROM COAL PREPARATION
SOURCE: Wewerka et al. 1976.
33
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TABLE 11
ENVIRONMENTAL CONTAMINATION FROM COAL STORAGE
AND TRANSPORT
SOURCE: Wewerka et al. 1976.
34
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TABLE 12
ENVIRONMENTAL CONTAMINATION FROM COAL COMBUSTION
SOURCE: Wewerka et al. 1976.
35
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ATMOSPHERIC
POLLUTION
COAL
PROCESS
STEP
AQUATIC/
TERRESTRIAL
POLLUTION
HYDROCARBON GASES
DUST
HYDROCARBON GASES
DUST
MINING
SULFUR., NITROGEN., AND
CARBON OXIDES
PARTICULATES
TRACE ELEMENTS
STORAGE/
TRANSPORTATION
PREPARATION
SPOIL LEACHING/
BURNING
ACID DRAINAGE
LEACHATES
PRECIPITATES FROM
BURNING REFUSE PILES
DUST
slag/fly ASH
LEACHING
REFUSE LEACHING/
BURNING
ACID DRAINAGE
SLURRY/PROCESS WATER
SOURCE: Wewerka et al. 1976.
FIGURES
BALANCE OF ENVIRONMENTAL CONTAMINATION
FOR COAL PROCESSING AND UTILIZATION
-------
usually low in volume and not directly related to the removal of
coal, include removed vegetation, damaged or used reagent or product
containers, domestic sewage sludges, and residuals from pollution
control equipment. Waste rock produced underground usually is mixed
with the run-of-mine product and removed during the coal preparation
process (Palowitch 1979). Unconsolidated materials such as sand,
earth, silt, and bedrock from the overburden at most surface mining
operations is used as mine backfill. Mining wastes (related terms
are tailings, fines, gob materials, slimes) are usually disposed of
on the surface in landfills and impoundments. Mine wastes are some-
times used in on-site road and dam construction (PEDCo Environmental,
Inc. 1978).
Mine refuse materials vary in size from large rocks to fine
materials existing as slimes. The mineralogical composition of these
materials generally corresponds to that of the host rock from which
the ore was derived. Normally, these materials contain various
mixtures of quartz, feldspars, carbonates, oxides, ferromagnesian
minerals, and minor amounts of other minerals. They also contain
traces of residues from detonation, dust control agents, and other
reagents.
Ground water can be impacted by leachate from tailings ponds and
mine waste piles, which may contain a variety of undesirable consti-
tuents such as aromatic hydrocarbons and heavy metals. The signifi-
cance of .the impact of the leachate on groundwater quality depends on
such factors as the climate, the nature of the soil or rock strata,
and the depth of the water table. Arid regions of the West should be
less severely affected because water either evaporates or is recy-
cled. Vegetation may be affected by polluted groundwater. Plant
uptake of metals depends upon the chemical form of metals, soil condi-
tions, and plant species; and the same considerations apply when
analyzing the revegetative potential for the mine wastes themselves
(PEDCo Environmental, Inc. 1978).
Surface water is the environmental medium most significantly
impacted by indirect pollution from mining and coal cleaning solid
waste. Drainage from waste heaps in the Eastern U.S. may contain
acid-forming materials that raise the acid level beyond the buffering
capacity of streams and may have a pH so low as to be considered
corrosive. It is also possible for this drainage to contain heavy
metals. Proper design of impoundments and spoil banks is critical.
Failure of refuse banks has resulted in great loss of life and
destruction of property. For example, the failure of a coal waste
heap in Aberfan, Wales, in 1966 killed 144 persons, and failure of a
coal waste dam in Buffalo Creek, West Virginia, in 1972 resulted in
the death of 125 persons and the destruction of hundreds of homes
(PEDCo Environmental, Inc. 1978).
37
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Solid wastes can produce fugitive dust and other atmospheric
emissions. Although these emissions have components that are consi-
dered hazardous, concentrations are usually too small to pose a sig-
nificant threat to human health or to the environment. For instance,
waste banks at coal mines, when accidentally ignited, emit particu-
lates, sulfur oxides, nitrogen oxides, and hydrocarbons, including
benzo(a)pyrene. Isolation of most large mining operations effective-
ly limits the impact of air emissions on human health; however,
natural biota may be affected especially when mine-mouth power plants
are present (U.S. Environmental Protection Agency 1976a; PEDCo
Environmental, Inc. 1978).
Some waste materials from coal cleaning operations may contain
potentially hazardous substances in higher concentrations than the
land on which they are disposed. The fine-grained texture of tail-
ings also makes them susceptible to wind and water erosion. If
properly handled and disposed of, however, these fine-grained wastes
can be contained and stabilized. Stabilization and control technol-
ogies encompass a variety of proven methods for providing structural
stability for tailing dams and overburden/waste rock piles; for pre-
venting both surface and groundwater pollution from tailings ponds
and overburden/waste rock piles; and for ultimately creating a
reclaimed area that is satisfactory functionally and aesthetically
(PEDCo Environmental, Inc. 1978).
At most active mining operations, disposal areas, as well as
disturbed areas, will eventually be rehabilitated or reclaimed in
some manner. The Federal Surface Mining Control and Reclamation Act
of 1977 (P.L. 95-87) requires full reclamation in all active strip
mines and provides for a tax on coal to finance a fund to reclaim
unreclaimed abandoned strip pits. In a few states the amount of land
being reclaimed by mine operators annually actually exceeds the
amount disturbed because lands devastated by mining activities before
passage of surface mining and reclamation legislation are being re-
claimed. Despite these positive aspects, however, mining solid
wastes still poses a threat to the environment for the following
reasons: (1) little was done before the late sixties to control and
rehabilitate waste disposal areas, thus large amounts of unstabilized
wastes had already accumulated; (2) there is often no one to assume
responsibility for the large quantities of waste materials at the
numerous inactive mining sites; (3) although they will eventually be
stabilized and reclaimed, wastes generated at active mines pose a
threat to the environment until such action is taken.
Erosion
Erosion of overburden piles, wastebanks, and cleared mining
land causes large amounts of sediment to enter surface waters. More
38
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erosion occurs on active and abandoned surface mines in the U.S. than
from any other source (Table 13). In 1965, coal mining accounted for
41 percent of the total area disturbed by surface mining. Erosion
related to coal mining is expected to be controlled substantially
through implementation of P.L. 95-87.
Surface mining poses a danger of erosion and acid drainage in
areas with rugged terrain and rainy climate in the East such as
southern Appalachia. In the West preventing erosion and restoring
land, particularly alluvial valleys which often form the backbone of
the ranching and farming economy of this region, is a great concern.
Experience in revegetating arid and semiarid areas is not extensive
(U.S. Department of Health, Education and Welfare 1979). The Sur-
face Mining and Control Act of 1977 strictly regulates mining on
alluvial valley floors, but enforcement is critical. Appalachian and
interior coal fields, in general, have thinner seams and are located
on steeper than average slopes than are Western fields. These fac-
tors result in greater surface disturbance per ton of surface-mined
Eastern coal. Western areas, with thicker seams and gentler slopes,
show less surface disturbance per ton of coal mined (U.S. Environ-
mental Protection Agency 1978a; U.S. Energy Research and Development
Administration 1977; Table 14).
Surface mining of coal in the Northern Great Plains is by either
the area- or open-pit method. Vegetation is removed and disposed of,
topsoil is removed and stockpiled, and the remaining overburden—soil
and rock—which covers the coal is overturned and exposed. Surface
topography and drainage patterns and soil conditions are altered dur-
ing the mining process.
The semiarid climate—less than 15 inches of annual precipita-
tion—lessens the problems of erosion, but increases the problem of
revegetation. However, high winds may cause sheet erosion and
infrequent, but violent storms will contribute to sheet erosion,
gullying, and stream channel erosion, the product of which is sedi-
ment (Northern Great Plains Resources Program 1974).
Subsidence*
Subsidence, a potential problem in underground mining, occurs
when the support of the mine roof either shifts or collapses.
Although subsidence can occur during active operation of a mine, it
is more likely to be delayed for many years as the mine pillars
slowly erode and collapse. Damage to the land surface includes
*Source: Northern Great Plains Resource Program 1974.
39
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TABLE 13
REPRESENTATIVE RATES OF EROSION FROM
VARIOUS LAND USES
Land use
Metric tons
per km^
per year
Tons per
mi2 per
year
Relative to
forest = 1
Forest
8.5
24
1
Grassland
85.0
240
10
Abandoned surface mines
850.0
2,400
100
Cropland
1,700.0
4,800
200
Harvested forest
4,250.0
12,000
500
Active surface mines
17,000.0
48,000
2,000
Construction
17,000.0
48,000
2 ,000
SOURCE: U.S. Environmental Protection Agency 1976c.
40
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TABLE 14
LAND DISTURBED PER MILLION TONS OF SURFACE COAL MINED1
COAL FIELDS
APPALACHIA
INTERIOR
TEXAS GULF
POWDER
RIVER
FORT
UNION
GREEN
RIVER
FOUR
CORNERS
Average Seam
Thickness (ft)
6.0
5.5
8.0
26.0
10.0
8.0
8.0
Acres per
million tons
mined
95
104
71
22
57
71
71
Numbers based on 1750 tons per acre-ft.
SOURCE: U.S. Energy Research and Development Administration 1977.
-------
fissures, sinkholes, cave-ins, and an irregular lowering of the land.
Horizontal displacement, combined with vertical subsidence, will
damage surface structures, alter surface and ground water drainage
patterns, and allow water and air access to the underground workings
and, therefore, may promote air (H2S, CH4, combustion gases) and
water pollution, which can affect plant and animal life. Subsidence
can also make plowing and traversing of the surface impossible, and
can depress land values by eliminating the land from future
development.
The extent, severity, and timing of the subsidence are complex
functions of factors such as rail composition, overburden thickness,
and mining method. Although reliable surveys of subsidence do not
exist, a sizeable percent of the 8 million acres where underground
mining has taken place has had some degree of subsidence, and more
may subside in the future. Preventing subsidence will depend on the
success of preplanning and control measures, and the degree to which
underground mining is used. A Bureau of Mines report estimates that
a potential 1.5 million acres would be affected by 2000 (U.S.
Department of Health, Education, and Welfare 1978).
Subsidence problems can be addressed by both preventive and
corrective measures. The common preventive measure is to leave a
considerable portion of the coal itself, sometimes as much as half
in place as a roof support. Pillars left for support may deteriorate
over time and eventually fail, whether in one or one hundred years
after the workings are abandoned. The highly unpredictable nature of
subsidence following partial extraction of coal is an essential con-
sideration in mine planning.
Total extraction, whether by longwall or by the pulling of pil-
lars, encourages subsidence to occur but in a controlled manner.
Each section of the mine roof collapses after all the coal is extrac-
ted. The subsidence thus not only occurs sooner, but more evenly
with major disruptions at the perimeter of the mined area. Con-
trolled subsidence through total extraction of the coal is practiced
in other countries, but time and experience will be required before
such methods can be properly utilized in the United States. More-
over, methods of total extraction are not universally applicable, but
must depend upon favorable conditions at specific sites.
Another method of reducing the impact of subsidence is the back-
filling, or stowing, of mine waste or other materials (including
flue-gas desulfurization sludge) in mined-out areas underground.
This would seem to solve waste disposal and subsidence at the same
time. However, studies show that this method is quite expensive, is
42
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a considerable hazard to workers, and may release contaminants into
ground water. In addition, some mine wastes and untreated sludge
lack the structural strength to support the mine roof.
Water Effluents
Alkaline drainage is most frequently found in Midwestern and
Western coal fields and is generally characterized by relatively high
levels of dissolved and suspended solids. The alkalinity is similar
to that of natural overburden materials. Most metals are insoluble
under alkaline conditions, except for selenium, which, therefore, may
present a problem. For Western coals, alkaline drainage and suspen-
ded solids appear to be the major water quality pollutants. However,
the most serious water-related mining problem associated with the
development of Western coal fields appears to be the disruption of
aquifers resulting in lowered water tables and well levels (U.S.
Environmental Protection Agency 1976b).
Generally, water quality analyses have indicated no significant
differences between untreated wastewater from surface and underground
mining operations in similar geologic settings. Several parameters,
namely, total and dissolved iron and total suspended solids, vary
within the classes of mine drainage; however, this is believed to be
the result of precipitation patterns (i.e. heavy rainfall on surface
mines) (U\S. Environmental Protection Agency 1976b).
The most serious water-related mining problem associated with
development of Eastern coal fields appears to be that of acid drain-
age. The industry has already developed technology for point source
discharges: neutralization of acidity with concurrent reduction of
other pollutants to safe concentrations. This is usually achieved
with lime neutralization followed by aeration and sedimentation.
Other reagents experimented with by the coal industry for treatment
include limestone, caustic soda, soda ash, and anhydrous ammonia.
Anhydrous ammonia can result in eutrophication of receiving waters if
used for prolonged time periods or relatively high mine drainage vol-
umes. However, such treatment plants can successfully control acid-
ity, iron, manganese, aluminum, nickel, zinc, and total suspended
solids (U.S. Environmental Protection Agency 1976b).
The extensive as well as the potential impact of uncontrolled
acid mine drainage associated with both underground and surface min-
ing and the attendant problems of erosion, sedimentation, and subsi-
dence have been studied in detail. An appraisal by the Appalachian
Regional Commission drew the conclusion that" . . . about 10,500
miles of streams in eight states of the Appalachian Region are
43
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affected by mine drainage . . . (and) of the total stream mileage
affected, acid drainage continually pollutes nearly 5,700 miles,"
The Commission estimated that acid mine drainage is responsible for
$3.5 million in added costs to users of water. The problem is
resistant to solution, and there is likely to be a continuing need to
control drainage at the mining site, to treat effluents, and to pro-
tect water sources of potentially high acidity (National Academy of
Sciences 1975).
Acid mine drainage is characterized by low pH and high concen-
trations of mineral acidity, sulfate, calcium, iron, and manganese
and lesser amounts of other metallic compounds such as magnesium,
aluminum, nickel and zinc (Table 15). It occurs at both surface and
underground mines, but the large majority of the acid mine drainage
in Appalachia comes from underground mines. Abandoned and inactive
underground mines in Northern Appalachia are the largest contributors
to stream degradation, and account for 88 percent of the acid drain-
age in Northern Appalachia. Due to the prevalence of high sulfur
coal (which has a high pyrite content) in northern Appalachia, acid
mine drainage is particularly severe and widespread.
The majority of acid drainage produced from surface mines and
refuse piles at underground mines and preparation plants occurs dur-
ing wet seasons when surface run-off is high; therefore, acid dis-
charges tend to be quite variable. The water in underground mines
comes from seepage of surface water into mines and from groundwater
aquifers. Acid discharges from underground mines tend to be steadier
and more concentrated than acid drainage from surface mines. This is
generally due to the longer time water remains in underground mines,
thus permitting more leaching prior to its discharge to surface
waters (U.S. Department of Energy 1978b).
Air Emissions
Dust presents a major environmental problem during surface coal
mining and reclamation in Western coal fields, particularly where
high winds and low rainfall are present. The impact of this emission
on society is reduced by the fact that most Western mine developments
are in sparsely populated regions. Dust problems also occur in
Eastern and Midwestern coal surface mines where dust occasionally
blows from roads, strip pits, trucks and railroad cars.
Underground coal mining, because of the confined working area,
does not pose a problem to ambient air quality in itself, except
around surface facilities and dump areas. Careful design and mainte-
nance of these facilities can prevent such airborne dust from becom-
ing a major pollutant.
44
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TABLE 15
TYPICAL ACID MINE DRAINAGE
PARAMETER
MINE #1
MINE #2
PARAMETER
MINE #1
pH
5.0
2.8
As
0.01
Acidity, CaCO^
640
470
B
0.5
Alkalinity, CaCO^
17
0
Cd
<0.001
Ca, CaCOg
370
210
Cr
0.05
Mg, CaCO^
110
93
Hg
0.0003
Fe, Total
300
93
Cu
0.02
Fe, Ferrous
270
0
Ni
0.20
Na
480
2
Se
<0.001
A1
15
31
Zn
0.25
Mn
6
4
p°4
8.6
so4
3040
610
T.D.S.
4320
1050
Conductivity
3760
1190
All units mg/1 except pH and conductivity (micromhos/cm)
SOURCE: Hill and Bates 1977.
45
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The abatement of fugitive dust pollution associated with surface
mining requires proper planning. Haul and service roads must be
surfaced with asphalt, oiled, or kept damp with water. Oiling of
roads may not be the best dust suppression method since many areas
come in close contact with surface and ground water. Mined areas
need timely reclamation and seeding to prevent wind erosion of spoil
piles. Planning is essential in designating areas of potential dust
pollution and utilizing the best methods possible to keep airborne
dust at an acceptable level.
Fires from coal refuse banks and mines release smoke, airborne
particles, and noxious, sometimes lethal gases. There are 250 x
106 metric tons of burning refuse bank material. The amounts of
refuse material in burning impoundments and of coal burning in aban-
doned mines and outcrops are unknown. However, a Bureau of Mines
survey shows that there are 271 burning refuse piles and impoundments
and 441 burning abandoned mines and outcrops. Burning of coal piles,
impoundments, abandoned mines, and outcrops results in emissions of
various pyrolytic and combustion products such as particulate matter,
nitrogen oxides, sulfur oxides, carbon monoxide, hydrogen sulfide,
ammonia, polycyclic organic materials (POM), and hydrocarbons
including benzene, toluene, and xylene. Trace elements such as
arsenic, boron and mercury are also emitted (U.S. Environmental
Protection Agency 1978b).
The spontaneous heating of coal and coal refuse piles is mainly
an oxidation phenomenon involving coal, associated pyrite, and impure
coal substances. It is also influenced by the presence of moisture.
The oxidation of carbonaceous and pyritic material in the coal refuse
is an exothermic reaction in which the temperature of a pile or por-
tions of it will increase if the amount of circulating air is suffi-
cient to cause oxidation but insufficient to allow for dissipation of
heat. The temperature of the refuse then increases until ignition
temperature is reached.
Experimental evidence has shown that the heat from the wetting
of coal is more than the heat from the oxidation of coal. Thus, the
presence of moisture in the air accelerates the self-heating process
in coal refuse piles. Oxidation of pyritic impurities in coal refuse
piles is another exothermic factor which enhances coal combustion.
Oxidation of pyrite is a highly exothermic reaction that increases
the temperature of the coal and thus increases its rate of oxidation
(U.S. Environmental Protection Agency 1978c).
Emissions from fires in coal refuse piles, abandoned minea, and
outcrops contribute 0.001 percent of the particulates, 0.16 percent
of the nitrogen oxides, 0.14 percent of the sulfur oxides, 0.14 per-
cent of the hydrocarbons, and 4.9 percent of the carbon monoxide
emitted nationally. Examples of emission factors for these criteria
46
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pollutants as well as for ammonia, hydrogen sulfide, mercury, and
polycyclic organic materials are presented in Table 16. Examples of
polycyclic organic materials emitted from coal refuse fires and their
degree of carcinogenicity are given in Table 17.
The general techniques for prevention of mine or refuse pile
fires are to reduce air circulation to combustible materials, mini-
mize the concentration of combustible material, and promote cooling.
It may not always be possible to apply these techniques for abandoned
mines. If it is feasible, the best techniques are to remove combus-
tible materials and seal holes. The Surface Mining Control and
Reclamation Act of 1977 (P.L. 95-87) requires that combustible mater-
ials exposed, used, or produced in underground mining (including
exposed coal seams) be treated, if necessary, and covered. The Act
also requires that all openings be capped, sealed, or backfilled when
no longer needed for mining. Development of controls to prevent
these fires which are a source of air pollution, has not received the
attention in the past given to air emissions from combustion. En-
forcement of these provisions presumably will decrease the incidence
of fires in new mines.
In the case of underground mining, blasting, coal, cutting and
loading can release methane, dust, noxious fumes and other air
pollutants. Exhausts from internal combustion engines, especially
diesel engines, in power vehicles and equipment emit pollutants \foich
pose a threat to human health. Although most equipment in under-
ground mines is electrically powered, one or more pieces of diesel
equipment are found in about 50 mines. Most of the diesel equipment
is used in the West, and a small amount in the East. Of the mines
where diesel equipment is found, about one-third have worker repre-
sentation, either by the United Mine Workers Union or independent
unions (Wheeler 1979).
In a properly ventilated mine, carbon monoxide is probably not
an important toxic factor. Oxides of nitrogen, although representing
a relatively large percentage of the toxic constituents of diesel ex-
haust (where present) are not considered a major toxic problem since
airflow in a properly ventilated mine would tend to remove nitric
oxide, the major oxide of nitrogen, long before it is oxidized to
nitrogen dioxide, a much more toxic nitrogen compound. Sulfur diox-
ide emissions are controlled due to stringent regulations of the
sulfur content of diesel fuel (Environmental Health Associates, Inc.
1978).
Polycyclic aromatic hydrocarbon (PAH) compounds, however, have
been identified as the most potentially hazardous agents found in
diesel engine exhaust. Although a properly maintained diesel engine
would be likely to emit small quantities of these compounds, the
47
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TABLE 16
EMISSION FACTORS FOR COAL REFUSE FIRE EMISSIONS
EMISSION FACTORS
POLLUTANT
kg/hr Per
kg/hr Per
of Burning
Metric Ton of
Coal Refuse
Burning Coal Refuse
Criteria Pollutants
Total Particulates
5.1 x 10~7
3.4 x 10~7
Respirable Particulates
1.3 x 10~8
8.7 x 10~9
Nitrogen Oxides
1.0 x 10~4
6.7 x 10 ^
Sulfur Dioxide
1.1 x 10"4
7.4 x 10"5
Sulfur Trioxide
2.7 x 10~7
1.8 x 10 7
Hydrocarbons
1.0 x 10~4
6.7 x 10
Carbon Monoxide
1.3 x 10~2
8.7 x 10~3
Noncriteria Pollutants
Ammonia
6.5 x 10"5
4.3 x 10~5
Hydrogen Sulfide
4.5 x 10""4
3.0 x 10 4
Mercury
6.8 x 10"9
4.6 x 10~9
Polycyclic Organic
-8
— ft
Materials
1.9 x 10
1.3 x 10
SOURCE: U.S. Environmental Protection Agency 1978c.
48
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TABLE 17
POLYCYCLIC ORGANIC MATERIALS EMITTED FROM COAL
REFUSE FIRES, AND THEIR CARCINOGENICITY
POLYCYCLIC ORGANIC MATERIAL
(POM)
CARCINOGENICITY
Dibenzothiophene
i
Unknown
Anthracene/phenanthrene
not carcinogenic
Methylanthracenes/phenanthrenes
Unknown
9-Methylanthracene
Unknown
Fluoranthene
Not carcinogenic
Pyrene
Not carcinogenic
Benzo (c) phenanthrene
Strongly carcinogenic
Chrysene/benz (a) anthracene
Carcinogenic
Dimejrhylbenzanthracenes (isomers)
Strongly carcinogenic
Benzo (k or b) fluoranthene
Not carcinogenic
Benzo (a) pyrene/benzo (e)
pyrene/perylene
Strongly carcinogenic
3-Methylcholanthrene
Unknown
Dibenz (a,h or a,c) anthracene
Strongly carcinogenic
Indeno (1,2,3-c,d) Pyrene
Unknown
7H-Dibenzo (c,g) carbazole
Strongly carcinogenic
Dibenzo (a,h or a,i) pyrene
Strongly carcinogenic
SOURCE: U.S. Environmental Protection Agency 1978c.
49
-------
possibility that they may be carcinogenic to mine workers singles
them out for careful attention. Such hydrocarbons within diesel
engine exhaust gases that have been measured include benzo(a)pyrene
at one to 422 parts per billion, from one to 533 parts per billion
for benzo(e)pyrene, and one to 466 parts per billion for benzo(a)-
anthracene. Other hydrocarbons observed in diesel engine exhausts
include chrysene, pyrene, anthracene, phenanthrene and its deriva-
tives, fluoranthene, and phenols (Environmental Health Associates,
Inc. 1978).
Aldehydes also are present in diesel exhaust emissions as a
result of unburned hydrocarbons. The acute toxicity of aldehydes is
related to their capacity to cause eye and respiratory tract irrita-
tions. Two specific aldehydes, formaldehyde and acrolein, are of
particular importance because of their biologic effects and their
presence in higher concentrations in diesel exhaust than other alde-
hydes (Environmental Health Associates, Inc. 1978).
Coal dust emissions in underground mines have long been recog-
nized as the most important physical hazard to the health of coal
miners. Activity associated with the use of modern extraction
machinery and rate of extraction is suspected to have increased the
levels of particles in the air of underground mines over those pre-
sent in the days when the pick and shovel were the principal method
of extraction.
Exposure to coal dust can result in a variety of lung-elated
diseases such as emphysema, pulmonary fibrosis, lung collapse, hole
in the lung, pulmonary edema, and cystic lungs. Dust levels in
modern mines are monitored, the air is filtered, dust suppressents
are used, and respirators are made available.
Accidents
Accidents causing death, injury, or physical damage can occur at
any step in the coal fuel cycle. Quantitative estimates of injury
and death rates for the fuel cycle (excluding end use) are provided
in Appendix A, Tables A-7 and A-8 (data prior to 1976), and Table A-
9 (data for 1978). It is apparent that the majority of occupational
death and injuries occur in the underground mining and transportation
sectors. The death and injury rates associated with underground
mining are substantially greater than those associated with surface
mining.
The human health or safety hazards associated with accidents
during the exploration phases of the coal cycle are few. All hazards
are generic in nature, with no specific coal exploration activity
having an unusual accident type or frequency. Although a significant
50
-------
amount of coal seam mapping must occur prior to actual mining opera-
tions, using drilling and coring equipment or explosives, no signifi-
cant accidental health, safety, or ecological hazards are present.
Historical data indicate that coal mining is a dangerous occu-
pation. Table 18 compares the risks associated with underground coal
mining with other industrial activities. The threat to personal
health or safety from mining accidents depends upon the extraction
technique used, the location of the mine, the activity of the miner,
the location of the individual inside the mine (underground miners),
the experience of. the mining crew, the equipment used, the safety
precautions and procedures employed in the mine, and other factors.
Roof, rib, and face falls accounted for about 50 percent of yearly
mine fatalities until the mid-1960s and still are the most important
cause of mine fatalities. Roof and rib falls also accounted for a
substantial part of the nonfatal coal mining accidents. Although the
number of persons hurt by a single roof or rib fall is small, the
high frequency with which they occur leads to a high death and injury
total.
The second greatest hazard in underground mining involves mining
equipment operation. An engineering safety analysis identified the
need for standardization of controls for mining equipment, noting
that the positioning and responsiveness of equipment controls varied
with manufacturer. Two causes of fatalities are often cited by
members of the mining industry—lack of mining experience and lack of
job task experience.
Less frequent accidents leading to deaths involve underground
fires and surface mine accidents. Although explosions and fire are
often the most newsworthy accidents associated with underground
mining, only 10 to 12 percent of the annual mining fatalities were
caused by these disasters from 1960 to 1970. Although the frequency
of injury and death at surface mineB is significantly less than at
underground mines, the number of accidents occurring at surface mines
has been increasing because of increasing reliance on surface mining
techniques (U.S. Environmental Protection Agency 1977a).
PREPARATION/PHYSICAL COAL CLEANING
Many pollutants associated with physical coal cleaning are
identical to those of extraction, namely acid drainage, refuse leach-
ing and burning, and fugitive dust* Since the process is conducted
for the purpose of reducing the concentration of undesirable mineral
impurities in coal, it is to be expected that the handling and con-
tainment of these substances present a major problem to the industry.
51
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TABLE 18
INJURY RATES IN SELECTED INDUSTRIES, 1973(a)
INDUSTRY
FREQUENCY
RATE(k)
SEVERITY
rate(°)
Automobile
1.60
176
(110)(d>
Chemical
4.25
397
(93)
Machinery
5.81
331
(57)
Petroleum
6.73
690
(103)
j Shipbuilding
7.08
653
(92)
j Non-ferrous metals and products
9.31
712
(76)
Mining, surface^)
9.75
1365
(140)
Tobacco
12.03
404
(34)
Construction
i
13.59
1544
(68)
1
! Railroad equipment
14.23
1361
(96)
; Quarry(e)
17.67
1825
(103)
Underground mining, except coal^e^
25.26
4431
(175)
Underground coal mining
35.44
5154
(145)
All industries(f)
10.55
654
(62)
^The data were reported by member companies of the National
Safety Council. NSC members generally have better safety
programs and lower injury rates than non-member companies.
Data are not comparable to Bureau of Labor Statistics (BLS)
rates for less severe injuries (requiring medical treatment
but not involving days of disability).
^Disabling injuries per 10^ man-hours
^Lost time (hours) per 10^ man-hours
^Average days charged per case
^Based on data for 1972
(f)Rates not fully comparable from year to year due to re-
porting inconsistencies
SOURCE: U.S. Environmental Protection Agency 1977a.
52
-------
Also included with these wastes are flocculants and other chemicals
used in and resulting from reactions during the cleaning process.
Trace Element Leaching
The predominant group of impurities removed by physical coal
cleaning which presents a health and environmental problem is the
trace metals. These include barium, cobalt, copper, nickel, rubidi-
um, strontium, yttrium, zinc, and zirconium. Generally, the concen-
trations of certain elements in the organic phase such as aluminum,
calcium, iron, silicon, manganese, and arsenic are relatively low and
are more likely to be associated with the removable mineral matter.
Those strongly associated with the organic matter and not readily
susceptible to washing include antimony, beryllium, boron, germanium,
and vanadium. The concentrations of trace elements tend to vary
among coalbeds within a region and also from region to region. Gen-
erally, the available data indicate that trace elements of interest
(toxic trace elements) tend to concentrate in the heavier specific
gravity fractions of the coal, indicating that they have an affinity
for mineral matter. In removing this matter, coal-washing plants can
reduce trace element concentrations in coal as much as 88 percent
(Cavallaro et al. 1978).
The aqueous drainage from coal refuse is usually contaminated by
acids and dissolved or suspended mineral matter. The higher concen-
trations of dissolved species are found in the more highly acidic
solutions. Typically, the acid drainage from coal refuse contains
high concentrations of iron, aluminum, calcium, magnesium, and sul-
fate ions which are derived from the major coal mineral complexes.
Recently, some of the minor or less abundant trace elements have been
identified in the drainage or leachates from coal refuse or spoils,
but a thorough assessment of this subject has not been made. There
is considerable evidence that coal refuse dumps will continue to
produce significant quantities of water-borne contaminants for many
years after their disposal (Wewerka and Williams 1978).
The effects of drainage from coal wastes can have a marked
effect on surface and ground water. In a recent study of the effects
of coal waste drainage in a Pennsylvania coal mining area, the miner-
al and trace-element contents of the water from several springs and a
number of surface waters were analyzed. Among the constituents mea-
sured were iron, manganese, aluminum, zinc, cobalt, nickel, copper,
chromium, cadmium, silver, and lead. Iron and manganese were found
to be greatly in excess of local drinking water standards for all of
the water samples and the concentration of zinc, chromium, copper,
and cadmium exceeded these standards in some of the ground waters.
Generally, the trace metal concentrations were higher in ground water
53
-------
samples than in the surface waters. A compilation of the ranges of
concentrations of dissolved species for all of the water samples
studied is given in Table 19 (Torrey 1978).
One of the main issues related to coal preparation wastes is the
importance of pH in determining the levels of trace element contami-
nation in refuse drainage. Recent studies have shown that under all
conditions of static and dynamic leaching, an inverse relationship
prevailed between pH and the amounts of elements leached from the
refuse samples. Thus, at low pH (2 to 3), worrisome quantities of
trace elements were leached from all of the samples studied; whereas,
in those systems where the leachate was more nearly neutral (pH from
5 to 7), trace element leaching and the capability of the leachates
to solubilize contaminants were minimized. Therefore, preventing the
formation of acids in refuse dumps, or neutralizing the acid drainage
as it is formed, should prove effective in controlling trace element
releases into the environment (Wewerka et al. 1978).
One aspect of coal preparation wastes is that they are generally
discarded wet or damp. This is a condition highly likely to lead to
pyrite oxidation. Also, wastes discarded in the Midwest and East
often receive substantial amounts of rain before they are covered.
These generally drain, but remain damp for long periods allowing
oxidation and trace element leaching.
Accidents
Mechanical coal-cleaning facilities have been in operation for
years. There are few fatalities at these plants (13 with respect to
coal-mining facilities in 1978, see Appendix Table A-9). A majority
of the nonfatal accidents are associated with haulage, materials
handling, and falls. The potential for explosions involving dust or
methane exists but is not considered a significant problem. Refuse
piles from coal mining or preparation activities are often used as
earthen dams. Since the 1972 Buffalo Creek, West Virginia, disaster,
where a refuse pile dam collapsed, killing 125 people, more emphasis
has been placed on coal refuse piles as potential hazards. A prelim-
inary assessment by the Bureau of Mines has indicated that more than
100 coal refuse impoundments in the eastern regions present potential
hazards (U.S. Environmental Protection Agency 1977a).
transportation
The distance of the mine mouth from the combustion site can have
a direct bearing on the amount of pollutants released to the environ-
ment For example, for Western coal production, different alterna-
tives such as shipping coal to the Midwest and mine-mouth power
54
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TABLE 19
QUALITY OF SURFACE AND GROUND WATER IN A
PENNSYLVANIA COAL-MINING REGION
Mean'
Variable
*pH
V
Monovalent Cations
Na
K
Ag
Divalent Cations
Mg
Ca
*Fe(lI)
*Mn
Zn
Ni
Co
Cu
Cr
Cd
Pb
Trivalent Cations
'Fe(III)
A1
Neutral
SiO,
Monovalent Anions
CI
HCOj
Divalent Anion
•SO/
PPM
4.24"1
1625*
15.9
4.8
120
104
61.5
29
1
0.69
0.5
PPB
RanKC6
19.7
13.2
10.3
204
13.9
985
0.54
29.6
10.8
3.6
1.8
2.69
222
0.8
1.5
0.0
5.8
3.0
0
0
0.001
0.04
0.01
1.5
0
0.3
0
0
0
2.9
0
0
28
- 6.78
7000
70
11.4
3.1
985
312
510
281
14.5
7.5
4.98
410
120
13.1
7.0
102
201
70
129
122
. 6230
Water
Standard'
6.0-8.5
<625
<50
<0.3
<0 05
<5
<1000
<50
<10
<50
<0.3
<260
<250
The average of this variable exceeds the water standard
(a) ppm = parts per million, PPB ¦ parts per billion
(b) Range units same as for mean
(c)
Recommended local drinking water standards (units sane as for mean)
pH units
(e) Micromhos at 25°C
(f) Much as HS0.
SOURCE: Torrey 1978.
55
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plants or large coal conversion plants will each have different
levels of pollutant emissions. Pollutants and disturbances of con-
cern are the pollutants released, solid wastes produced, land dis-
turbances and reclamation requirements, water requirements, and
secondary impacts associated with mining towns, roadways, and water
and waste treatment and disposal. Table 20 presents the air emis-
sions, solid waste production, and water requirements associated with
varying distances and modes of conventional coal transport from mine
mouth in Montana to power plant in Chicago (U.S. Environmental
Protection Agency 1978a).
Rail and Truck
Generally, unit trains (dedicated to coal transport) provide
more efficient coal transportation and therefore contribute fewer air
pollutants, especially particulate matter, as compared with conven-
tional trans. Both trains and trucks can disperse fugitive dust
along the route with windage losses from the top of the coal being
transported. Engine exhaust emissions from locomotives and trucks,
especially on long hauls can be significant.
Water
Historically, although inland water transportation has played
a significant role in the movement of coal (e.g. , the Monongahela and
Ohio rivers), its future role is speculative owing to the pro-
jected increase in coal production from Western lands not directly
accessible to water transportation. Water problems associated with
this mode of transportation center largely around terminals where
coal is loaded and unloaded. Spilled coal in these areas can accumu-
late on sediments near piers. In these areas, typically character-
ized by low flushing rates, hydrogen sulfide, metals, and various
hydrocarbons can build up to levels harmful to aquatic biota.
Pipeline
Coal slurry pipelines have been viewed as a viable alternative
to rail transportation (Wasp 1975; 1979). One of the important un-
resolved issues is that of water availability, requiring about 1 ton
of water per ton of coal transported from water-poor areas.
There are problems incident to existing coal slurry pipeline
operations. Biologists from the University of New Mexico report
periodic large discharges of slurry fluids from the Black Mesa line
at a location known as Secret Pass in Arizona in order to avoid
separation of the slurry and thus, clogging of the line. Discharge
of such low-quality water, along with the coal being slurried, has a
substantial potential for contamination of surface water and ground
water (Train 1975).
56
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TABLE 20
ENVIRONMENTAL CONSIDERATIONS ASSOCIATED WITH VARIOUS
COAL TRANSPORTATION SCENARIOS5
Air
emissions,
in
Land use,
Water re-
thousands of
Solid waste,
in thou-
quired, in
pounds/day
in thousands
sands of
millions of
Fuel Cycle
Particles S02
HC
of tons/day^
acres0
gallons/day
Mine mouth
Surface coal mine (Montana)
55
0
0
0
5
0
Coal-fired powerplant (mine mouth)
16
3,244
37
10
13
138
Long distance transmission (Chicago)
0
0
0
0
161
0
Total for scenario
216
3,245
38
10
179
128
Rail haul
Surface coal mine (Montana)
51
1
1
0
4
0
Rail to Chicago
40
91
44
1
36
0
Coal-fired powerplant (Chicago)
147
2,976
34
9
10
117
Total for scenario
2 38
3,068
80
10
50
117
Slurry pipeline
Surface coal mine (Montana)
52
1
1
0
5
0
Slurry pipeline to Chicago
0
0
0
0
28
32
Coal-fired powerplant (Chicago)
147
2,976
34
9
10
117
Total for scenario
199
2,977
36
9
42
149
frotals may not add because of rounding.
The solid wastes assocaited with rail haul result from coal dust blown off the rail cars,
CIncludes all the land in the transmission right-of-way; only a portion of the right-of-way
land for the slurry pipeline because the land may be used for other purposes when the pipeline
is buried; and the portion of railroad right-of-way equal to the portion of the total railroad
capacity that would be taken up by coal trains.
SOURCE: U.S. Environmental Protection Agency 1978a»
-------
At the power plant the recovered water could be used as a source
for cooling water, discharged to suriface watersor used for
agricultural irrigation. High metal, salt, and hydrocar
concentrations will need to be " U"d °r
water disposal (Office of Technology Assessment 1978).
Accidents
Coal haulage in coal mining operations currently accounts for
between 10 and 15 percent of mining fatalities. In underground min-
, y accounts for about 72 percent of total
haulage^ccidents, and for 61 percent of all haulage-related man-days
1««.' A worker at the ^
location than a " toC.l haulage-related acci-
controls are involved in I" ?"ntof the total man-days loat. (U.S.
dents, and account for 69 percent o
Environmental Protection Agency 19//a;.
Rail systems transport approximately 66 percent of coal produced
0 9 in unit trains, and 44 percent via mixed
"aiM.C2"nhipmenL represented 27 percent of total rail freight
irS9 and 1,70 *t imated »« "'-^^at "n™
of coal tranapo Rcu equ£vaient tons shipped. Comparable
dents for.e^^ slurry pipeline accident rates of 0.0019 fatalities
and o!o032 nonfatal injuries for 1012 jrucU°?
rates are estimated at 0.032 fatalities and 0.69 nonfatal injuries
tor 1012 Btu energy shipped. These accident projections are based
on national statiatica for motor freight carrier, where asaumed coal
s. „;jon 1- rates are represented as the coal shipped to total
freight carrier tonnage for STc span in Ration This assumes
that the transport of coal present* no additional accident potential
than the generic rate for all motor carrier transpor s. This
motion may not hold in those regions (e.g., Appalachia) where
steep, unimproved roads may exist (U.S. Environmental Protection
Agency 1977a).
COAL STORAGE
. \-)L * 106 metric tons (137 x 106 tons) of coal
A total United States in 1975. A representative coal
were stockpiled in the Un ^ (104,000 tons) of coal. This
stockpile con ains all intensity of 1.8 «/. to 3.5
"*/' (0 25 to 0 50 in/hr) for 1 hour a day, every 2.6 days (139 daya/
fini/s (0.25 to . f ttii® rainfall drains through the
yr). Approximate y P d.,ute
-------
TABLE 21
DILUTED AND UNDILUTED EFFLUENT CONCENTRATIONS
FROM A REPRESENTATIVE COAL STOCKPILE
EFFLUENT
CONCENTRATION, g/m3
Undiluted
Diluted
Total suspended solids
1,551
0.16
Total dissolved solids
754
0.08
Sulfate
401
0.04
Iron
39
0.007
Manganese
0.69
7 x 10" 5
Free silica
10.1
0.001
Cyanide
< 0.001
<1 x 10"7
BOD5
<3.8
0.002(a)
COD
1,436
0.002(a)
Nitrate
0. 31
3 x 10"5
Total phosphate
Antimony
4.6
4 x 10-4
Arsenic
15.7
0.001
Beryllium
Cadmium
0.002
2 x 10"7
Chromium
0.004
4 x 10"7
Copper
0.08
7 x 10-6
Lead
0.06
6 x 10-6
Nickel
3.1
4 x 10"5
Selenium
19.9
0.002
Silver
Zinc
0.8
7 x 10"5
Mercury
<0.001
1 x 10-7
Thallium
Chloride
0.27
2 x 10"5
Total organic carbon
280
0.003
pH(b)
6. 78
6.9
2-Chloronaphthalene
0.014
2 x 10" 5
Acenaphthene
0.015
2 x 10"5
Fluorene
0.014
2 x 10~5
Fluoranthene
0.016
2 x 10" 5
Benzidine
0.014
2 x 10"5
Benzo(ghi) perylene
0.044
7 x 10"5
Dissolved oxygen deflcite at critical
distance (BOD5 results questionable).
^Logarithm of reciprocal of hydrogen ion
concentration in g/m^.
Note: Blanks indicate no detectable level.
SOURCE: U.S. Environmental Protection Agency 1978b.
59
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area to reach the nearest waterway. Based on a distance of 86 m to a
stream flowing at 629 m^, the diluted concentrations have been
projected to be at least one order of magnitude less than concentra-
tions considered to be detrimental to aquatic biota (U.S. Environ-
mental Protection Agency 1978b).
At present, control technology for effluents is not generally
applied at coal storage areas; however, effluent limitations have
been established. These limitations are based on application of the
best practicable control technology currently available, which is
primarily collection, neutralization, and sedimentation.
The amount of coal stockpiled at user sites has grown from 40.4
x 10^ metric tons (44 x 10^ tons) in 1940 to the present level of
124 x 10^ metric tons. The current energy shortages and mining
trends of the United States may increase coal storage quantities to
229 x 10^ metric tons (252 x 10^ tons) in 1985 and 680 x 10*>
metric tons (750 x 10^ tons) in the year 2000. Increases in stock-
pile quantities will average 3.8 percent (by weight) per year, with a
corresponding increase in mass emissions.
END USE
The environmental contaminants produced by the burning of coal
in boilers, power generators, and other stationary sources are well
identified. The oxides of sulfur, nitrogen, and carbon are the most
notorious air contaminants produced by the combustion of coal. These
contaminants enter the atmosphere in great quantities. In 1974
about 20 million tons of SO2 and 5 million tons of nitrogen oxides
(NOx) were discharged into the environment from coal burning. In
addition to these gaseous contaminants, coal combustion also produces
large quantities of finely divided mineral particulates (flyash) that
also escape into the environment. Finally, in the last few years it
has been recognized that certain toxic trace elements, such as lead
mercury, arsenic, and cadmium, may be released into the atmosphere in
substantial quantities from coal combustion sources. It is not yet
clear whether these elements are in a completely volatile state or
whether they are adsorbed on the surface of flyash or other particu-
late emissions.
The burning of coal also produces solid waste materials that
need to be disposed of in environmentally compatible ways. The bulk
of this residue is bottom ash formed by the nonvolatile mineral
matter in the coal. In addition, to lessen the air pollution load
increasing amounts of flyash are being removed from the stack com-
ponents by precipitators and other devices. About 70 million tons
of bottom and flyash are produced annually in the U.S. from coal
60
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combustion. There is growing awareness that the discarded solid
wastes from coal combustion may themselves be a serious source of
environmental contamination. In particular, these materials may be
subjected to leaching by rainwater or surface flows that could
produce mineral or trace element contamination (Wewerka et al. 1976).
Air Emissions
The fuel used, the type of combustion technology, and emissions
control technology all determine the amount of air pollutants emitted
by electrical power plants. Power plants fueled with low-sulfur coal
(e.g., 0.5 percent) usually can meet the emission requirements of
current new source performance standards. But the use of the more
abundant higher sulfur coal must also be expanded. Flue-gas desul-
furization using high-sulfur coal is one option. The advantages are
lower sulfur emissions and expanded utility of high-sulfur Eastern
coals. The disadvantages are significant capital and operating
costs, energy efficiency losses, and sludge disposal requirements.
Atmospheric fluidized bed combustion, still in the experimental
stage, promises to give higher efficiencies and lower N0X and S0X
emissions, but may also increase solid waste disposal problems. Oil
and natural gas are far cleaner to burn. These advantages are
counterbalanced by the need for these scarce fuels for other uses
such as home heating, transportation, and as chemical feedstocks
(U.S. Environmental Protection Agency 197 8a) A comparison of coal
emissions with the emissions of other energy technologies is
presented in Table 22.
Table 23 summarizes the percentage of trace elements (including
uranium) in the coal fuel of three power plants that was discharged
in the flue gas of each power plant. Although the three plants used
different coals and different control devices, the percentage of each
trace element discharged in the flue gas by each plant was similar
(U.S. Energy Research and Development Administration 1977). For
power plants with scrubbers and electrostatic precipitators, the per-
centage of trace elements released into the air can be expected to
vary widely from about 1 percent for beryllium and copper to almost
100 percent for mercury.
Coal generally contains radioactivity in amounts similar to
other sedimentary minerals. Concentrations are highly variable and
range from 0.001 to 1.3 picocuries per gram. Radioactive releases of
uranium, radium-226, and thorium, and their daughter products, may
result from the burning of both Eastern and Western coals, with the
amounts of each emission depending on the source of the coal. These
radioactive elements are not entirely released in stack gases. For
example, large quantities of radium remain with the ash and therefore
61
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TABLE 22
COMPARISON OF EMISSIONS FROM CONVENTIONAL COAL
AND OTHER ENERGY TECHNOLOGIES
Fuel Consumption
Low Sulfur Coal1''
(0.5XS)
High Sulfur Coal*
with FGD-85X
(3.0% S)
Atmospheric1
Fluidlzed Bed
Combustion
Residual Oil*
FGD-85%
(3.0XS)
Natural*
Gas
High BTU'
Gasification
3,270,000 tons/yr
2,500,000 tons/yr
2,150,000 tons/yr
400x10* gallons/yr
56x10* ft'/yr
~60xl0° ft'/yr
Air Pollutants
SOx (ton/yr)
35.000
23,000
19.000
14,000
16
280
NOx (tons/yr)
21.000
22,000
11.000
21,000
20,000
20,600
Particulates (tons/yr)
3,000
3,000
2,700
1.500
300
350
Other Pollutants
Solid Waste (tons/yr)
0
700.000
1.200.000
450.000
0
60,400
(Sludge)
Ash (tons/yr)
320.000
250,000
210,000
0
0
0
1 33% Eft. 9.000 BTU/'.n HHV
*31% Eff. 12.500 BTU ion HHV
' 36% Eff. 12.500 BTU (on HHV
' 31 % Eff. 150.000 BTl I gallon HHV
' 33% Eff. 1.050 BTU/'ft1 HHV
* 33% Eff. 1.050 BTU- 'tl1 HHV (Conversion Emissions Added )
' Medium-to-high sulfur i.uls can be physically or chemically cleaned. The use of cleaned coals is expected to produce pollutant loads similar to those of naluraHy occumng low sulfur coals
Based on a 1000 MW Power Plant
65 % Load Factor with
Various Controls
NOTE: HHV indicates heat recovery from steam released during combustion.
SOURCE: U.S. Environmental Protection Agency 1978a.
-------
TABLE 23
PERCENTAGE OF TRACE ELEMENTS IN INPUT COAL
DISCHARGED IN FLUE GAS*
TRACE
ELEMENTS
STATION I
SUB-BITUMINOUS
VENTURI SCRUBBER
STATION II
SUB-BITUMINOUS
ELECTROSTATIC
PRECIPITATOR
STATION III
LIGNITE
CYCLONE
Aluminum
0. 25
0.7
11.2
Antimony
0.61
3.9
77.9
Arsenic
7.5
0.05
20.5
Barium
<0.84
<0.09
<1.6
Beryllium
0.65
<2.0
6.5
Boron
5.9
4.7
54.1
Cadmium
7.0
<3.8
41.1
Calcium
0.85
0.8
16.6
Chlorine
75.0
80.2
80.0
Chromium
9.9
12.4
40.3
Cobalt
2.6
1.5
28.5
Copper
0.66
0.8
28.9
Fluorine
2.0
7.6
74.0
Iron
0.63
0.8
17.5
Lead
1.9
7.5
64.6
Magnesium
1.2
0.8
14.8
Manganese
0. 38
1.2
12.5
Mercury
86.8
97.9
96.1
Molybdenum
43.2
9.4
63.0
Nickel
4.1
18.2
62.8
Selenium
2.2
27.7
65.4
Silver
4.7
1.3
<15.9
Sulfur
62.2
87.8
98.1
Titanium
0.30
0.6
7.9
Uranium
2.0
1.5
27.6
Vanadium
2.5
2.4
24.9
Zinc
2.5
2.6
52.7
By Plant, Coal Type and type of Emission Control
SOURCE: U.S. Energy Research and Development Administration 1977.
63
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the element is concentrated in it (ranging from 2.1 to 5.0 picocuries
per gram (U.S. Environmental Protection Agency 1978c; U.S. Energy
Research and Development Administration 1977).
Water Emissions
Energy-related water discharges from coal-fired power plants can
be either continuous or intermittent. Continuous discharges include
flows from cooling water systems, and boiler blowdowns. Intermittent
discharges include flows from boiler water pretreatment operations,
such as ion exchange, filtration, clarification, and evaporation.
Other intermittent discharges include those from stack cleaning in
which high pressure water is used to clean flyash and soot from
stacks (wastes may include suspended solids, metals, oil, and high or
low pH values) and cooling tower basin cleaning waters which contain
suspended solids. Basically, two major categories of water pollut-
ants from steam electric power plants are heat and chemical wastes.
The chemical pollutants from a steam electric power plant result
from chemicals added to plant cooling water or process systems, pro-
ducts of corrosion (as well as corrosion inhibitors), erosion, wear
or chemical reaction from plant systems, combustion products, resi-
duals from pollution control equipment, and rainfall run-off.
Traditional pollutants of concern and limited by EPA for control in
various waste streams have been pH, polychlorinated biphenols, total
suspended solids, oil and grease, copper, iron, free and residual
chlorine, zinc, chromium, phosphorus, and various other corrosion
inhibitors. Many other water pollutants appear in power plant waste-
waters, and many do not have their source in programs for corrosion
and scale control. The specific concentrations and quantities of
pollutants which may appear in a particular waste stream depend on
the specific design characteristics of the plant, its control
programs for water chemistry and fouling organisms, as well as the
influence of regulatory constraints. For an in-depth review of the
technology of wastewater management in the steam electric power
industry, its capabilities, and costs, the reader is referred to
Teknekron, Inc. (1976).
There are two basic approaches that can be used to control ther-
mal discharges. (This discussion of thermal effluents is taken
largely from U.S. Energy Research and Development Administration
1975). One is to reduce or eliminate the amount of heat released to
receiving waters, and the other is to manage the environment which
receives these discharges (e.g.» temperature limitations, mixing-zone
requirements, etc.). The current emphasis is on the former as the
basis for regulatory activity. Elimination or reduction of the
quantity of heat discharged may require the implementation of cooling
ponds or towers (Figure 6).
64
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CHANNEL
OR
RIVER
EVAPORATION
AND
BLOWDOWN
TO
DISPOSAL
NATURAL DRAFT WET COOLING TOWER COOLING SYSTEM
COOLING POND COOLING SYSTEM
SOURCE: U.S. Energy Research and Development Administration 1975,
FIGURE6
THERMAL EFFLUENT CONTROL SYSTEMS
65
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Heat rejection from power plants through the use of cooling
ponds is highly dependent upon site weather conditions. The heat is
rejected from the pond surface by the natural effects of conduction
convection, radiation, and evaporation. However, the cooling pond
also absorbs heat through the processes of solar radiation and
atmospheric radiation to the pond, as well as waste heat from the
power plant.
Cooling ponds offer several advantages:
• reasonable construction costs where soil conditions permit
• service as a settling basin for suspended solids
• potential for cooling system operation for extended periods
without makeup water
• potential for recreational activities and as a wildlife
sanctuary
The two major disadvantages associated with cooling ponds are:
• the requirement for a large land area
• the necessity of a low permeability soil basin
Natural draft wet cooling towers are basically large chimneys
that provide a draft to pull air over the surface of a body of water.
The heat is removed from the cooling water through evaporation and
heat transfer. The large towers use the density difference between
warm moist air in the tower and cooler ambient air outside the tower
to create a draft in the tower shell. Because of their hyperbolic
shape, the internal losses from acceleration of gases up the chimney
are minimized thereby maximizing the available draft. Natural draft
towers are usually constructed from reinforced concrete and range in
size from 250 to 400 feet in diameter, with heights from 320 to
nearly 500 feet.
The advantages associated with natural draft towers include:
• long-term maintenance free operation
• relatively small ground space requirement
• opportunity for relatively low piping costs when the tower
can be located adjacent to the power plant
66
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• no electrical consumption by fans needed to induce the tower
draft
• fewer electrical controls and less mechanical equipment than
required for a mechanical draft tower
The principal disadvantages of natural draft towers are:
• a decreased ability to design the system as precisely as one
that includes mechanical draft towers
• an inability to control air outlet temperatures as well as
with mechanical draft towers
• tendency of the tower's large size to dominate the landscape
Alternative cooling systems such as once-through cooling and dry
cooling tower systems possess particular problems which constrain
their acceptance. The impact of thermal pollution on natural waters
as a result of once-through cooling eliminates this system for seri-
ous consideration in the construction of new power plants. The pen-
alty to overall power plant efficiency associated with dry cooling
towers because of power consumption also eliminates this type cooling
system from serious consideration. The reduced plant efficiency
would necessitate a greater coal input to achieve the desired elec-
trical output. This would have the deleterious effect of increasing
all of the power plant air, water, and solid waste emissions. Fur-
ther, the capital cost for dry towers is significantly higher than
wet towers. While dry towers would reduce the consumptive use of
water by the power plant, the power plant consumption is a relatively
small portion of the coal complex water requirement.
Solid Wastes
The solid wastes produced by coal-fired power plants in combus-
tion and stack-gas cleaning pose a serious environmental concern.
The incorporation of incombustible shale material into the coal
results in an ash. Also, a variable increase in iron content due to
pyrite in coal commonly occurs in the ash, and an increase in calcium
in the ash can arise from carbonate minerals in the coal or from
limestone used in stack-gas scrubbers. Coal ash usually contains
some unburned carbonaceous material.
Various chemical and mineral compositions of laboratory ash,
bottom ash, and flyash have been reported in many publications.
Generally, it has been observed that the trace element composition of
coal ashes can vary considerably depending on the source of coal and
the combustion process employed. Flyash makes up from 10 to 85
67
-------
percent of coal ash residue (in most modern plants it is 70 to 80
percent) and usually occurs as spherical particles (0.5 to 100 jjl )
called cenospheres. Bottom ash is composed of coarser and heavier
particles than fly ash and contains a high amount of a glassy com-
ponent called slag (Ray and Parkey 1977).
Lime, limestone, and double-alkali scrubbing processes to remove
sulfur oxides from power plant stack gases (flue-gas desulfurization,
FGD) have undergone extensive testing and some plants, new and
retrofitted, are already in operation. It is recognized that FGD pro-
duces large quantities of sludge consisting primarily o£ water and
calcium-magnesium sulfates and sulfites. The sheer magnitude of
these wastes from lime and limestone FGD presents a potentially seri-
ous disposal problem. It is estimated for a 500-megawatt power plant
burning 3.5 percent sulfur coal that the volume of solids (50 percent
moisture) produced annually would occupy about 6,000 acre-feet.
Studies of the composition, solubility, and disposal of FGD
sludges have been made by Rossoff, et al. (1977). Table 24 gives a
range of concentrations of chemical constituents in FGD sludges. A
direct relationship has been observed between trace element amounts
in the sludge and those in the coal. Further, a direct relationship
between trace elements in sludge and flyash suggests that flyash is
the principal component containing the trace elements in the sludge.
The most persistent pollution potential appears to be from percola-
tion of wastes through the sludge and into the subsoil, assuming best
management practice is not utilized for land disposal (Rossoff, et
al. 1977).
Accidents*
Data on accidents associated with electrical power generation
are sparse. Present Federal Power Commission (FPC) regulations
require accidents to be reported to the FPC only when loss of power
occurs. Thus, it is conceivable that an explosion in a boiler kill-
ing or injuring many workers will not be reported because an auxil-
iary boiler or generator took over and prevented a power outage. Many
state regulatory agencies have reported requirements which are more
strict than those for the Federal Government (e.g., the New York
State Public Service Commission).
A serious accident which can occur at a boiler-fired plant is
explosion of the boiler. Boilers operate at a combustion temperature
of approximately 1500° F and pressures of 10 atmospheres. Such pres-
sures can present an explosion hazard. The probability of explosion
*U.S. Environmental Protection Agency 1977a.
68
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TABLE 24
RANGE OF CONCENTRATIONS OF CHEMICAL CONSTITUENTS IN
FLUE GAS DESULFURIZATION SLUDGES
SCRUBBER
CONSTITUENT
SLUDGE CONCENTRATION RANGE
Liquor, mg/1
(except pH)(a)
Solid, ppn/k^
Aluminum
0.03
2.0
Arsenic
<0.004
1.8
0.6
52
Beryllium
<0.002
0.18
0.05 -
6
Cadmium
0.004
0.11
0.08 -
4
Calcium
180
2,600
105,000
268,000
Chromium
0.015
0.5
10
250
Copper
<0.002
0.56
8
76
Lead
0.01
0.52
0.23 -
21
Magnesium
4.0
2,750
Mercury
0.0004
0.07
0.001 -
5
Potassium
5.9
100
Selenium
< 0.0006
2.7
2
17
Sodium
10.0
- 29,000
(4.8)
Zinc
0.01
0.59
45
430
Chloride
420
- 33,000
(0.9)
Fluoride
0.6
58
Sulfate
600
- 35,000
35,000
473,000
Sulfite
0.9
3,500
1,600
302,000
Chemical Oxygen
Demand
<1
390
Total Dissolved
Solids
2,800
- 92,500
PH
4.3
12.7
(a)
(b)
Liquor analyses were conducted on 13 samples from 7 power plants
burning eastern or western coal and using lime, limestone, or
double-alkali absorbents.
Solids analyses were conducted on 6 samples from b power plants
burning eastern or western coal and using lime, limestone, or
double-alkali.
SOURCE: Rosshoff, etal. 1977.
69
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can be increased by the high dynamic stresses caused by high tempera-
ture and erosion in localized areas where temperatures may be greater
than 1500° F.
Several additional but infrequent accidents can occur in the
boiler-fired plant. Subatmospheric pressure in the condenser could
cause an implosion, destroying the condenser. A tube rupture in the
boiler can occur, leading to damage to the equipment as well as
shutdown. A high-pressure, high-temperature steam line could rupture
causing injury or death to nearby workers. Statistics on these
accidents are not available.
The most severe accidents which may occur at a gas turbine plant
are explosion, asphyxiation, and ruptured lines. Explosion, with
possible subsequent fire, can occur in the turbine, compressor, com-
bustor, and recuperator. In gas turbine and steam plants, explosions
may occur in the fluidized bed combustor system with ejection and
dispersion of the bed contents. The containment vessel in an atmos-
pheric fluidized bed system could rupture as a result of accidental
pressurization, whereas pressurized vessels can suffer burn-through
and explode. Both atmospheric and pressurized fluidized bed systems,
fired with coal, also run the risk of fire from spontaneous combus-
tion. An additional accident which may occur in gas turbine plants
is asphyxiation from toxic working fluids. Two developmental gas
turbine systems, integrated low-Btu gasification and refined coal,
could release toxic substances such as hydrogen sulfide, carbon mon-
oxide, and coal tar volatiles from leaks, pressure ruptures, process
failures, or human error. The fluidized bed coal combustor could
release alkali metal hydroxides through leaks, pressure ruptures,
error, or spilling. In the condensor or boiler an accident could
occur which would result in an alkali metal water reaction causing
fire explosion.
70
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72
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75
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Part 2
Chemical Coal Cleaning
-------
TABLE OF CONTENTS
Page
LIST OF ILLUSTRATIONS 79
LIST OF TABLES 80
INTRODUCTION 81
MAGNEX CHEMICAL COAL CLEANING PROCESS 85
TECHNOLOGY DESCRIPTION 85
Overview 85
Process Description 85
Process Chemistry 87
Technology Status 88
POLLUTANTS/DISTURBANCES 89
SYRACUSE CHEMICAL COAL COMMINUTION PROCESS 91
TECHNOLOGY DESCRIPTION 91
Process Description 91
Technology Status 91
POLLUTANTS/DISTURBANCES 93
MEYERS PROCESS 96
TECHNOLOGY DESCRIPTION 96
Process Description 96
Process Chemistry 98
Technology Status 98
POLLUTANTS/DISTURBANCES 100
PITTSBURGH ENERGY TECHNOLOGY CENTER CHEMICAL
COAL CLEANING PROCESS 104
TECHNOLOGY DESCRIPTION 104
Overview 104
Process Description 104
Process Chemistry 106
Technology Status 107
POLLUTANTS/DISTURBANCES 107
GENERAL ELECTRIC CHEMICAL COAL CLEANING PROCESS 108
TECHNOLOGY DESCRIPTION 108
Overview 108
Process Description 108
Technology Status 110
POLLUTANTS/DISTURBANCES 111
77
-------
TABLE OF CONTENTS (Continued)
Page
BATTELLE CHEMICAL COAL CLEANING PROCESS 113
TECHNOLOGY DESCRIPTION 113
Overview 113
Process Description 113
Process Chemistry 116
Technology Status 117
POLLUTANTS/DISTURBANCES 121
JPL COAL DESULFURIZATION PROCESS 123
TECHNOLOGY DESCRIPTION 123
Process Description 123
Process Chemistry 126
Technology Status 129
POLLUTANTS/DISTURBANCES 130
KVB CHEMICAL COAL CLEANING PROCESS I33
TECHNOLOGY DESCRIPTION 133
Process Description I33
Process Chemistry 135
Technology Status 136
POLLUTANTS/DISTURBANCES 136
AMES CHEMICAL COAL CLEANING PROCESS I39
TECHNOLOGY DESCRIPTION 139
POLLUTANTS/DISTURBANCES 141
ATLANTIC RICHFIELD COMPANY PROCESS 143
TECHNOLOGY DESCRIPTION 143
POLLUTANTS/DISTURBANCES 143
MISCELLANEOUS CHEMICAL COAL CLEANING PROCESSES 144
REFERENCES 147
78
-------
LIST OF ILLUSTRATIONS
Figure Number Page
1 Magnex Process Flow Sheet 86
2 Syracuse Coal Comminution Process Flow
Sheet (Conceptual) 92
3 Emissions Associated with the
Syracuse Process 94
4 TRW (Meyers) Process Flow Sheet 97
5 Emissions Associated with the Meyers
Process 102
6 PETC Process Flow Sheet 105
7 General Electric Microwave Process
Flow Sheet 109
8 Flow Diagram of the Basic Hydrothermal
Coal Process 114
9 JPL Process Flow Sheet 124
10 Process Flow Diagram for Laboratory
Scale Coal Desulfurization 125
11 Emissions Associated with the JPL Process 131
12 KVB Process Flow Diagram 134
13 Emissions Associated with the KVB Process 138
14 Flow Diagram and Emissions Associated with
the Ames Process 140
79
-------
1
2
3
4
5
6
7
8
9
10
11
12
pa&e
82
88
95
99
101
119
120
127
132
137
142
145
LIST OF TABLES
Summary of Major Chemical Coal Cleaning
Processes
Comparison of Feed and Clean Coal
Summary of Emission Sources from
Syracuse Process
Major Advantages and Disadvantages of
Meyers Process
Summary of Emission Sources from Meyers
Process
Chemical Analysis of Raw and Hydrothermally
Desulfurized Pittsburgh Seam (Westland) Coal
Trace Element Reduction in Coals Treated
by the Battelle Hydrothermal Process
Summary of Coal Desulfurization Data—
Eastern, Midwestern, Western Coals
Summary of Emission Sources from JPL
Process
Summary of Emission Sources from KVB
Process
Summary of Emission Sources from Ames
Process
Results of Microbiological Treatment of
Utility Coal for Sulfur Removal
-------
INTRODUCTION
Chemical coal cleaning processes involve sulfur oxidation or
leaching to remove pyritic and organic sulfur from coal prior to com-
bustion. These processes are still under development and mostly, are
at bench scale. The largest unit which has been tested to date is 8
metric tons of coal per day (Meyers Process). Consequently, data on
emission rates are not established, and the potential environmental
impact of the chemical coal cleaning processes cannot be assessed at
this time.
Thirteen chemical coal cleaning processes are identified and re-
viewed in this section.* Among them, nine processes are classified
as major processes; and four as minor ones as a result of their early
stage of development. All the identified processes are currently ac-
tive except the Meyers Process which is temporarily inactive and the
Jolevil process whose development status is unknown. The Meyers pro-
cess is the most advanced chemical coal cleaning process to date;
therefore, it is included despite its inactive status.
The nine major chemical coal cleaning processes are greatly
diversified with respect to factors such as:
• major process scheme and performance
• process chemistry
• process development status
• potential pollution associated with the process
Table 1 shows a listing of the nine major processes with brief
summaries of the above factors. Comprehensive discussions of these
factors for the major processes are presented in the following
sections. The four minor processes will only be given summaries be-
cause of their short development efforts.
The recently revised EPA New Source Performance Standards for
utility boilers have resulted in a more stringent sulfur dioxide em-
ission limit which will have implications for the ultimate utility of
a number of chemical coal cleaning processes. In some cases, scrub-
bing will still be required to meet SO2 emission levels. When the
*For a more complete and detailed description of many of these
processes, the reader is referred to: Oak Ridge National Labora-
tory. 1979. Survey and Evaluation of Current and Potential Coal
Beneficiation Processes. ORNL/TM-5953. Oak Ridge, Tennessee.
81
-------
TABLE 1
SUMMARY OF MAJOR CHEMICAL COAL CLEANING PROCESSES
PROCESS &
SPONSOR
TYPE SULFUR
REMOVED
STAGE OF
DEVELOPMENT
EMISSION/EFFLUENT
ISSUES
"Magnex," Hazen
Research Inc.,
Golden. Colorado
Dry pulverized coal treated
with FE (CO)5 causes pyrite
to become magnetic; magnetic
materials removed magnetically.
Up to 90% pyritic
Bench and 91 kg/hr
(200 lb/hr) pilot plant
operated
Disposal of S-containing solid
residues. Health and safety
considerations involving the
use of iron carbonyl and carbon
monoxide.
"Syracuse," Syracuse
Research Corp.,
Syracuse, N.Y.
00
N>
"Meyers," TRW, Inc.,
Redondo Beach, CA
Coal is comminuted by
exposure to NH^ vapor;
conventional physical
cleaning separates coal
from the noncombustible
mineral content.
50-70% pyritic
Bench scale
Oxidative leaching using
Fe2 (SO^>3 + oxygen in
water
90-95% pyritic
8 metric ton/day PDU
for reaction system.
Lab or bench scale for
other process steps
Disposal of sulfur containing
residues
Disposal of acidic FeSO^ and
CaSO^
"PETC," Bruceton, PA Air oxidation and water <^90Z pyritic; up Bench scale 11 kg/day Gypsum sludge disposal
leaching at high tempera- to 40% organic (25 lb/dav) continuous
ture and pressure unit under construction
-------
TABLE 1
(Concluded)
PROCESS &
SPONSOR
METHOD
TYPE SULFUR
REMOVED
STATE OF
DEVELOPMENT
EMIS SION/EFFLUENT
ISSUES
"GE," General
Electric Co.,
Valley Forge, PA
Microwave treatment of
coal permeated with NAOH
solution converts sulfur
forms to soluble sulfides
75% total S
Bench scale
Trace elements and hydrocarbon
in bleed stream
"Battelle"
Laboratories,
Columbus, OH
Mixed alkali leaching
*"95% pyritic;
^25-50% organic
9 kg/hr (20 Ib/hr)
mini pilot plant and
bench scale
Trace elements and hydrocarbon
in bleed stream
"JPL," Jet Propulsion
m Laboratory, Pasadena,
CO CA
Chlorinolysis in organic
solvent
~90% pyritic; up
to 70% organic
Lab scale but proceeding
to bench and mini pilot
plant
Hazards of solvent; chlorine
and chlorinated HC
"KVB," KVB, Inc.
Tustin, CA
Sulfur is oxidized in NO2
containing atmosphere,
sulfates are washed out
•^100 pyritic; to
40% organic
Laboratory
Waste and possibly heavy metals
disposal, possible explosion
hazard via dry oxidation
"Ames," Ames Lab,
Iowa State University
Leaching by sodium carbonate
solution
Up to 80% total
sulfur; 30% organic
Bench scale
Sulfate containing wastes
"ARCO," Atlantic
Richfield Company,
Harvey, IL
Two stage chemical oxidation
procedure(similar to "PETC"
process)
yV95% pyritic; some
organic
Continuous 0.45 kg/hr
(1 lb/hr) bench scale
unit
-------
more promising chemical cleaning processes are sufficiently advanced
economic studies will be required to determine if these processes
(with or without scrubbing) can compete with those coal-based tech-
nologies requiring scrubbing.
84
-------
MAGNEX CHEMICAL COAL CLEANING PROCESS
TECHNOLOGY DESCRIPTION (Contos 1978)*
Overview
The Magnex** process is a dry coal beneficiation process which
utilizes vapors of iron pentacarbonyl [Fe (CO)j] to selectively mag-
netize the mineral components of coal. These components are then re-
moved from the coal as a waste by passing the treated coal over a
suitable magnetic separator. The process can remove pyritic sulfur
only (as well as some ash) and is able to remove up to 90 percent of
the pyritic sulfur in some coals. At this time, the process is
partly conceptual, in that the proposed closed-loop features have not
been demonstrated.
Process Description
Figure 1 presents a simplified flow diagram of the Magnex pro-
cess. The proposed process involves four major steps:
• crushing and grinding
• heating and pretreatment
• carbonyl treatment and cooling
• magnetic separation
In the conceptualized process, run-of-mine (ROM) coal is crushed
to minus 14 mesh and then fed to the thermal pretreating unit, where
it is heated to about 170°C (365°F) in the presence of steam. The
steam and thermal treatment conditions the coal to improve the selec-
tivity of the magnetic coating.
The heated coal is then gravity fed to the iron pentacarbonyl
reaction vessel, where it is subjected to the treatment vapors at
atmospheric pressure for a residence time of thirty minutes to one
hour.
The carbonyl treated coal is conveyed to the magnetic separation
section. The treated coal passes across three induced magnetic rolls
*Unless otherwise noted.
**Proces8 patented by Hazen Research, Inc., Boulder, Colorado. The
process patent is presently owned by the Medlog Technology Group.
85
-------
VENT
SOURCE: Contos 1978
FIGURE 1
MAGNEX PROCESS FLOW SHEET
86
-------
in series. The first roll removes the strongly magnetic minerals and
the second and third rolls remove the weakly magnetic minerals. Sev-
eral commercially available magnetic separators have been evaluated
under funding by the Electric Power Institute.
After passing through the magnetic separator, the clean coal is
conveyed into a storage bin. Some clean coal from storage may be re-
turned to the CO burner for in-process use; the remaining is conveyed
to the coal compaction unit. The pelletized coal will be then con-
veyed to the product storage for subsequent shipment.
The process consumes 1 to 20 kilograms of iron pentacarbonyl per
metric ton of coal (2-40 lb/ton), depending on the feed coal; and
generates 0.6 to 13.0 kilograms (1.4 to 28.6 lb) per metric ton, of
CO for recycle.
Iron carbonyl would be produced by reacting the CO-rich gas with
iron onsite. Even with a projected CO recirculation system, a bleed
stream may be discharged from the reactor.
Process Chemistry
It has been experimentally demonstrated that free iron resulting
from decomposition of iron pentacarbonyl selectively deposits on, or
reacts, with the surface of pyrite and other ash-forming mineral ele-
ments of coal to form magnetic materials. Microscopic observations
and chemical analyses suggest that for pyrite the magnetic material
is a coating of a pyrrhotite-like mineral, while for ash the magnetic
material is metallic iron. It has also been demonstrated that the
pentacarbonyl does not deposit iron on the surface of coal particles.
Reactions suggested for this process are (Porter and Goens 1977):
• Iron carbonyl formation
Fe + CO ^" 5Fe(CO)5
(1)
• Iron carbonyl decomposition
Fe(C0)5^HTFe + 5C0
(2)
• Reaction of iron carbonyl with pyrite
FeS2 + XFe(CO)s 170°^ Fen + X)S2 + 5xco
pyrrhotite-like
(3)
• Reaction of iron carbonyl with ash-forming minerals
Ash + Fe(CO)5 Fe Ash + 5C0
iron crystallites on ash
(4)
87
-------
Technology Status (Kindig 1978)
The Magnex process has been under development for about 6 years.
The process has been investigated on a laboratory scale, using initi-
ally 75 gram samples and later one kilogram samples, in batch-scale
tests. To date about 40 coals, mostly Appalachian in origin, have
been tested. The major emphasis of the laboratory work has been on
the chemistry of the process. During this study efforts were direc-
ted to determine the effects of process variables such as reactor
temperature, iron carbonyl requirements and reaction residence time.
Based upon a successful laboratory development program and
favorable preliminary economics, a 200 lb/hr pilot plant was designed
and constructed to test the process on a continuous basis. Start-up
operation for the pilot plant was in November 1976. The feed coal
was crushed to 14 mesh, pretreated, iron carbonyl treated, and mag-
netically separated. Pretreatment and carbonyl treatment were con-
tinuous while crushing and magnetic separation were carried out on a
batch basis. Crushing was accomplished with jaw and impactor crush-
ers. Indirect heating, and pretreatment with steam at atmospheric
pressure were done while the coal passed through a screw conveyor.
Carbonyl treatment was accomplished in a shaft furnace with a very
slow concurrent flow of iron carbonyl gas, also at atmospheric pres-
sure. Magnetic separation was completed with a commercially avail-
able induced magnetic roll separator. These pieces of equipment were
a convenience for pilot plant operation and are not necessarily the
ones which would be used in a larger installation.
The pilot plant was operated continuously for five runs; each
run lasted from four to six days. Coal processed continuously
through the pilot plant behaved as expected from laboratory tests on
the same coal. Samples from the pilot plant operation met the pres-
ent EPA limits for SO2 emissions from new sources, 1.2 pounds/ mil-
lion Btu. Data showing the quality of clean coal in comparison to
feed coal are given in Table 2.
TABLE 2
COMPARISON OF FEED AND CLEAN COAL:
PILOT PLANT RESULTS
Yield
Weight %
Ash,
%
Pyritic
Sulfur,
%
Total
Sulfur,
%
Calorific
Value,
Btu/lb
Pounds of
Sulfur/
MM Btu
Clean coal
Feed coal
82.3
100.0
14.8
18.1
0.07
0.62
0.73
1.22
12,520
11,981
1.17
2.03
SOURCE: Kindig and Goens 1978.
88
-------
An economic study based upon data obtained from the pilot plant
showed that the operating cost was about equal to the cost of clean-
ing fine coal in existing coal preparation circuits.
Current plans for Magnex process development include:
1. Intensive studies on iron carbonyl generation have been most
successful and are now in the pilot plant stage.
2. Intensive search for alternate magnetic separators to sepa-
rate large volumes of dry solids efficiently and inexpen-
sively is just beginning.
3. Operate the pilot plant again, but with the coal selected
for the demonstration plant and provide support for the de-
sign engineers.
4. Design a coal preparation flowsheet, which employs the best
blend of the advantages of conventional coal processing and
the Magnex technology.
5. Improve the scope and efficiency of the process and reduce
the cost.
*
6. Proceed to a demonstration plant, about 60 tons per hour
(TPH).
POLLUTANTS/DISTURBANCES (Contos 1978)
The treat-gas stream used in this process consists of iron pen-
tacarbonyl and carbon monoxide. Both of these gases are toxic, and
thus extensive safety measures would have to be taken to isolate and
contain these hazardous materials. There are several other indus-
tries in the U.S. which currently use toxic materials. For example,
toxic nickel carbonyl is used in nickel powder manufacturing. Since
the hazard of nickel carbonyl is recognized, safety precautions have
been instituted at these plants to render their operations environ-
mentally safe. Similar control and safety measures could be insti-
tuted at Magnex plants.
Extensive use of lock-hoppers will be made to isolate the toxic
compounds. The bleed gas from the reactor would be incinerated or
scrubbed. Toxic gas alarm systems will be utilized as a warning
measure in cases of unavoidable gas emissions. The use of of proper
ventilation system coupled with adequate air emission controls would
minimize the adverse environmental effects from Magnex facilities.
89
-------
In the vicinity of the plant, coal handling, crushing, grinding,
and conveying operations would have to be enclosed to provide dust
control. Use of cyclones and baghouses for solids recovery and par-
ticulate emission control would be adequate.
There would be no waterborne waste generated by a Magnex plant.
However, the dry refuse generated by this facility would contain
heavy metals and sulfur compounds and be enriched in iron content.
This waste would have essentially the same characteristics as the
refuse material generated by physical coal cleaning plants. However,
as it would be in a totally dry and relatively compact form, it
should be more manageable.
90
-------
SYRACUSE CHEMICAL COAL COMMINUTION PROCESS
TECHNOLOGY DESCRIPTION
Process Description (Contos 1978; Datta 1976; Datta 1978)
The Syracuse chemical coal comminution process involves the ex-
posure of coal to ammonia gas or a concentrated aqueous ammonia solu-
tion. A conceptual flow sheet for this process is presented in
Figure 2.
Raw coal is sized to 3.8 cm (1 1/2 inch) x 0 mesh. It is then
fed to a batch reactor where the coal is exposed to ammonia vapor at
9 atm (120 psi) for 120 minutes. The coal is comminuted to about
1 cm (3/8") top size. After the reactor is depressurized, the com-
minuted coal is slurried with a recycle stream from the ammonia wash
column. The coal slurry is pumped to the wash column and is washed
free of ammonia with hot water. The washed coal is then dewatered
and discharged to a stockpile ready for sending to a conventional
physical cleaning plant for separating coal from pyrite-rich ash.
Based on available data, it is anticipated that the Syracuse
chemical comminution process followed by conventional physical coal
cleaning, will remove 50 to 70 percent of pyritic sulfur in coals,
with product recoveries of 90 to 60 weight percent. Appendix B,
Figures B-l and B-2 show sulfur washability curves for Pittsburgh
coal at various lengths of ammonia exposure. Figures B-3, B-4, and
B-5, as well as Tables B-l and B-2 present more experimental data on
washability and product recovery.
During the process, the ammonia disrupts the natural bonding
forces acting across the internal boundaries of the coal structure
where the ash and pyritic sulfur deposits are located. A breakage of
natural bonds occurs along these boundaries, thus exposing the ash
and pyrite for follow-on conventional separation. Since no mechani-
cal breaking is involved in the chemical comminution approach, the
size distribution of the comminuted (fractured) coal is mainly gov-
erned by the characteristics of the coal treated and the process-
operating parameters.
Technology Status
All work to date has been performed on a laboratory or bench
scale at the facilities of Syracuse Research. The largest tests have
been with 23 kg (50 lb) batches of coal, which were run in large,
specially constructed steel "bombs."
91
-------
SOURCE: Contos 1978
FIGURE2
SYRACUSE COAL COMMINUTION PROCESS
FLOW SHEET (CONCEPTUAL)
-------
In 1977 marketing of the process was undertaken by Catalytic,
Inc., Philadelphia, Pennsylvania. Currently, a washability study is
being performed at Homer City, Pennsylvania (Howard 1978). Catalytic,
Inc., is developing the engineering parameters for the chemical com-
minution reactor (Howard 1979).
Exploratory effort by Catalytic, Inc., to build and operate a
pilot plant at a suitable location [Homer City or Tennessee Valley
Authority (TVA)] is under negotiation with EPRI and TVA (Howard
1978).
POLLUTANTS/DISTURBANCES (Contos 1978)
The chemical comminution process, per se, appears to possess no
undesirable environmental aspects. Ammonia gas and resulting ammo-
nium hydroxide are utilized or operated on in a completely closed
system, so that fire or explosion hazards or escape of concentrated
vapors to the worker operating areas should be only a small possibil-
ity. In the event of a process stream leaking to the environment,
there should be sufficient provisions of seal pumps or compressors to
minimize large losses. Small losses can be safely allowed to dissi-
pate to the environment with no adverse environmental effects.
The major pollution resulting from this process is the pyrite-
rich refuse generated after physical coal cleaning of the chemically
comminuted coal.
Figure 3 and Table 3 illustrate the potential emissions from the
Syracuse process.
93
-------
ATMOSPHERE
CO
LU V)
(— I-
Q
O
— Q
I— z
cc <
<
a.
COAL
STORAGE
CO
lu cn
I— I—
< CO
_J ZD
=> Q
O
— Q
I- Z
DC <
<
CL
COAL
REDUCED
NH3
COAL
SIZING
COAL
CLEAN COAL-4-
o
z
SCRUBBER
n
X
AMMONIA
COMMINUTION
PHYSICAL
CLEANING
SCRUBBER WATER
t
NH'
COAL
COAL
WASHING
c
o
o,
nh3~h2°.
DEWATERING
COAL
COAL
FINES
AND
WATER
PYR1TE
RICH
SOLID WASTE
FINES
CLARIFICATION
AMMONIA
RECOVERY
WATER
LAND DISPOSAL
I
LEACHATE
LAND OR WATER ENVIRONMENT
FIGURE 3
EMISSIONS ASSOCIATED WITH THE SYRACUSE PROCESS
-------
TABLE 3
SUMMARY OF EMISSION
SOURCES FROM SYRACUSE PROCESS
Source Media
Coal storage Air
Water
Coal sizing Air
Scrubber on reactor Air
Pyrite rich solid Solid
waste
Characteristics
Coal dusts and particulates
Run-off
Coal dusts and particulates
NH3
Trace elements and pyrites
95
-------
MEYERS PROCESS
TECHNOLOGY DESCRIPTION
Process Description (Contos 1978)
The Meyers process, developed at TRW Inc., is a chemical leach-
ing process using ferric sulfate and sulfuric acid solution to remove
pyritic sulfur from coal. The leaching takes place at temperatures
ranging from 50° to 130°C (120°-270°F); pressures from 1 to 10 atmo-
spheres (15-150 psia) with a residence time of 1 to 16 hours. A
modification of this process is termed the "Gravichem Process," in
which the front end of the process consists of gravity separation of
the pyrite in a solution of ferric sulfate. This modification has
been successful in greatly reducing the cost of the process.
A detailed flow diagram of this process is shown in Figure 4.
The diagram includes five distinct sections of the process:
• coal sizing
• coal leaching/reaction/leachate regeneration
4 sulfur removal by high temperature steam
• sulfate removal
• washing and drying
Crushed coal, with a nominal top size of 14 mesh, is mixed with
hot recycled iron sulfate leachate. The mixing is performed in a
continuous reactor with about 15 minutes residence time. The wetted
coal, having undergone about 10 percent pyrite extraction in the
mixer, is introduced into the reaction vessel at an elevated tempera-
ture and pressure. In this step, about 83 percent of the pyrite re-
action takes place under conditions of 5.4 atm. (80 psia) and 118°C
(245°F), with varying residence time for different coals. Oxygen is
simultaneously added to regenerate the leachate. The slurry then
moved to a secondary reactor where the reaction continues to about 95
percent completion.
The iron sulfate leachate is removed from the fine coal in a
series of countercurrent washing and separation steps. The slurry
from the secondary reactor is filtered and washed with water. Both
the filtrate and the wash water are sent to the sulfate removal cir-
cuit. The filter cake is reslurried, filtered a second time and then
reslurried with the recovered clear water and finally dewatered in a
centrifuge.
96
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SOURCE: Contos 1978
FIGURE 4
TRW (MEYERS) PROCESS FLOW SHEET
-------
Wet coal from the centrifuge is flash-dried by high temperature
steam which vaporizes both the water and the sulfur. The dry coal is
separated from the hot vapors in a cyclone and cooled to give the
clean product. The hot vapor from the cyclone is scrubbed with large
quantities of recycled hot water from the evaporator. The gas and
liquid phases from the gas cooler are separated in a cyclone. The
liquid stream from the cyclone which contains water and sulfur is
phase separated in a vessel. The gas phase consisting of saturated
steam is compressed, reheated, and recycled to the drier.
In the sulfate removal step, the filtrate and the wash water
from the first-stage filter are fed to an evaporator which recovers
most of the wash water. The by-product iron sulfate crystals are re-
moved from the concentrated leachate and stored or sent to disposal.
The remaining wash water from the first filter is partially neutral-
ized and precipitated with lime to form a gypsum by-product. The
partially neutralized wash water is combined with the dilute leachate
from the centrifuge and recycled to the process.
The Meyers process only removes pyritic sulfur, 80-99 percent.
A significant pyrite removal rate exists for various coals. Table
B-3 in Appendix B summarizes the sulfur removal results by the Meyers
process for 32 types of coals. Table 4 presents some major advan-
tages and disadvantages of the Meyers process.
Process Chemistry (Contos 1978)
The chemistry of the Meyers process is outlined in the following
equations:
(1) Coal leaching/reaction
5FeS2 + 23 Fe2(S04>3 + 24^0 —~ 51FeS04 + 24H2S04+ 4S
pyritic sulfur in coal
(2) Simultaneous leachate regeneration by oxygen
02 + 4 FeS04 + 2H2S04 —>2Fe2(S04)3 + 2H20
Technology Status (Contos 1978)
TRW conducted extensive bench-scale testing of the major treat-
ment units for the Meyers process. More than 45 different coals have
been treated, and over 100 complete material balances on the process
have been calculated and tabulated. Other than TRW1s effort, this
process was also evaluated by Battelle Columbus Laboratories,
98
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TABLE 4
MAJOR ADVANTAGES AND
MEYERS
Advantages
Advanced Development (8 metric
ton/year reaction test unit)
Abundance of available data
(tests on 45 different coals)
Significant removal of trace
elements (As, Cd, Mn, Ni, Pb
and Zn) (See Appendix B,
Figure B-6)
DISADVANTAGES OF THE
PROCESS
Disadvantages
Generation of iron sulfate waste
Sulfur removal limited to pyritic
sulfur
Long leaching time required
Complicated process scheme
99
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Stanford Research Institute, Exxon, Dow Midland, Dow-Texas, AEC-Oak
Ridge, and the University of Michigan. As a result of these exten-
sive studies of the Meyers process, this chemical coal cleaning pro-
cess is probably the best characterized process of all the chemical
coal cleaning technologies.
With EPA's sponsorship, an eight metric ton/day Reactor Test
Unit (RTU) started up in June 1977. This RTU was designed to handle
coal less than 0.32 cm (1/8 inch) in size and variable test para-
meters of temperature, pressure, residence time, and oxygen concentra-
tion. Currently, this unit is not active due to lack of funding.
Neither the Environmental Protection Agency (EPA) nor the Department
of Energy (DOE) is pursuing this process. (Kilgroe 1979; Warnke
1978).
POLLUTANTS/DISTURBANCES
The major emission streams emanating from the Meyers process are
summarized in Table 5. They are also presented in a diagram, Figure
5.
The major environmental problem associated with this process is
the disposal of a large quantity of iron sulfate by-product, which is
acidic and highly corrosive. Treatment of this waste and the recov-
ery of sulfuric acid may be required to provide an environmentally
sound solid waste material for disposal. Several techniques have
been suggested to accomplish this:
• conversion of ferrous sulfate to basic iron sulfate
• roasting to iron ores and producing a concentrated stream of
S02
• direct treatment with lime to produce calcium sulfate and
iron oxides which are both relatively insoluble
Additionally, the leaching solution, ferric sulfate, dissolves a
small amount of coal ash during reaction. Therefore, solid wastes
destined for landfill potentially contain trace elements to some ex-
tent.
The elemental liquid sulfur which is removed during the coal-
drying stage may be cast into blocks and stockpiled or sold where a
market exists. The gypsum by-products can be dewatered and disposed
of by standard acceptable practices.
100
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TABLE 5
SUMMARY OF EMISSION SOURCES
FROM MEYERS PROCESS
SOURCE
MEDIA
CHARACTERISTICS
COAL STORAGE
Air
Water
Coal Dusts and Particulates
Run-Off
COAL SIZING
Air
Coal Dusts and Particulates
PROCESS VENT FROM
REACTOR
Air
SO2 + Organics
LEACHATE TREATMENT:
Solid
Air
Solid
Gypsum (CaSO^) + I^O^ + Coal Fines
so2
Iron Sulfate Solids
1. Lime Treatment
2. Evaporation +
Roasting
3. Evaporation +
Conversion of
FeSO, to
FeSO^(SO^)3
SULFUR REMOVAL
Solid
Sulfur
101
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FIGURE 5
EMISSIONS ASSOCIATED WITH THE MEYERS PROCESS
-------
The low-pressure steam that leaves a Meyers process plant is
vented to the atmosphere and is environmentally acceptable.
One possible sulfur dioxide emission source from this process is
from the vent gas scrubber which is incorporated in this system for
the removal of traces of acid mist. This emission is expected to be
primarily oxygen containing about 10 percent SO2 and organics.
Quantitative emission characterization has not been studied for
the Meyers process. However, theoretical material balance is per-
formed and the results are included in Table B-4 in Appendix B.
103
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PITTSBURGH ENERGY TECHNOLOGY CENTER CHEMICAL COAL CLEANING PROCESS
TECHNOLOGY DESCRIPTION
Overview
The Pittsburgh Energy Technology Center (PETC) air/steam leach-
ing process employs air at elevated temperatures and pressures to
affect the bulk of the inorganic and some organic sulfur removal.
Available data from batch operations indicate that at temperatures of
150° to 160°C (300°-320°F), the PETC air/steam oxydesulfurization
process can remove more than 90 percent of the pyritic sulfur. Addi-
tionally, at temperatures in the 180° to 200°C range (360-400°F), up
to 40 percent of organic sulfur can be removed. Significant coal
losses occur at the higher temperatures.
A coal desulfurization process very similar to the PETC process
is described in a U.S. patent 3,824,084 assigned to the Chemical Con-
struction Corporation.
The PETC process is still conceptual in nature in that the con-
tinuous closed-loop features of the process have not as yet been de-
monstrated. Additionally, serious engineering problems will be en-
countered because of the corrosive nature of the reaction products.
Process Description
A conceptual flow diagram of the PETC process is shown in Figure
6. Pulverized coal is mixed with water in thie slurry mixing tank.
The coal slurry is pumped to feed-effluent exchanges where the feed
is heated with recovered heat from the reacted product. The feed is
further heated in the flash gas quench tower by direct contact with
desulfurization reaction off-gas, recycled from the product slurry
flash tank. The feed slurry at operating temperatures and pressure
is passed through a series of reaction vessels where the sulfur in
the coal is oxidized in the presence of compressed air at tempera-
tures of 105°C to 200°C (300-400°F), pressures of 0.34 KPa to 1.02
KPa (34 to 102 atm), and residence time of 1 hour or less. At these
operating conditions, it is claimed that all the pyritic sulfur and
approximately 40 percent of the organic sulfur is removed as sulfuric
acid. The product slurry is next flashed into the product slurry
tank and subsequently thickened, filtered, and dried prior to com-
pacting. A portion of the clean coal is burned to provide heat for
drying.
The coal thickener overflow is combined with the coal filter
and sent to lime treatment for neutralization of sulfuric acid and
104
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o
U1
PULVERIZED COAL-
MAKEUP-
h2o
HEAT
EXCHANGER
SLURRY
MIXING
TANK
AIRJ5L
COMPRESSOR
THICKENER
OFFGAS
X
u
REACTORS
FLASH GAS . ^
QUENCH TOWER X.
FLASH
TANK
v
LIME
RECYCLE H20
BINDER
FLUE GAS
CLEAN COAL
DRYER COAL
AIR
GYPSUM
FILTER
SOURCE: Contos 1978
FIGURE 6
PETC PROCESS FLOW SHEET
-------
ferrous sulfate. The sulfuric acid in this stream is converted to
gypsum, and the ferrous sulfate to gypsum and ferrous hydroxide.
These reaction products are sent to the gypsum sludge thickener and
subsequently filtered. The filter cake from this operation consti-
tutes the solid waste from this process. The thickener overflow and
the filtrate constitute the recycle water, which is sent to the
slurry mixing tank.
Process Chemistry
In the PETC chemical coal cleaning process the pyritic sulfur is
first oxidized to soluble sulfates. It is claimed that when the pro-
cess operates at the preferred temperature and pressure of 150°C
(320°F) and 34 atm (500 psia), essentially all the soluble sulfate is
oxidized to insoluble iron oxide and sulfuric acid. Details on the
pyrite removal reactions are given below.
2FeS2 + 7 02 + 2H20—»>2FeS04 + 2H2SO4 (1)
4FeSC>4 + 02 + 4H20—~2Fe203 + 4H2S04 (2)
The resulting stoichiometric reaction for pyrite removal is
4FeS2 + 15 02 + 8H20—»-2Fe203 + 8H2S04 (3)
The organic sulfur leaching chemistry is not well known. It is
the developer's belief that the major portion (>50 percent) of the
organic sulfur in coal is of the dibenzothiophene (DBT) type which is
inert to air at relatively high pressure and temperature. However,
the remaining fraction of organosulfurs are not DBT-like and can
react with air and steam to produce sulfuric acid (Friedman and
Warrinski 1979). The suggested organic sulfur removal reaction is as
follows:
Rj - S - R2 + 202 + H20—+ R2 + H2S04 (4)
The by-products from this process are dilute sulfuric acid and
probably some unhydrolyzed ferrous and ferric sulfate. These are
treated with lime according to the following equations,
H2SO4 + Ca(0H)2—>-2H20 + CaS04 (5)
FeS04 + Ca(0H)2—M?e(0H)2 + CaS04 (6)
The gypsum (CaS04) and ferrous hydroxide can be disposed of as
filter cake. The filtrate from this operation can be recycled to the
slurry mixing tank.
106
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Technology Status
The PETC chemical coal cleaning process was conceived approxi-
mately eight years ago by Dr. Friedman at the Bureau of Mines and the
process is currently under study at the Department of Energy's Pitts-
burgh Energy Technology Center (PETC). Initial experiments on the
air/steam oxydesulfurization of coal were carried out using a batch,
stirred autoclave system with 35 gram coal samples. This apparatus
was modified to allow continuous air flow through the stirred reactor
while the coal-water slurry remained as a batch reactant. Represen-
tative results of those tests are shown in Appendix B, Tables B-5
through B-7.
The current effort at PETC, centers on operation of a 25 kg/day
fully continuous desulfurization unit.* This system is designed to
obtain data on reaction rates and develop information on process en-
gineering and economic evaluation. Operating data is currently being
developed which will permit a decision to be made regarding the de-
sign, construction, and operation of a larger continuously operated
process development unit (PDU).** There is a possibility that a
large, private engineering group may assume the PDU effort, with sup-
port from DOE.
POLLUTANTS/DISTURBANCES
There are no serious air emission problems anticipated with this
process. The off-gas from the reaction section will be scrubbed and
condensed prior to venting. In the vicinity of the plant, coal hand-
ling, crushing, grinding, and conveying operations will be enclosed
to provide dust control. There should be essentially no waterborne
waste generated by this system, provided the plant is designed to
operate as a closed-loop system. The water balance in the system is
claimed to be very good, with minimal makeup water requirement.
A potentially serious environmental problem associated with this
process is the disposal of gypsum and ferrous hydroxide solid waste.
This filter cake, approximately 0.1 metric ton per metric ton of coal
will contain some trace metals and should be disposed of in an envi-
ronmentally safe manner.
* *
This unit is operating on a limited basis due to a lack of
funding (Friedman 1979).
JLJL , ,
Preliminary data obtained to date appear to parallel the
desulfurization ability of the PETC process as determined from
autoclave experimenta (Warzinski 1978).
107
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GENERAL ELECTRIC CHEMICAL COAL CLEANING PROCESS
TECHNOLOGY DESCRIPTION (Contos 1978)
Overview
The General Electric microwave process for chemically cleaning
coal is based on microwave irradiation of caustic-impregnated ground
coal. Both pyritic and organic forms of sulfur react with the sodium
hydroxide to form soluble sodium sulfide (Na2S) and polysulfides
(Na2Sx) during irradiation.
The uniqueness of microwave treatment lies in the fact that the
sodium hydroxide and the sulfur species in the coal can be heated
more rapidly and efficiently than coal itself. Thus, the reaction
between sodium hydroxide and sulfur occurs in such a short time and
at such low bulk temperatures that an insignificant amount of coal
degradation occurs. As a result, the heating value of the coal is
either unchanged or is slightly enhanced.
A number of bituminous coals having total sulfur contents from 1
to 6 percent, and having either predominately pyritic sulfur or
organic sulfur contents, have been tested with total sulfur removals
of 70 to 99 percent. Thus, the process does address itself to both
of the two major forms of sulfur in coal. For most coals, two micro-
wave irradiation treatments with fresh caustic are necessary. Single
treatments are generally 30 to 70 percent effective in total sulfur
removal.
The G.E. process is still conceptual in nature in that the oper-
ation of a continuous, closed-loop system has not been demonstrated
as yet.
Process Description
A conceptualized flow sheet of the G.E. desulfurization process
is shown in Figure 7. The steps involved in the process would
include the following:
• 40 mesh top-size coal is slurried with a 20 percent solution
of sodium hydroxide so that the coal is thoroughly wetted by
the caustic.
• The moist coal is then subjected to microwave radiation for
30 seconds. During this brief time, 30 to 70 percent of the
total sulfur in the coal is converted to sodium sulfide
(Na2S) or polysulfide (Na2Sx), and some of the water is
evaporated.
108
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SOURCE: Contos 1978
FIGURE 7
GENERAL ELECTRIC MICROWAVE PROCESS FLOW SHEET
-------
• The coal is then slurried in water to dissolve and remove the
sodium sulfides, dewatered, and then resaturated with about
the same concentration and amount of caustic as previously.
• After a second exposure to microwave energy, the desulfurized
coal is again washed free of sulfides and excess caustic and
is dewatered and dried to the extent required for onsite use
or is dried and compacted prior to shipping. Depending on
the coal itself and certain operating factors, at least 70
percent of the total sulfur in the coal will have been
removed.
• Wash waters containing sulfur would be processed by carbon-
ating these liquors to produce hydrogen sulfide gas (H2S),
and then recover elemental sulfur via the Claus Process.
• The sodium carbonate, which also results from the carbonation
step, would be treated with lime to regenerate soluble sodium
hydroxide and insoluble calcium carbonate.
• The latter is then kilned to produce CO2 and lime (CaO),
which are both recycled and reused.
The caustic regeneration process is almost identical to the one
being considered by the Battelle Institute as a part of their chemi-
cal coal process.
Technology Status
All work on the G.E. process to date has been done on a labora-
tory scale with small (10-100g) quantities of coal subjected to
microwave radiation from a 1 KW, 2.4 GHz or a 2.5 KW, 8.35 GHz gen-
erator. The coal is first impregnated with a 20 percent solution of
sodium hydroxide (NaOH), and sufficient caustic solution is retained
on the coal after dewatering so that about 16 parts of NaOH are pre-
sent per 100 parts of coal at the time of treatment. Batch tests
have been made on a number of coals in which the coals were irradi-
ated once or twice for varying periods of time. However, exposure
periods exceeding 30 seconds rarely gained further benefits.
Coals tested are obtained from the Fuel Sciences Department of
Pennsylvania State University. These coals provide a sulfur spectrum
ranging from low organic-high inorganic to high organic-low inorganic
sulfur. These are all bituminous coals, with heating values of
6,200-7,500 kg cal/kg (11,300-13,400 Btu/lb) and a size consisting of
-40 to +100 mesh. Details of these coals are given in Appendix B,
Table B-8. Results of laboratory treatments of these coals are given
in Table B-9, Appendix B.
110
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A 12 KW microwave generator will be in operation by the end of
1978. It is planned to make test runs on quantities of coal up to 1
kilogram. These tests will also be made in conjunction with a pres-
sure chamber which will allow microwave irradiation under pressures
of 7.8 atm (100 psig) with various inert gases. The principal func-
tions of the inert gases are to retain any evaporated water as water
vapor, to exclude oxygen from the working atmosphere, to minimize
formation of undesired oxysulfur reaction products, and to eliminate
the possibility of fire in case an electrical discharge occurs in the
reaction zone.
Total sulfur (combustible to SO2) removals of 75 percent have
been achieved for most bituminous coals, provided that two sequential
treatments are given. However, much remains to be done in terms of
equipment development and economic optimization of the process.
The only projected by-product from the G.E. process will be ele-
mental sulfur. This will be obtained by carbonation of the inter-
mediate by-products, sodium sulfide and sodium polysulfide, to form
gaseous hydrogen sulfide (H2S). Hydrogen sulfide can then be re-
acted to form elemental sulfur via the Claus or Stretford process.
Other by-products attributable to imperfections in the caustic re-
covery and the Claus or Stretford process areas are possible but are
presently unknown.
The G.E. chemical coal cleaning process possesses some excellent
potential benefits, as follows:
• On the small scale thus far tested, the process appears
highly efficient in removing sulfur from bituminous coal,
regardless of whether the sulfur is pyritic or organic.
• The coal matrix is only slightly affected by the process, and
weight and heating value yields of product based on feed coal
appear to be high but little data is currently available.
POLLUTANTS/DISTURBANCES (Contos 1978)
Few environmental problems of a special nature are apparent in
the G.E. process. Two process steps will require built-in design
safeguards to prevent their becoming safety or environmental prob-
lems, as follows:
• Carbonation of the spent aqueous stream containing sulfides
or polysulfides will result in the generation of highly toxic
hydrogen sulfide gas. Since this gas is valuable and will be
111
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further processed to elemental sulfur, a properly designed
enclosed reaction system should minimize the problems from
this unit.
• The high intensity microwave generators which will be used
must be completely shielded. If adequate shielding is not
provided, other microwave transmissions (TV, radio, telephone
microwave transmitters) will be affected. In addition,
humans can be affected adversely by exposure to microwaves,
which can produce cataracts in the eyes.
No analyses of toxic trace elements which could build up in the purge
from the closed-loop operation are available at this time.
112
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BATTELLE CHEMICAL COAL CLEANING PROCESS
TECHNOLOGY DESCRIPTION (Contos 1978)*
Overview
The Battelle hydrothermal coal process (BHCP) is based upon
hydrothermal alkali leaching of mineral and organic sulfur compounds
from coal. The process presently proposed by Battelle employs sodium
and calcium hydroxides as a mixed leachate and operates under condi-
tions of elevated temperatures and pressures. The desulfurized coal,
after filtration and washing to separate the spent leachate, is dried
and compacted for use in coal-fired utility boilers. At the present
stage of development, the process must be considered as partially
conceptual since process development has been confined primarily to
the desulfurization, product coal filtration, and washing steps.
The BHCP desulfurization step has been tested on a series of raw
bituminous coals and has been shown to extract essentially all of the
pyritic sulfur and 25 to 50 percent of the organic sulfur starting
with a range of total sulfur content of 2.4 to 4.6 percent. The
product is a solid fuel which meets the current new source standard
of a maximum of 2.16 kilograms of sulfur dioxide emission per million
kg cal (1.2 lbs/10^ Btu) with certain coals.
Process Description
A simplified schematic flow diagram at the BHCP is shown in
Figure 8.
The proposed process consists of five principal steps:
• coal preparation
• hydrothermal treatment (desulfurization)
• fuel separation (separation of spent leachate from clean
coal)
• fuel drying and agglomeration
• leachate regeneration
*Unless otherwise noted.
113
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WATER
STEAM
~
SOURCE: Stambaugh 1978.
FIGURE 8
FLOW DIAGRAM OF THE BASIC HYDROTHERMAL COAL PROCESS
-------
Coal Preparation
The raw coal is crushed and ground to suitable particle size,
generally 70 percent -200 mesh. The coal then goes directly to a
slurry tank for mixing with the leachant. Alternatively, the coal
can be physically beneficiated to remove some ash and pyritic sulfur
before introduction into the slurry tank.
Hydrothermal Treatment
The coal slurry is pumped into a reactor where it is heated to
temperatures in the range of 200° to 340°C (400° to 650°F) and sub-
jected to a pressure in the range of 18 to 170 atm (250 to 2,500
psig) to extract sulfur and dissolve a portion of the ash from the
coal. Residence time is approximately 10 minutes. It is essential
that this operation and the fuel separation step following, be
carried out in an oxygen-free atmosphere to minimize the formation of
oxysulfur compounds which prevent the quantitative recovery of sodium
hydroxide from the spent leachate.
The recommended leachate for the process is a mixture of 8 to 10
percent sodium hydroxide (NaOH) solution in a 3 percent calcium
hydroxide (Ca(0H)2) slurry. Concentrations of these components of
the leachate will vary depending on coal properties.
Fuel Separation
The desulfurized coal is separated from the leachate by means of
filtration and water washing. The leachate is then concentrated
before regeneration.
Drying and Agglomeration
Water is evaporated from the coal in a drier, leaving dry,
clean, solid fuel. This material is then compacted to a suitable
pellet size for shipment to the user.
Leachate Regeneration
A chemical regeneration step using carbon dioxide is used to
remove sulfur from the leachate as hydrogen sulfide. This gas is
then converted to elemental sulfur by either the Claus or Stretford
process.
In one of the major conceptualized portions of the BHCP, the
spent leachate would be regenerated for recycle by the C02-Ca0
process. This entails sparging the spent leachate with carbon diox-
ide to liberate the sulfur as hydrogen sulfide, which is subsequently
115
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converted to elemental sulfur by the Claus or Stretford process. The
carbonated liquor is then causticized with lime and filtered to
remove the calcium carbonate which is calcined to produce lime and
carbon dioxide for recycle. The regenerated leachate is concentrated
and recycled to the process.
Process Chemistry
Sulfur Extraction
Sulfur is contained in coal in primarily two forms—inorganic
sulfur as FeS2 (pyrite) which is associated with the mineral matter
and organic sulfur which is part of the coal molecule. During treat-
ment of the coal by hydrothermal leaching, up to about 95 percent of
the inorganic sulfur is extracted from most coals and up to 50 per-
cent of the organic sulfur is extracted from some coals.
The dissolution; or extraction, of the inorganic sulfur from
coal using alkaline leaching may involve several chemical reactions
including the following:
(1) FeS2 + OH" —~ Fe(OH)2 + S2~2
(2) 2FeS2 + 60H~^_1 Fe2C>3 + S2""2 + 2S~2 + 3h20
(3) 3FeS2 + 80H"^± Fe304 + S2"2 + 2S"2 + 4H20.
However, experimental studies on leaching of coal at Battelle
have demonstrated that sulfur species found in the spent leachate is
sodium sulfide, Na2S if the leaching is carried out to eliminate
oxygen from the system. This data would indicate that the sulfur
extraction mechanism may be as follows:
(4) FeS2 + 2NaOH —~Fe(0H)2 + Na2S2
(5) Na2S2 + Fe(OH)2—> Fe2C>3 + Na2s or
(6) Na2S2 + coal—*¦ CO2 + Na2S.
In Reaction (4), the pyritic sulfur is extracted as the disulfide.
The disulfide is then chemically reduced to form the sodium sulfide
(Na2S) by the ferrous hydroxide [Fe(0H)2] (Reaction 5) or by the
carbon in the coal (Reaction 6).
A mechanism for extraction of organic sulfur from coal has yet
to be resolved. This could occur by cleavage of carbon to carbon or
carbon to sulfur bonds. A simple organic sulfur compound (CH3 - S
-CH3) has been identified in the gases evolved during desulfuriza-
tion of the coal.
116
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Leachate Regeneration
As discussed above under the desulfurization mechanism, the
spent leachate contains sulfide sulfur as Na2S, which must be re-
moved in order to recylce the leachate. One approach for achieving
this is by the C02~Ca0 process. This involves:
(1) Liberation of the sulfide sulfur as H2S by carbonation
according to the following reactions
NaOH + Na2S + CO2 ^2° H2S + NaHCC>3
NaHC03 +A—~ Na2C03 + C02»
(2) Regeneration of NaOH by treatment of the solution from (1)
above with lime.
Na2C03 + Ca0_>CaC03 + NaOH.
(3) Regeneration of CaC03 for recycle by thermal decomposition
CaC03 +A—»Ca0 + C02«
Technology Status
The original Battelle hydrothermal coal process has been under
development at the Columbus Laboratories since 1960 (initially under
Battelle sponsorship). The desulfurization step has been carried
through prepilot level (continuous bench-scale) laboratory investi-
gations. In this effort, sulfur extraction from approximately twenty
different eastern and midwestern bituminous coals have been studied.
Battelle has published sulfur extraction data on a number of coals.
In all of these studies, the SO2 emission on the BHCP treated coals
was equal to or less than the EPA New Source Performance Standards of
2.16 kg/10^ kg cal (1.2 lb/10^ Btu) for coal-fired steam gener-
ators. Results of these studies are given in Appendix B, Tables B-10
through B-12.
Liquid/solid separation and regeneration of spent leachate are
being studied under EPA Contract No. 68-02-2187 in bench-scale
equipment in an attempt to:
• establish definitive information as to whether the process
can operate in closed-loop fashion
• improve the economic viability of the process by reducing the
cost of these two high-cost segments
117
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These studies are covered in detail in a progress report pre-
sented at an EPA symposium on Coal Cleaning held in Miami, Florida
on Sept. 11-15, 1978 (Stambaugh 1978). ' '
The EPA has funded a third area of interest in the BHCP: a com-
bustion study on BHCP treated coals (Contract No. 68-02-2119). This
study was a laboratory-scale evaluation of BHCP-treated coal combus-
tion characteristics. This work was completed and reported in
November of 1976 (Stambaugh 1976).
With respect to regeneration of spent leachate, experimental
efforts have concentrated on screening the use of zinc and iron com-
pounds as possible regenerants for spent leachate from the coal
desulfurization step. Results so far have not indicated significant
process viability for either of these two heavy metals as alkali re-
generants. In the case of zinc, there are indications of residual
zinc buildup in the coal as well as environmental problems expected
when zinc sulfide is roasted to regenerate the zinc oxide. In the
case of iron oxides or hydroxides as possible regenerants, there has
been no notable success to date. Ferrous carbonate shows promise as
a regenerant although recovery of this material for recycle to the
regeneration step has yet to be demonstrated.
To date, experimental work on optimization of the solid and
liquid separation treatment of the slurry from the desulfurization
step indicates that coarser coals (-20 and -50 mesh coal as compared
to -200 mesh used in the original studies) and other process modifica-
tions could reduce the residual moisture and residual sodium in the
filtered, washed coal to 42 percent and 0.5 percent respectively.
Chemical analysis of the raw coal and a typical coal product filter
cake are summarized in Table 6. To achieve the levels of sodium and
moisture shown, it is presently conceptualized that 10 countercurrent
stages of saturated lime water repulp filtration-washing followed by
centrifugation would be required (Stambaugh 1978).
In the preliminary combustion studies with two BHCP-treated
coals, the combustion characteristics of these coals were determined
in two test facilities at Battelle, a one-half kg/hr (one lb/hour)
laboratory-scale furnace and a 10-40 kg (20-80 lb) per hour multi-
fuel furnace facility. Tests in both units were conducted with dry,
pulverized BHCP-treated coal. The results of these tests indicated
that the treated coals would meet the present U.S. EPA-NSPS for
sulfur dioxide emissions and that combustion of these coals proceeded
as well or better than the corresponding raw coals (Stambaugh 1976).
The BHCP appears to have a significant effect on the trace ele-
ments levels of the treated coals. Table 7, compares the concentra-
tions of twelve trace elements in raw coals and in the leached
118
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TABLE 6
CHEMICAL ANALYSIS OF RAW AND HYDROTHERMALLY
DESULFURIZED PITTSBURGH SEAM (WESTLAND) COAL
H90 Ash,Mf(S,MAF^b) Na.MF Ca.MF
Raw Coal, percent 2.11 7.96 2.08 0.02 0.07
Treated Coal, percent^ 42.0 7.88 0.86 0.43 2.65
(a) MF: Moisture free basis.
(b) MAF: Moisture, ash free basis.
(c) Raw coal ground -50 mesh prior to treatment with 0.24 lb NaOH/lb
coal and 0.10 lb CaO/lb coal at 275° C and 1000 psig. Washing
conducted by six stages of saturated lime water repulp washing at a
2.0 lb wash water/lb dry solids ratio. Separation was by vacuum
filtration followed by a final centrifuge dewatering.
SOURCE: Stambaugh 1978.
119
-------
TABLE 7
TRACE ELEMENT REDUCTION IN COALS TREATED
BY THE BATTELLE HYDROTHERMAL PROCESS
Metal
Concentration, ppm
Raw Coal Leached Product
Reduc t ion
Lithium
15
3
80
Beryllium
10
3
70
Boron
75
4
95
Phosphorus
400
80
80
Chlorine
20
2
90
Potassium
5000
200
96
Vanadium
40
2
95
Arsenic
25
2
92
Molybdenum
20
5
75
Barium
25
4
84
Lead
20
5
75
Thorium
3
0.5
83
~Average value for 3 Ohio coals: CN719-Seam 6, HN658-Seam 6A,
and Jackson-Seam 4. Analyses were conducted by Battelle.
SOURCE: Cleland 1976.
120
-------
product for three Ohio coals. Based on these results, less trace
metals emissions than would be expected from combustion of BHCP coals
compared to raw coals. Varying quantities of the leached trace ele-
ments would be expected to precipitate with the solubilized coal in
the sulfide stripping operation and then be removed in the filter
cake in the subsequent filtration operation. Landfilling of this
material could present some environmental problems.
POLLUTANTS/DISTURBANCES (Contos 1978)
The BHCP is claimed to be essentially free of environmental
problems due to the "closed-loop" feature of the process. However,
this assertion is open to question because of the following factors:
• The feasibility of the closed-loop feature in a continuous
process is as yet undemonstrated. In a limited batch-type
evaluation of the carbon dioxide/lime regeneration process
for the mixed leachate (four complete recycles of the re-
generated mixed leachate were carried out), there is a ten-
dency for oxysulfur compound buildup which inhibits the de-
sulfurization ability of the recycled mixed leachate. A
fairly sizable purge stream may have to be discharged from
the system for disposal. This stream would contain some dis-
solved organics and trace metals from the hydrothermally
treated coal. Additionally, pH adjustment of this stream
prior to disposal would create large quantities of dissolved
salts. Disposal of this stream could therefore pose environ-
mental problems.
• In the processing scheme proposed by Battelle, the ash solu-
bilized by the hydrothermal treatment would precipitate as a
result of the carbonation of the spent leachate (in the sul-
fide stripping step). The filtered ash would contain some
precipitated metals and insoluble inorganics and could pose
environmental problems if placed in ordinary landfills.
• Elemental sulfur recovery from the sulfide stripping opera-
tion will be accomplished by treatment of the hydrogen sul-
fide in either a Claus or Stretford process. Tail-gas from
the Claus or Stretford process will require scrubbing for
sulfur dioxide or hydrogen sulfide removal, respectively.
• Conveying of the -200 mesh, dry, treated coal to either a
briquetting operation or intermediate storage, may create
particulate emissions problems (and possible spontaneous com-
bustion problems due to the pyrophoric nature of this mater-
ial). Use of baghouses, water sprays, and cyclones may be
121
-------
necessary for recovery of Che submicron-size solids before
venting the gases to the atmosphere. Use of coarser mesh
coals (e.g., 20 to 50 mesh) would appreciably minimize these
problems.
• In the closed-loop calcination of the precipitated calcium
carbonate to regenerate calcium oxide, the possibility of
impurity buildup in the lime, i.e., heavy metals and ash com-
ponents from the coal, could require periodic purge of this
material. Disposal of the purged material could pose envi-
ronmental problems.
Until the BHCP is operated as a continuous closed-loop process
in at least pilot scale quantities, e.g., 8-10 tons per hour, mean-
ingful data on actual quantities of the pollutants referred to above
is not available with which to assess the environmental and health
effects of the process.
122
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JPL COAL DESULFURIZATION PROCESS
TECHNOLOGY DESCRIPTION
The Jet Propulsion Laboratory of the California Institute of
Technology has developed a coal desulfurization process by a two-
stage process that includes chlorination and dechlorination. An en-
couraging feature of the process is that high organic sulfur removal
is demonstrated in conjunction with high pyritic sulfur removal
(=90%) for total sulfur removal under favorable operating conditions
of greater than 70% (Kalvinskas 1978).
Process Description (Kalvinskas 1978; Contos 1978; Frankel 1979(b))
A flow diagram based on the JPL process is shown in Figure 9.
Chlorine gas is sparged into a suspension of moist, pulverized coal
(-100 to +200 mesh) in methyl chloroform (1,1,1-trichloroethane) at
50°-100°C and atmospheric pressure for 1 to 2 hours. The suspension
consists of approximately 1 part coal to 2 parts solvent. Chlorine
(CI2) usage is 3 to 3.5 moles of chlorine per mole sulfur, or about
250 kg CI2 per metric ton (500 lbs/ton) of coal. Moisture is added
to the feed coal to the extent of 30-70 percent by weight.
After^chlorination the coal slurry is distilled for solvent re-
covery, and the solvent is recycled for reuse in the chlorinolysis
step. The chlorinated coal is then washed with water and filtered.
The coal filter cake is simultaneously dried and dechlorinated by
heating at 350°-550°C with superheated steam (or possibly a vacuum)
or hot air for about 1 hour. A process flow diagram for laboratory
scale is shown in Figure 10. Laboratory apparatus for chlorination
and dechlorination are depicted in Appendix B, Figures B-7 and B-8.
There are a number of by-product streams: (Contos 1978)
• Vented gas from the chlorinolysis reactors contains unreacted
chlorine (CI2) and by-product hydrogen chloride (HC1).
The gas is cooled to condense CI2, which is recycled, and
the relatively noncondensable HCl gas is piped to a Kel-
Chlor process unit which converts the HCl to Cl2»
• Vapors from the solvent evaporation step are cooled to permit
condensation and recycling of the methyl chloroform. The
HCl gas is piped to a Kel-Chlor unit for conversion.
• Filtrates and wash water from the filtration of washed coal
contain hydrochloric acid and sulfuric acid. The HCl is
driven off in a stripper and recycled to a Kel-Chlor unit.
123
-------
ROM
COAL'
N>
-P-
WATER 1 '
Kt POWDERED
COAL
CRUSH
AND
GRIND
H-H-
BLENDER.
SOLVENT RECYCLE
-1 SOLVENT
/nEVAP.
V
•CD'
J I
CHLORINATOR
CHLORINE
HCI +
EXCESS CI
MAKEUP
HCI
COAL WASHER
i
IWETl
ICOAL
rs
WATER
BINDER
DECHLORINATOR
ROTARY
FILTER
CONDENSER
1
COMPACTOR
TO
STORAGE
HCI
SUPERHEATED
STEAM
OR
HOT AIR
ACID
CONCENTRATOR
T
FILTRATE
HCI RECOVERY UNIT
SOURCE: Contos 1978
BY-PRODUCT
h2so4
FIGURE 9
JPL PROCESS FLOW SHEET
-------
POWDERED COAL
DESULFURIZED COAL
(WITH <0.1% CHLORINE)
SOURCE: Kalvinskas and Hsu 1978.
FIGURE 10
PROCESS FLOW DIAGRAM FOR LABORATORY SCALE
COAL DESULFURIZATION
125
-------
The residual dilute sulfuric acid is concentrated to a
salable 91 percent sulfuric acid.
• Superheated steam exhausting from the dechlorination will
also contain HC1 gas which must be condensed as hydrochloric
acid and recycled to a Kel-Chlor unit for chlorine recovery.
Coal desulfurization data for twelve eastern, midwestern and
western coals that include bituminous, subbituminous and lignite
coals show substantial organic and pyritic sulfur removal for the
majority of coals, Table 8. Five coals show greater than 50 percent
organic sulfur removal, 5 coals show better than 80 percent pyritic
sulfur removal and 6 coals show better than 60 percent total sulfur
removal (Kalvinskas 1978). No correlation appears between sulfur re-
moval and geographical origin of the coal. The desulfurization pro-
cess appears applicable to a wide variety of coals. A summary of
these results is shown in Appendix B, Tables B-13 and B-14.
Dechlorination of the treated coal at temperatures of 35° to
550°C in a steam atmosphere for 15 to 75 minutes provides residual
chlorine values from less than 0.01 to 1.29 weight percent with aver-
age values of less than 0.5 weight percent (Kalvinskas and Hsu 1978).
Process Chemistry (Contos 1978)
The chemistry of this process is somewhat complex, but is hypo-
thesized as follows:
U +
R-S-R' + Cl+ - CI" t > RSC1 + R'Cl
where R and R' represent hydrocarbon groups, and S stands for sulfur.
S-S Bond (Electrophilic cleavage) REACTION -
13 +
RS-SR' + Cl+ -ri+-j wsr.i + R'SCI
Sulfonyl chloride is oxidized to sulfonate or sulfate according to
the following reactions:
Clo, H2O A
RSC1 - RSO2CI ci2 ,H20 * rsq3h + HC1
RSC1 + 2C12 + 3H20 —~RSO3H + 5HC1
or
RSC1 Cl2, H2°» RS02C1 ' cl2*H2o» S°4 + RC1
RSC1 + 3C12 + W20 —RC1 + h2S04 + 6HC1
126
-------
TABLE 8
SUMMARY OF COAL DESULFURIZATION DATA*
EASTERN, MIDWESTERN, WESTERN COALS
COAL DESCRIPTION
PSOC-108, HVA Bit.
Pittsburgh, Wash., PA.
PSOC-342, HVA, Bit.
Clarion, Jefferson, PA.
PHS-398, Raw Head, 3A
Upper Freeport, Somerset, PA.
(BOM-High Pyr., Low Org.)
PHS-513, Mine 513,
Upper Clarion, Butler, PA.
(BOM-Phys. Cleaned, High Org.)
ORGANIC
EASTERN COALS
53
-42
34
PSOC-219, HVA Bit.
Ky #4, Hopkins, Ky.
MIDWESTERN COALS
45
PSOC-276, HVA Bit. 67
Ohio #8, Harrison, Ohio
PSOC-026, HVC Bit. 40
111. #6, Saline, 111.
PSOC-213, HVB Bit. 72
Ky. #9 (120 min., Cl2(0.182 g/min)
PSOC-190, HVA Bit. 19
111. #6, Knox, 111.
SULFUR REMOVAL (%)
PYRITIC TOTAL
79
63
92
78
81
87
13
90
68
50
71
34
63
74
72
43
47
*(Chlorination - 60 minutes, CI2 @ 0.75 g/min. - 100 grams)
127
-------
TABLE 8 (Concluded)
COAL DESCRIPTION
SULFUR REMOVAL (%)
ORGANIC PYRITIC TOTAL
WESTERN COALS
PSOC-240A.I, Sub-bit. B
Big D, Lewis, Wash. (120 Min.)
PSOC-097, Sub-bit. A
Seam 80, Carbon, Wyo.
PS0C-086, Lignite
Zap. Mercer, N. Dak.
72
12
50
58
87
37
64
34
39
Source: Kalvinskas and Hsu 1978.
128
-------
pyritic sulfur reactions are summarized as follows:
FeS2 + 2C12 — ~ FeCl2 + S2C12
2FeS + 7C12 ~2FeCl3 + 4SC12
2FeS2 + 10SC12 ~2FeCl3 + 7S2C12
S2C12 + 8H20 + 5C12 ~ 2H2S04 + 12 HC1 (FAST)
RH + S2C12 ~RS2C1 + HC1 (SLOW)
FeS2 + 7C12 + 8H20 ~FeCl2 + 2H2S04 + 12HC1.
Chlorinated coal is hydrolyzed to give hydrochloric acid ac-
cording to the following reaction.
RC1 + H20 ~ ROH + HC1
where R represents a hydrocarbon group in coal.
The sulfur converted to sulfates or sulfonate is water soluble
and is leachable by washing with water.
The possible reactions during dechlorination are:
in an inert gas atmosphere:
RH + R'Cl ~ RR' + HC1
and
in steam atmosphere:
RCl(s) + H20(g) ~ ROH(s) + HCl(g)
Technology Status (Frankel 1979 b)
As of now, effort on this process has been on a laboratory scale
batch operation using 100 gram coal samples. The follow-on activity
will include bench-scale, batch tests at 2 kg of coal per batch and
construction and operation of an integrated continous flow, mini-
pilot plant to demonstrate the process at a coal feed rate of 2
kg/hr.
129
-------
POLLUTANTS/DISTURBANCES (Contos 1978)
There appear to be several severe potential environmental prob-
lems associated with this process. The hydrocarbon solvent used for
the chlorinolysis reaction is 1,1,1 - trichloroethane which has been
listed by the EPA as a priority pollutant. Most of the substances on
the list of priority pollutants are suspected carcinogens. The re-
lease of even small quantities of this material to the environment
will probably be prohibited from a new source processing plant. Vent
gases from the chlorinolysis reactors contain chlorine and by-product
hydrogen chloride. Although these will presumably be sent to the
Kel-Chlor process unit, there is a potential for release of gases
from this process unit. Filtrate from the coal washing unit will
contain hydrochloric acid, sulfuric acid and probably chlorinated
hydrocarbons and organic sulfonates. This filtrate will be concen-
trated hydrocarbons and organic sulfonates. This filtrate will be
concentrated in a sulfuric acid concentration step which will prob-
ably require a bleed stream to remove impurities, trace elements from
the concentrated sulfuric acid product. The disposal of this bleed
stream will present some environmental problems. Also there may be
some environmental problems associated with the operation of the
Kel-Chlor Chlorine recovery process.
Figure 11 and Table 9 present the major emission streams emanat-
ing from the "JPL process.
130
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ATMOSPHERE
Q
Z
<
CO
I—
CO
ZD
a
co
Z3
o
DC
<
Q.
COAL
STORAGE
COAL
~
Li.
0
1
z
=3
cc
MAKE-UP
HC1
Q
z
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CO
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CO
ZD
Q
co
UJ
3
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Q_
Q
Z
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CO
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COAL
SIZING
COAL
~
CO
UJ
r WATER
£
BLENDER
CHLORINE
WET
COAL
o
UJ
>
—I
o
CO
or
o
_l
X
<_)
Q
z
<
CHLORINATION
UNIT
UJ
>
_j
o
CO
SOLVENT
RECOVERY
o
o
KEL-CHLOR
I *
PLANT
* I
COAL SLURRY
FILTRATE
WATER
WASHING
UJ
HC1
BLEED STREAM
CONTAINING TRACE
ELEMENTS, H2SO4,
AND CHLORINATED
HYDROCARBON
ACID
CONCENTRATOR
DISPOSAL
LEACHATE
RESIDUAL
* LIQUID
<
o
<_>
FILTRATION
STEAM OR
HOT AIR
Uf
c
o
0
DECHLORINATION
BY-PRODUCT
H2S04
I
CLEAN COAL
SALABLE
PRODUCT
LAND OR WATER ENVIRONMENT
FIGURE 11
EMISSIONS ASSOCIATED WITH THE JPL PROCESS
-------
TABLE 9
SUMMARY OF
EMISSION
SOURCES FROM JPL PROCESS
SOURCE
MEDIA
CHARACTERISTICS
Coal Storage
Air
Coal dusts and Particulates
Water
Run-off
Coal Sizing
Air
Coal dusts and Particulates
Coal Blending
Air
Coal dusts and Particulates
Chlorination reactor
Air
Solvent (methylchloroform),
HC1, Cl2
Acid Concentrator
bleed stream
Water
H2SO4, Trace Elements and
chlorinated hydrocarbon
132
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KVB CHEMICAL COAL CLEANING PROCESS
TECHNOLOGY DESCRIPTION (Contos 1978; Frankel 1979a; Guth 1978)
Process Description
The KVB coal desulfurization process is based upon selective
oxidation of the sulfur constituents of the coal. In this process,
dry coarsely ground coal (-14 to +28 mesh) is heated in the presence
of nitrogen oxide gases for the removal of a portion of the coal sul-
fur as gaseous sulfur dioxide (SO2). The remaining reacted sulfur
in the coal is claimed to be in the form of inorganic sulfates, sul-
fites or is included in an organic radical. These nongaseous sulfur
compounds are removed from the pretreated coal by subsequent washing
with water or heated caustic solution followed by a water wash.
A flow diagram of the process is shown in Figure 12. Dry coal
from the preparation section is pneumatically conveyed to a gas/solid
cyclone where it is separated from its conveying gas (nitrogen).
Then it is gravity fed into a rotary kiln reactor. The reactant gas
is introduced through the bottom of the reactor through a distribu-
tor. The reactant gas is composed of, by volume, 1.5 percent of
02, 5 percent of NO2, and the remainder of N2. The reaction is
carried out at 100° C and 1 atm for 1/2 to 1 hour. After the com-
pletion of the reaction, the gases pass through a two-stage cyclone
separator which removes the fine coal particles from the gas.
The treated coal from the reactor is next reacted with caustic
solution or water to remove additional sulfur (organic sulfur) and
also convert the ferrous sulfate hydroxide and soluble sodium sul-
fate. The coal slurry from the extractor is filtered and water-
washed on the filter. The product coal is then dried prior to com-
pacting.
The KVB process also incorporates treatment for the following
streams: N2 stream from the cyclone, and the filtrate from the
coal filter.
Nitrogen, (the transporting gas) from the cyclone is passed
through a dust collector for the recovery of fine coal particles and
is then discharged via a blower into a coal-fired heater prior to re-
cycling this gas to the coal preparation and conveying section.
The filtrate from the coal filter is treated with lime to regen-
erate caustic and form gypsum. The sludge from the lime treatment
tank is concentrated in a thickener. The underflow of the thickener
containing a large fraction of the gypsum is filtered to recover the
133
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-------
caustic solution. The thickener overflow is divided into two
streams. One portion is recycled to the extractor and the other is
sent to an evaporator for further removal of gypsum in order to pre-
vent gypsum buildup in the system. The steam generated in the evap-
orator is condensed and used as wash water for the filter cake. The
gypsum slurry is cooled and set to the gypsum filter. The gypsum
slurry is cooled and sent to the gypsum filter. Gypsum constitutes
the solid waste from this process.
The major portion of the reactor off-gas is recycled. A frac-
tion of the major off-gas leaving the purifier is vented to prevent a
buildup of inert gas in the gas stream. By venting a portion of the
gas and providing makeup gas, the required gas proportion can be
maintained. The recycle gas is then combined with makeup NO2 and
O2 to form the treat-gas. The treat-gas is compressed and recycled
to the reactor.
This process has a desulfurization potential of up to 100 per-
cent pyritic sulfur and 40 percent organic sulfur. Tables B-15
through B—17 in Appendix B present some results of the laboratory
studies. The results indicate that higher desulfurization is
achieved when the treat-gas contains 10 percent by volume of nitric
oxide.
The washing step removes iron and loosely bound inorganic mate-
rial which reduces the ash content of coal. KVB claims a 95+ percent
ash removal with their system.
Process Chemistry (Contos 1978)
The mechanism of oxidation is still unknown. Details of process
chemistry, explained by KVB, are (considered by the author to be
hypothetical):
Oxidant generation NO + 1/202 —» NO2
Pyrite oxidation FeS2 + 6NO2 —~ FeSO^ + SO2 + 6N0
Organic sulfur oxi- + NO2 —» Ri~i-R2 + NO
dation reactions 0 0
Rj—S-R2 + NO2 —~ R1—S —R2 + NO
Extraction of sulfur
from an
radical
from an organic R^-S^ + 2NaOH —» R^H + R2H + Na2S0^
135
-------
Removal of iron FeS04 + 2NaOH —~ Fe(OH)2 + Na2S04
sulfates in the
extractor
Caustic regeneration Na2S(>4 + Ca(0H)2 —»2NaOH + CaS04
Technology Status (Frankel 1979a)
This process is still in the laboratory stage where parametric
studies are in progress. Proposed design of a pilot plant oxidation
unit includes either a rotary kiln or a vertical multiple hearth.
KVB, Inc. has been acquired by Research Cottrell Corp.
POLLUTANTS/DISTURBANCES (Contos 1978)
Gaseous emissions from the integrated system will primarily
include water vapor, nitrogen, and may contain some small quantities
of nitrogen oxides as illustrated in Table 10 and Figure 13. Since
the basic process is a dry oxidation system, there will be some dust
problems; however, adherence to good engineering practices should
keep these to a minimum. In the reaction system, the coal fines in
the reaction gases will be recovered because these gases will be
passed through a two-stage, internal cyclone separator prior to leav-
ing the reactor. Both the feed coal and the treated product would be
stored in lock hoppers and introduced to the reactor or removed from
the system through air lock rotary valves. The lock hoppers will be
continuously purged with nitrogen to prevent the formation of an
explosive dust. In the vicinity of the chemical coal cleaning plant,
coal handling, crushing, grinding, and conveying facilities may need
to be equipped with dust control equipment.
The process generates solid waste consisting primarily of gypsum
with coal ash. This waste material must be handled in an environ-
mentally safe manner since it will contain some trace metals.
Essentially no waterbone waste will be generated by this system
assuming the plant can be designed to operate as a closed-loop sys-
tem. Caustic solution would be regenerated and recycled to the ex-
tractor and all water condensate from the process can be utilized as
wash water in the process.
136
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TABLE 10
SUMMARY OF EMISSION SOURCES FROM KVB PROCESS
Source
Coal Storage
Coal Sizing
Dust collector on
Cyclone
Reactor off-gas
(bleed stream)
Flue gas from dryer
Filtrate treatment
Media
Air
Water
Air
Air
Air
Air
Solid
Characteristics
Coal dusts and particulates
Run-o f f
Coal dusts and particulates
Coal dusts and particulates
NO2, O2 and N2
Coal fines and H2O
Gypsum slurry and coal ash
137
-------
o
O
oc
CL
Ui >
D ~
OjU
Z <
u
o
(ft
(ft
<
(ft
z
o
138
-------
AMES CHEMICAL COAL CLEANING PROCESS
TECHNOLOGY DESCRIPTION (Markuszewski 1978)
The Ames process is an oxydesulfurization process developed at
the Ames Laboratory, Iowa State University. This process is based on
leaching fine-size coal with a hot, dilute sodium carbonate solution
containing dissolved oxygen under pressure. Presently, this process
is at bench scale and the leaching experiment is conducted in a
1-liter autoclave reactor.
Several high-sulfur bituminous coals are studied. Parameters
such as agitation, leaching time, temperature, oxygen partial
pressure, and alkalinity on the process were investigated.
Markuszewski1s "Coal Desulfurization by Leaching with Alkaline Solu-
tion Containing Oxygen" provides detailed information on these re-
sults.
A simple flow diagram of this process is shown in Figure 14.
Crushed coal (-200 to +250 mesh) is mixed with the leaching solution
(Na2C03) in the autoclave reactor. After sealing the reactor,
the autoclave is purged with nitrogen gas while being heated up to a
desired temperature. The flow of nitrogen stops when the reactor re-
aches the desired temperature, (150°C) Oxygen is introduced into the
autoclave after venting. Some gas is bled continuously from the re-
actor to prevent any build-up of gaseous reaction products, while the
system purged with nitrogen, and the reactor cooled. The leached
coal is then recovered by filtration and dried at 90°C for 1 day.
This process removed both pyritic and organic sulfur in coal.
For pyritic sulfur, the removal mechanism appears to be:
2FeS2+ 7.5 O2 + 4 H2O—*Fe203 + 4H2SO4
H2SO3 + Na2C03—»Na2S04 + CO2 + H2O
The mechanism for removal of the organic sulfur in coal has not been
established.
At 150°C and 50 psia oxygen partial pressure, the reduction in
total sulfur is about 76-79 percent after 1.5 hours of leaching.
More concentrated alkaline solutions are less beneficial and even de-
trimental, causing lower reduction in sulfur and decreasing the heat-
ing value recovery. Leaching longer than 1-1.5 hr. results only in a
modest increase in sulfur removal, but the advantage is offset by a
decrease in heating value recovery. Increasing the oxygen partial
139
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PARTICULATES
AND
DUSTS
PARTICULATES
AND
DUSTS
ATMOSPHERE
C>2* N2, CO2j
POSSIBLY COAL
FINES
COAL
STORAGE
COAL ^
COAL
SIZING
COAL ^
LEACHING
(reactor)
COAL
SLURRY
Na2C03
SOLUTION
RUN-OFF
FILTRATION
FILTRATE
(Na2S04)
WASTEWATER
TREATMENT
SOLID
WASTE
DISPOSAL
LEACHATE
COAL
FINES
h2o
COAL ^
T\n\J T M/*
jjr\ 1
1 iiu
CLEAN
COAL
WATER
DISCHARGE
FIGURE 14
FLOW DIAGRAM AND EMISSIONS ASSOCIATED WITH
THE AMES PROCESS
-------
pressure improves the extraction of sulfur without a noticeable de-
crease in the heating value recovery. The improvement is due mainly
to an increase in the removal of organic sulfur, amounting to 30 per-
cent in some cases. An optimum temperature range has been observed
at about 120°-150°C for which the reduction of sulfur is maximum. At
higher temperatures, both the extraction of sulfur and the heating
value recovery decline significantly.
POLLUTANTS/DISTURBANCES
The major emission streams potentially emanating from the Ames
Process are summerized in Table 11 and shown in Figure 14.
The major potential environmental impact associated with this
process will be the treatment and disposal of sulfate-containing
wastes. Since this process is still at an early development stage
with limited data available, environmental effects can not be fully
assessed.
141
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TABLE
11
SUMMARY
OF EMISSION SOURCES FROM AMES PROCESS
Source
Media
Characterization
Coal Storage
Air
Coal dusts and particulates
Water
Run-off
Coal Sizing
Air
Coal dusts and particulates
Reactor Vent
Bleed Stream
Air
^2» ^2» C®2» possibly coal
fines
Coal
Air
Coal Fines, H2O
Leachate Treatment
Water
Sulfates, trace elements
Solid Sulfates, coal fines
142
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ATLANTIC RICHFIELD COMPANY PROCESS
TECHNOLOGY DESCRIPTION (Contos 1978; Slughter 1979)
The ARCO process is basically an oxydesulfuriation process which
is very similar to PETC's. It removes both pyritic and organic sul-
fur compounds and ash from coal. The process requires the use of
either a recoverable or a nonrecoverable reacting promoter. Very
little has been published about the process, no process flowsheet is
available.
Process development work has largely proceeded on the basis of
data generated from batch bench scale experiments and a 0.45 kg
(1-pound) per hour continuous reactor system. This research is
financed both by ARCO and the Electric Power Research Institute.
Five coals were selected and tested in the ARCO process:
• Lower Kittanning, Martinka #1
• Illinois #6, Burning Star #2
• Pittsburgh #8, Montour #4
• Western Kentucky #9/14, Colonial
• Sewickley, Green County, Pennsylvania (beneficiated)
Depending on the coal treated, overall reduction of sulfur was up to
95 percent for pyritic sulfur (Contos 1978; Slughter 1979), up to 35
percent for organic sulfur, and 66-72 percent for total sulfur
(Contos 1978; Slughter 1979). Overall reduction of iron was up to 96
percent and of ash up to 78 percent. The BTU yield of the process is
estimated at 90-98 percent. Ash content of the product is frequently
reduced by 50 percent, compared to feed coal, and the process weight
yield is about 95 percent, depending on ash removal.
POLLUTANTS/DISTURBANCES (Contos 1978; Slughter 1979)
From limited available data, the ARCO process appears to gener-
ate gypsum waste and an iron-containing by-product. The process is
alleged to have minimal environmental impacts. However, fugitive
airborne emissions, and trace elements potentially coexist with the
gypsum waste might require environmental considerations.
143
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MISCELLANEOUS CHEMICAL COAL CLEANING PROCESSES
UNIVERSITY OF HOUSTON PROCESS (Contos 1978; Attar 1979)
Development of this process is proceeding under the direction of
Dr. Attar of the Chemical Engineering Department of the University of
Houston. The present effort involves bench-scale development of a
modified version of the Battelle process, a low-pressure oxidation
process. The significant difference between the two processes is
claimed to be a modified leaching process (proprietary at this time)
which results in much lower residual sodium in the coal than the
Battelle leaching conditions yield.
The University of Houston process claims to remove essentially
all of the pyritic sulfur and 20 to 60 percent of the organic sulfur,
(Attar 1979). (It is believed that this process is removing at least
the mercaptan and aliphatic organic sulfur forms). This project is
studying methods to regenerate an additive to the leachate which ap-
parently represses the bonding of sodium to the coal. Experiments
have been on less than one-pound samples (using Illinois #6 and
Kentucky #9 coals) up to this point. The potential environmental
impact may result from the disposal of sulfate wastes and sulfur
oxides emissions.
OHIO STATE UNIVERSITY PROCESS (Contos 1978; Dugan 1979)
Development of a microbiological process for coal desulfuriza-
tion is under the direction of Dr. Patrick R. Dugan, of the Microbi-
ology Department at the Ohio State University, Columbus, Ohio. The
experimental effort is currently in the laboratory stage and is pri-
vately funded.
The study has been conducted with a pulverized coal blend sup-
plied by a local utility. The total sulfur content of this coal is
4.6 percent with about 3.1 percent pyritic sulfur. The coal has been
screened and used in two mesh-size ranges as well as the "as re-
ceived" material. Microbiological treatment of these fractions has
resulted in sulfur reductions as tabulated in Table 12.
Treatment time is around 7 days. The microbiological treatment
is effective in removing better than 96 percent of the pyritic sul-
fur, but appears to have little or no effect on organic sulfur.
144
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TABLE 12
RESULTS OF MICROBIOLOGICAL TREATMENT OF UTILITY
COAL FOR SULFUR REMOVAL
Initial Sulfur Percentage Final Sulfur Percentage
Mesh Size Range Total Pyritic Total Pyritic
as received
100 - 200 mesh
-200 mesh
4.6
4.1
5.4
3.1
2.9
2.9
2.0
1.8
2.0
0.1
0.1
0.1
WESTERN ILLINOIS UNIVERSITY PROCESS (Contos 1978; Venugopalan 1979)
Dr. M. Venugopalan of the Department of Chemistry of Western
Illinois University, Macomb, Illinois, has conceived a process for
coal gasification and desulfurization utilizing a plasma jet, and has
constructed a laboratory unit. During an 8-hour run, the total sul-
fur content of an essentially dry Illinois #6 coal (+6 mesh) was
reduced from 2.1 percent to 1.5 percent. Argon was initially used as
the plasma gas, but the equipment has been operated on hydrogen gas
as well. Runs in a 1-meter-long tube are carried out with about a
lOOg sample of coal using 60-100 watts of electrical power and
achieving temperatures of about 1,200°C. Off-gases are analyzed for
methane, ethane and hydrogen sulfide. With argon, the methane off-
gas is derived entirely from the coal, but with hydrogen plasma, the
coal will probably not lose very much hydrogen.
JOLEVIL PROCESS (Contos 1978)
This process was developed for Jolevil Associates, Inc., Hoover,
Alabama, by the Southern Research Institute, Birmingham, Alabama.
The process is considered proprietary with only sketchy details
available. The basic principle involved appears to be wet oxidation
of pyritic sulfur in coal using air at 10-14 atm. (1250-200 psi) and
temperatures up to 120°C (250°F). The process is claimed to remove
most of the pyritic sulfur and does not affect organic sulfur. Indi-
cations are that the process could be used in a coal slurry pipeline
application.
145
-------
REFERENCES
Attar. 1979. Personal communication between Dr. Attar of the
University of Houston and C. Vanessa Fong at The MITRE Corp. on
Feb. 5, 1979.
Cleland, J. G. 1976. Chemical coal cleaning, process summaries and
EPA involvement. RTI for IERL/RTP/EPA.
Contos, G. Y. 1978. Assessment of coal cleaning technology: An
evaluation of chemical coal cleaning processes. EPA-600/7-
78-173a.
Datta, R. S. 1976. Feasibility study of pre-combustion coal
cleaning using chemical comminution. Syracuse Research Corp.
Datta, R. S. and Howard, P. U. 1978. Characterization of the
chemical comminution of coal. Syracuse Research Corp.
Dugan, P. R. 1979. Personal communication between Dr. P. R. Dugan at
Ohio State University and C. Vanessa Fong at The MITRE Corp. on
Feb. 12, 1979.
Frankel. 1979a. Trip report of visit to KVB by Irwin Frankel of The
MITRE Corp., on Feb. 8, 1979.
Frankel. 1979b. Trip report of visit to JPL by Dr. Irwin Frankel of
The MITRE Corp. on Feb. 6, 1979.
Friedman, S., 1979. Personal communication between S. Friedman at
DOE Pittsburgh Energy Technology Center, Pittsburgh, Pa., and
Marvin Drabkin on Jan. 24, 1979.
Guth, E. D. 1978. Oxidative coal desulfurization using nitrogen
oxides - The KVB process - for EPA Symposium on Coal Cleaning to
Achieve Energy and Environmental Goals, Hollywood, Florida,
Sept. 11-15, 1978.
Howard, P. 1979. Personal communication between Mr. Philip Howard at
Syracuse Research Corp. and C. Vanessa Fong at The MITRE Corp.
on Jan. 24, 1979.
Kalvinskas, J. J. and Hsu, G. C. 1978. JPL coal desulfurization
process by low temperature chlorinolysis. Presented at U.S. EPA
Symposium for for Coal Cleaning to Achieve Energy and Environmental
Goals, Hollywood, Florida, Sept. 11-15, 1978.
147
-------
Kilgroe, J. D. and Hucko, R. E. 1978. Energy/environment III,
Decision Series. EPA-600-19-78-022.
Kindig, J. K. and Goens, D. H. 1978. The dry removal of pyrite and
ash from coal by the magnex process: coal properties and
process variables. Presented at the EPA Symposium on Coal
Cleaning to Achieve Energy and Environmental Goals, Hollywood,
Florida, Sept. 11-15, 1978.
Kilgroe, James. 1979. Personal communication between James Kilgroe
at EPA/RTP and C. Vanessa Fong at The MITRE Corp. on Jan. 29,
1979.
Markuszewski, R. 1978. Coal desulfurization by leaching with
alkaline solutions containing osygen. Presented at EPA
Symposium on Coal Cleaning to Achieve Energy and Environmental
Goals, Hollywood, Florida. Sept. 11-15, 1978.
Porter, C. R. and Goens, D. N. 1978. Magnex pilot plant evaluation
- A dry chemical process for the removal of pyrite and ash from
coal. Paper presented at SME-AIME fall meeting and exhibit,
Oct. 1977. St. Louis, Missouri.
Stambaugh, E. P. 1978. States of hydrothermal processing for
chemical desulfurization of coal. Presented at EPA Symposium on
Coal Cleaning to Achieve Energy and Environmental Goals,
Hollywood, Florida, Sept. 11-15, 1978.
Stambaugh, E. P. 1976. Study of the Battelle hydrothermal process
U.S. Environmental Protection Agency Draft Report.
Slughter, B. 1979. Personal communication between Bill Slughter at
EPRI and C. Vanessa Fong at The MITRE Corp. on Jan. 29, 1979.
Venugopalan, M. 1979. Personal communication between Dr. M.
Venugopalan of Western Illinois University and C. Vanessa Fong
at The MITRE Corp. on Feb. 14, 1979.
Warnke, W. 1979. Personal communication between W. Warnke at DOE
and M. Drabkin at The MITRE Corp. on Jan. 25, 1979.
Warzinski, R. P. 1978. Survey of coals treated by oxydesulfuri-
zation. Presented at EPA Symposium on Coal Cleaning to Achieve
Environmental and Energy Goals, Hollywood, Florida, Sept. 11-15
1978.
148
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Part 3
Fluidized Bed Combustion
-------
TABLE OF CONTENTS
Page
LIST OF ILLUSTRATIONS 150
LIST OF TABLES 151
SECTION I - TECHNOLOGY DESCRIPTION 153
INTRODUCTION 153
TECHNOLOGY CLASSIFICATION AND STATUS 153
Atmospheric Fluidized Bed Combustion 153
Pressurized FBC Systems 158
Regeneration of Sorbent 162
Current Development Status 162
SECTION II - POLLUTANTS/DISTURBANCES 172
STACK GAS EMISSIONS 174
Overview 174
S02 Emissions 175
Nitrogen Oxides 177
Other Gaseous Pollutants 179
Particulates 182
SOLID WASTES 183
General 183
Spent Sorbent Characterization 185
Spent Sorbent/Ash Land Disposal 186
EMISSIONS FROM LIMESTONE MINING, PROCESSING,
AND TRANSPORTATION OPERATIONS 191
REFERENCES 195
149
-------
LIST OF ILLUSTRATIONS
Figure Number Page
1 AFBC Boiler/Combustor Arrangements 155
2 Atmospheric Fluidized Bed Combustion
System Showing Location of the Carbon
Burnup Cell 157
3 Pressurized Fluidized Bed Combustion
Concepts 159
4 PFB Air Heater System Design 160
5 Exxon Fluidized Bed Combustion Miniplant
with Sorbent Regeneration 163
6 Fluidized Bed Combustion Program Milestones 165
7 Rivesville Test Facility Cell Arrangement
and Coal-Sorbent Handling Systems 166
8 Flow Diagram for the Georgetown University
100,000 Lb/Hr Industrial Boiler 167
9 Coal Distribution System for the
Georgetown University FBC Boiler 168
10 Combined Cycle PFB Pilot Plant at Curtiss
Wright Co., Woodbridge, N. Jersey 17Q
11 Schematic Diagram of Emission Sources
within Atmospheric-Pressure Fluidized Bed
Combustion Plant ^73
12 Projected Desulfurization Performance of
Atmospheric Fluidized Bed Coal Combustor,
Based upon Model Developed by Westinghouse
150
-------
LIST OF TABLES
Table Number Page
1 Sorbent Requirement to Meet SO2 Emission
Standard of 1.2 lb/10^ Btu (520 ng/J) in
Atmospheric Fluidized Bed Combustors 178
2 Analysis of PFBC Flue Gas Inorganic
Constituents 180
3 Analysis of PFBC Flue Gas Organic Compounds 181
4 Inorganic Analysis of Particulate Emissions 184
5 Projected Characteristics of FBC Spent
Sorbent 187
6 Comparison of Chemical Compositions of
Actual Spent Sorbents from Fluidized Bed
Combustion Units with the Projected Values 188
7 Preliminary Indications of Environmental
Impact from the FBC Solid Waste Disposal 190
8 Limestone Sorbent Requirements for an AFBC
to Meet EPA S02 Emission Standard Based on
Pilot Plant Data 192
151
-------
SECTION I - TECHNOLOGY DESCRIPTION
INTRODUCTION
Fluidized bed combustion (FBC) is a process by which a fuel is
burned in a bed of small particles which are suspended or "fluidized"
in a stream of air blown upward from below the bed. It represents
one of the more important emerging coal technologies because it can
burn any kind of fuel and, at the same time, control the emission of
sulfur oxides without the use of a flue gas scrubbing device. Most
of the problems associated with the use of wet scrubbers in flue gas
desulfurization (FGD) could be avoided with an FBC combustor since
the desulfurization takes place in the bed.
FGD is relatively expensive as it typically is an "add-on" tech-
nology. FBC can be incorporated into the design and operations of
combustion systems and removes sulfur at the combustion stage without
the need of add-on devices to trap and remove sulfur from stack gas
emissions.
Other potential advantages include the high heat release rates
and heat transfer rates which can reduce the size of the combustion
unit and thus reduce capital and operating costs. The comparatively
low operating temperature of the FBC makes it characteristically a
low emitter of nitrogen oxides as determined at the pilot plant scale
and potentially a more reliable unit. Performance of a full-scale
FBC unit has yet to be assessed. The low bed temperature also circum-
vents the problem of fireside slagging encountered in conventional
boilers, where the high flame temperatures melt the coal ash, which
is them deposited on the heat transfer surfaces.
The FBC unit is comparatively small in size and can be operated
under pressure for an additional potential advantage, that of improv-
ing the thermal efficiency of the conversion of fuel (coal) to elec-
tricity by expanding the pressurized flue gas through a turbine.
Pressurized fluidized bed combustion (PFBC) shows promise for further
emission reduction. Fluidized bed combustion technology is discussed
in detail in the following sections.
TECHNOLOGY CLASSIFICATION AND STATUS
Atmospheric Fluidized Bed Combustion.
The FBC combustion system which most nearly approximates con-
ventional systems is the atmospheric fluidized bed combustor (AFBC),
so designated because it operates at atmospheric pressure. Such a
153
-------
system is shown in Figure 1. Because of the intense mixing of coal
and air in the fluidized bed, the rate of heat release from the bed
may be an order of magnitude greater than those of conventional
systems which vary from 25,000 to 45,000 Btu/hour per cubic foot of
furnace volume (Johnson 1951). For AFBC units, the heat release rate
may be as high as 1,000,000 Btu/hr/ft3 (Elliott and Virr 1973),
although a practical maximum is in the order of 200,000/Btu/hr/ft3.
Removal of the heat from bed is facilitated by substantially
higher heat transfer coefficients operating in the bed. Overall heat
transfer coefficients of 40 to to 100 Btu/hr/ft2/°F have been
reported in the bed as compared to values of 2 - 10 Btu/hr/ft^°F
for the convection banks of conventional boilers (Johnson et al. 1951
Skinner 1970). Effective combustion can be sustained in the bed at a'
low 1500°F temperature with rapid heat removal within the tempera-
ture range 1500°F-1700°F. The overall effect is a reduction in the
size of the combustion zone by a factor of 15 to 1 over the conven-
tional unit (U.S. Department of Energy 1977a) for the pressurized
units to be discussed.
The heat generated in the bed could be removed by air or some
other working fluid or the flue gases used directly for process heat-
ing. The process configurations for four such uses of the FBC are
also shown in Figure 1. The figure shows schematically the relative
position of the bed, immersed tubes, the convection banks above the
bed, injection of fuel and that of sorbent, limestone, used to con-
tain the sulfur input with the fuel.
Injection of limestone into a fluidized bed in which a sulfur-
containing fuel is burned has been found to be an effective means of
suppressing SO2 emissions. The chemical reaction is the following:
CaC03 + S + 2 °2 CaS04 + co2
2
This reaction takes place in the surface of the limestone particles.
The underlying carbonate is calcined in passing through the system
according to the following equation to form unreacted lime:
CaC03 CaO + C02
Without limestone in the bed virtually all the sulfur in the fuel
would appear as sulfur dioxide (S02) in the flue gas. The quantity
of limestone needed to reduce the S02 emissions by, say 85 percent
would require a stoichiometric ratio carbon-to-sulfur of about 3 0'
(U.S. Department of Energy, 1977b). For a 2.5 percent sulfur coal
this would amount to 468 lbs of limestone per ton of coal. These '
154
-------
A. SATURATED STEAM BOILER
B. SUPERHEATED STEAM GENERATOR
INDIRECT PROCESS HEATER
OFF GAS
D. DIRECT PROCESS HEATER
1
FLUIDIZED BED
ASH DISPOSAL
HOT GASES
*¦ FOR PROCESS
NEEDS
HOT WORKING
FLUID FOR
PROCESS
-FUEL AND
SORBENT INLET
-FLUIDIZING
AIR INLET
ASH DISPOSAL
FUEL AND
SORBENT
INLET
AIR INLET
(FLUIDIZING
AND PROCESS)
SOURCE: U.S. Department of Energy 1977a.
FIGURE 1
AFBC BOILER/COMBUSTOR ARRANGEMENTS
155
-------
results apply to a pilot scale fluidized bed operating in the temper-
ature range of 1500°F -1600°F. Less limestone may be required in the
larger scale units.
This low operating temperature provides a unique advantage in
the combustion of lignites and subbituminous coals which contain a
small fraction of alkaline compounds: carbon oxide (CaO), magnesium
oxide (MgO), sodium oxide (Na2) and potassium oxide (K2O). Tests
have shown that these naturally occurring sorbents can retain much of
the sulfur in the coal at a favorable stoichiometric ratio (Goblir8ch
and Sondreal, 1977). Such sulfur retention would not be as effective
with limestone in the high flame temperatures associated with conven-
tional combustion systems.
The most important impact of the low bed temperature, however
is the cha-racteristically low emission of nitrogen oxides (N0X) as'
compared to conventional systems. Pilot-scale tests have shown NO
emission values of 0.3 lbs/10°Btu as nitrogen dioxide (NO2) com- *
pared to 0.7 to 2.2 lbs/10^ Btu for conventional systems (Mesko
1974).
One characteristic of fluidized bed combustion is the entrain-
ment of small coal particles along with the flyash in the flue gas.
Fine particles in the feed and those formed by decripitation and
partial combustion can blow through the bed before combustion is
complete. This bed loss may be as high as 5 to 10 percent of the
combustible input. This loss of carbon from the bed would be
economically unacceptable and a potential environmental issue.
The proposed solution to the carbon loss problem has been to
collect the flyash blown out of the bed and inject it into a "carbon
burnup cell." This cell is operated at a lower air velocity and at a
higher temperature (no in-bed cooling) to burn up the carbon and thus
make the heat available to the process. The location of the carbon
burnup cell (CBC) in the FBC system is shown in Figure 2. The cell
is also operated at a higher excess air level than the primary cell
to aid the combustion process and to prevent the loss of SO2 by
breakdown of the spent sorbent carried over with the flyash. The
operation of the CBC at the higher temperature (2000°F) tends to in-
crease the concentration of N0X in the flue gas above the cell but
when this stream is combined with the main flue gas stream, the ef-
fect should be small. Recent pilot-scale tests by the Electric Power
Research Institute at Alliance, Ohio, are reported to burn up flyash
carbon by flyash reinjection for 98 percent overall combustion
efficiency (Ehrlich 1979).
156
-------
FINAL DUST
COLLECTOR
SOURCE: U.S. Department of Energy 1977b.
FIGURE2
ATMOSPHERIC FLUIDIZED BED COMBUSTION SYSTEM
SHOWING LOCATION OF THE CARBON BURNUP CELL
157
-------
The addition of limestone or other sorbent such as a dolomite
(MgCOj'CaCOj) for sulfur emission control a.ldn to the flyash
load but most of the limestone is retained in the bed and removed as
bed material when the bed level builds up. Some dolomites are too
friable to be used in the AFBC unit because of the high superficial
gas velocity in the bed (10 to 12 ft per second) but are effective in
the pressurized systems, which operate at a lower velocity.
The AFBC system offers a further potential advantage in that the
flue gas need not be cooled for scrubbing and then reheated for ade-
quate dispersion of flue gas from the stack. The quantity of heat
saved can be as much as 5 percent of the input, and thus represent a
substantial saving on the utility scale.
Technology issues to be resolved before a large demonstration
plant can be built are: (1) the operating characteristics of large
fluidized beds, (2) feeding coal uniformly over the bed with a mini-
mum number of feed points, (3) feeding of coal with over 5 percent
moisture content, (4) design of a low-cost air distributor, (5) car-
bon loss and carbon burn up cell operation, (6) ignition of large
beds, (7) heat transfer from large horizontal and vertical tube con-
figurations, and (8) problems with hot bed material handling (Mesko
1978). The need to improve sorbent utilization is a continuing
problem*
Pressurized FBC Systems.
The pressurized fluidized bed combustion (PFBG) concept involves
combustion of coal in a fluidized bed under a pressure of 6 to 10 at-
mospheres. Because of the greater density of air at these pressures
the combustion unit could be made much smaller than the atmospheric '
unit of equivalent capacity for possibly lower capital and operating
costs. The flue gas generated in the bed at 1700°F could be expanded
in a turbine and theoretically improve the thermal efficiency in the
conversion of heat into electricity. The inlet air pressure could be
provided by a compressor driven by the turbine.
A variety of PFBC systems are possible as shown in Figure 3.
Steam can be generated in tubes in the bed to drive a conventional
steam turbine and the flue gas used to drive a gas turbine for elec-
tricity generation at two points with optimum heat recovery. Heat
may be removed from the bed with air-cooled tubes to drive a gas tur-
bine with very clean air or mixed with the flue gas for greater vol-
ume, as shown in Figure 4. This system provides a partial solution
to a major problem—that of cleaning the particulate matter from the
high-temperature, high-pressure gas stream to the degree necessary to
prevent fouling, corrosion and erosion of the turbine blades. Alter-
natively, the heat may be dissipated with a large excess of air and
158
-------
STEAM TURBINE
STACK
AIR
ASH DISPOSAL
STEAM-COOLED TUBES IN BED
STACK
STEAM TURBINE
STACK
CONDENSOR
AIR
BOILER FEED WATER
WASTE HEAT
BOILER
AIR
ifp P-®
" COMPRESSOR
r9
GAS TURBINE
PARTICULATE
REMOVAL
GAS TURBINE
PRES-
SURIZED
COM-
BUSTOR
ADDITIVE
COAL
FU
PARTICULATE
REMOVAL
ASH DISPOSAL
AIR-COOLED TUBES IN BED
SOURCE: U.S. Department of Energy 1977a.
ASH DISPOSAL
BED COOLED BY EXCESS AIR
(300% NO IN-BED TUBES)
FIGURE 3
PRESSURIZED FLUIDIZED BED COMBUSTION CONCEPTS
-------
1ST
STAGE
CYCLONE
2ND
STAGE
HOT GAS
CLEAN-UP
PFB
COMBUSTION
I
FIN-TUBE
•HEAT EXCHANGER
2/3 FLOW
MIX
SOURCE: Curtiss Wirght Corporation 1977.
FIGURE4
PFB AIR HEATER SYSTEM DESIGN
160
-------
the larger mass flow passed through the turbine to a waste heat boil-
er. Theoretical thermal efficiencies for these systems is estimated
at 40.6, 38.3, and 31.7 percent, respectively (Klett, Szwab, and
Clark 1977).
The PFBC can be operated at the lower gas velocity through the
bed than the AFBC units and reduce the carbon loss problem to manage-
able proportions by ash reinjection but without the use of a carbon
burn up cell. The lower velocity also permits the use of dolomite
sorbents which are too friable for high velocity use. These dolo-
mites under pressure can reduce the SO2 emissions at a comparative-
ly low Ca/S ratio based on the CaCOo content of the dolomite (Hoke
et al. 1977).
The PFBC system has been shown to emit an even lower level of
N0X than the AFBC system due to the effect of pressure and probably
the lower air velocity (0.1 to 0.3 lbs NO2/I06 Btu input) (Hoke,
1975). The following reaction which is postulated to take place in
the bed, would tend to limit NO emissions according to thermodynamic
principles
2N0 + 2 CO —»-2C02 + N2
The lower air velocity and hence a longer equivalent residence time
in the bed would permit a longer time for approach to equilibrium
conversion. The effect of pressure was conclusively demonstrated in
1975 (Mesko 1974).
The major technical issues for the PFBC system is that of clean-
ing the flyash or particulates from the high temperature, high pres-
sure flue gas stream before it is expanded in the gas turbine.
"Granular bed" filters and cyclones are being investigated. Experi-
ence to date indicates the need for substantial improvement in the
technology. The level of particulate concentration needed to protect
turbine blades may prove to be very low. The chemical species of the
particulate matter are also important since some metals, notably the
alkali metals (Na, K), tend to foul and corrode the turbine blades.
An alternative approach to the problem is to develop better turbine
blading to increase operating life with higher particulate loadings.
Additional problems are the feed of coal into a pressure system,
design and testing of alloy materials for fabricating the tube mater-
ials, the scale up of systems to commercial size and the improvement
of sorbent utilization.
161
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Regeneration of Sorbent
The feasibility of regenerating the sorbent has been demonstra-
ted on the pilot scale but not without some problems. Clearly if the
sorbent could be regenerated the quantity of sorbent needed for SO2
emission control could be minimized as well as the problem of spent
sorbent disposal. This would add a process step to recover the
SO2, but its concentration would be relatively high and its recov-
ery established technology.
The spent sorbent, containing CaSC>4 as the sulfur bearing com-
pound, can be regenerated according to these general reactions:
CaSCty + H2 —~ CaO + H2O + SO2, or
CaSC>4 + CO —> CaO + CO2 + SO2
These reactions are carried out in the bed by raising the bed temper-
ature (to 2000°F) and reducing the excess air to effect reducing con-
ditions. This temperature is limited by the tendency of ash to
agglomerate and form "clinkers" which destroy the fluidization of the
bed.
The natural sorbents, limestone and dolomite lose their reactiv-
ity to SO2 after only a few cycles of regeneration and a fresh sor-
bent input is necessary. Nevertheless, one pilot-scale PFBC unit
reduced the sorbent requirement by a factor of four during a five-day
operation with continuous regeneration (Ruth et al. 1978). This
performance was observed at the Exxon "Miniplant" facility shown in
Figure 5. The possibility of developing more reactive and durable
sorbents is under study.
Current Development Status
All of the emission characterization data determined thus far
have been from pilot or bench scale FBC units (1-2 MWe). The large
unit (30 MWe) at Rivesville has not been operating in steady state
for periods long enough to permit an environmental impact evaluation.
Clearly such evaluation is necessary on a large unit to resolve un-
certainties as to the effects of developmental variations and stale
up.
Operation of the Rivesville unit has been hampered by problems
of coal feeding and distribution in the large bed. These problems
have proven to be so difficult that the contractor (Pope Evans and
Robbins) has recommended a separate test facility dedicated to study
of the solids handling problem (Mesko 1978). In August 1978, the
162
-------
SOURCE: Hoke et al. 1977.
FIGURE5
EXXON FLUIDIZED BED COMBUSTION MINIPLANT
WITH SORBENT REGENERATION
163
-------
operation was shut down by a fire in the air preheater section which
caused substantial damage. As of February 1979 the unit vas being
prepared for restart.
An industrial boiler demonstration unit of 100,000 lb/hr steam
capacity is expected to be on stream at Georgetown University in
Washington, D.C. in October 1979. This unit proposes to solve the
coal feed distribution problems by using a conventional means to be
described. With regard to the pressurized unit development, one mod-
ule of a pilot-scale unit is nearing completion at the Curtiss Wright
Co. in Woodbridge New Jersey. No data are available as yet. These
unit8 are listed with others in the Figure 6 milestone chart and are
discussed in more detail in the following sections.
The Fluidized Bed Combustion Program milestones shown in Figure
6 have been modified somewhat since the March 1978 publication. The
Rivesville pilot plant activity has been extended through the first
quarter of FY 1981. The Battelle/Fluidized Combustion 25,000 lb/hr
steam boiler project is to be terminated in the third quarter of FY
1979. The Fluidyne/Owatonna Tool project is eliminated. The com-
ponent test unit at Morgantown, West Virginia, will be under con-
struction until the end of FY 81, and the closed-cycle gas turbine
(TTU) project has been postponed, as has the 200 MWe AFBC demonstra-
tion plant. Design and construction of the anthracite application
equipment is extended to the first quarter of FY 1980 with test
operations to begin at mid FY 1981.
The Rivesville Test facility consists of four cells, three pri-
mary and one carbon burnup cell. Operating parameters are shown in
Table C-l in Appendix C. The coal and limestone feed systems are
shown in Figure 7 with the dust collection and particulate emission
control systems. Particulate emission control is provided with a hot
side precipitator.
The Georgetown University boiler consists of a 100,000 lbs/hour,
625 psi saturated steam unit operated with coal and equipped with a
baghouse as shown in Figure 8. The design and operating parameters
are shown in Table C-2 in Appendix C.
This unit uses the conventional "spreader stoker" to feed and
distribute the coal over the fluidized bed. It differs significantly
from the FBC concept of feeding the coal under the bed to burn up
fine particles as they pass through the bed. It distributes the coal
by slinging it over the bed from a central feed point as shown in
Figure 9. It has proven satisfactory for many years in conventional
packaged boilers.
164
-------
Ln
FISCAL YEAR
1977
1978
1979
1980
1981
1982
ATMOSPHERIC FLUIDIZED-BED COMBUSTION
30MWe
Rivesville, West Virginia
• INDUSTRIAL APPLICATIONS
BOILERS
W»M
!••••
MIM
»•••<
#•••<
*•••
—
BATTELLE/FLUIDIZED COMBUSTION
25,000 *1 b/hr Steam
COMBUSTION ENGINEERING
50,000 lb/hr Steam
GEORGETOWN/FLU IDIZATION COMBUSTION
100,000 lb/hr Steam
HEATERS
EXXON RES. AND ENGINEERING CO.
15 M Btu/hr
FLUIDYNE/OWATONNA TOOL
900° F
• FLUIDIZED-BED ATMOSPHERIC COMBUSTION
COMPONENT TEST UNIT
Merc, Morgantown, W. Va.
• CLOSED-CYCLE GAS TURBINE (TTU)
Oak Ridge, Tenn.
• 200 MWe AFBC DEMONSTRATION PLANT
• ANTHRACITE APPLICATIONS
—
...
»••••
• ••••
• •••<
MM*
—
—
—
—
•••<
«•••
»•••«
»••••
>••••
• •••
MMI
• ••—
• •• •
mmm
PRESSURIZED FLUIDIZED BED COMBUSTION
• COMBINED CYCLE PILOT PLANT
5 T/H
13 MWe
Curtiss Wirght, Wood-Ridge, N.J.
• GRANULAR-BED FILTER/HOT GAS CLEANUP
Design Effort
Combustion Power Company
• INTERNATIONAL ENERGY ADMINISTRATION
PFBC Test Facility
Grimethorpe, U.K.
»•••
MMI
»••••
• •••<
IN*
•••••• DESIGN CONSTRUCTION TEST OPERATIONS
SOURCE: U.S. Department of Energy 1978.
FIGURE6
FLUIDIZED BED COMBUSTION PROGRAM MILESTONES
-------
SOURCE: Stringfellow 1978.
FIGURE 7
RIVESVILLE TEST FACILITY CELL ARRANGEMENT
AND COAL-SORBENT HANDLING SYSTEMS
166
-------
Forced Draft
Fan
ON
©
] Air Blower
Bag
House
Fines to
Waste
SOURCE: Buck 1977.
NOTE:0 Air Supply Fines Recycle System
FIGURE 8
FLOW DIAGRAM FOR THE GEORGETOWN UNIVERSITY
100,000 LB/HR INDUSTRIAL BOILER
-------
Coal
Feeder
Grid Plate
/
* • «»»k.
». . V*' ».-_ -
SOURCE: Buck 1978.
FIGURE 9
COAL DISTRIBUTION SYSTEM FOR THE GEORGETOWN UNIVERSITY
FBC BOILER
168
-------
A smaller industrial fluidized bed boiler (40,000 lbs/hr) has
been sold by the Johnston Boiler Company, Ferrysburg, Michigan, for
the British firm Combustion Systems Ltd. (CSL). This unit has not
yet been built and no design data are available.
The PFBC pilot test facility at the Curtiss Wright Company, de-
signated the SGT/PFB, is an air-cooled FBC unit operated at 6.5 at-
mospheres pressure supplied by an independent source. The systems
configuration of the overall combined cycle plant shown in Figure 10.
The pressure vessel contains nine full-scale, air-cooled tubes with
internal fins for maximum heat transfer. The flue gases are cleaned
in a high-performance cyclone and mixed with the clean hot air to
operate a small gas turbine designed originally for aircraft use.
Operating characteristics are shown in Table C-3 in Appendix C.
Other PFBC studies are underway in England but are not expected
to produce a full-scale unit in the immediate future. A major test
facility to be staged up to 170 MWe is presently under design by the
British Babcock and Wilcox Company and the American Electric Power
Company for installation in Ohio (Smith 1978).
The Environmental Protection Agency has developed a very compre-
hensive and well-designed test procedure to evaluate the environment-
al impact of the Rivesville FBC unit. The tests are to include the
effluents and solid wastes from the unit as well as the air emis-
sions. It is designed to maximize the effort spent in evaluating the
dominant pollutants while at the same time, minimizing the time spent
on the thousands of chemical species which may be present at less
than trace concentrations. This evaluation is expected to be conduc-
ted by and EPA contractor as soon as the unit is in steady operation.
While the impact evaluation of the full scale unit is most
important, there is no reason to suppose that the beneficial aspects
of the concept as determined on the pilot scale will not apply to the
full scale operation. The nitrogen oxides emission may increase with
the larger beds because of local high temperatures. If so, conven-
tional means of N0X reduction such as flue gas recirculation may be
used to restore the orginial low level of emission.
If sulfur oxides emission control should prove to be less effec-
tive in the large units, additional limestone may be necessary unless
current limestone utilization studies can provide a means to offset
it. Either solution may increase the uncontrolled particulate emis-
sion from the units, but application of conventional control tech-
nology (i.e., a baghouse) should prove effective. The lime contained
in the flyash should, in fact, prolong baglife by neutralizing acid
gasses.
169
-------
COAL sum*
n n
-J
o
r-FMMC
\ collector
STACK
SOURCE: Curtiss Wright Co. 1977.
FIGURE 10
COMBINED CYCLE PFB PILOT PLANT AT CURTISS WRIGHT CO.
WOODBRIDGE, N. JERSEY
-------
If the hydrocarbons emissions of the large-scale units are found
to be excessive at the projected operating conditions, an increase
in the excess air rate would probably remedy the condition but not
without some penalty in operating costs. Carbon monoxide emissions
should parallel hydrocarbons. Both could be substantial during upset
conditions where air to the fuel is restricted. Upset conditions
should not occur with a frequency greater than that of conventional
unit if the fully developed unit is to be viable.
The Fluidized-Bed Atmospheric Combustion Component Test and
Integration Unit is expected to provide support studies for the AFBC
development. Its construction at Morgantovm, West Virginia, began in
March 19 79.
Overall, the development of a demonstration AFBC unit in the
utility size (200 MW or greater) is not expected until the mid-1980s
(U.S. Department of Energy 1977c). Clearly, the industrial boiler
development can be expected sooner. On the other hand, the PFBC sys-
tems are not expected to be fully demonstrated before 1990 (U.S.
Department of Energy 1977c), Although regeneration of the sorbent is
stillunder investigation, it is not economically competitive with the
once-through system (Bianco 1978) and hence is not expected to be
employed in the immediate future.
171
-------
SECTION II - POLLUTANTS AND DISTURBANCES
In order to insure that all possible emission sources associa-
ted within the FBC process are being considered, a schematic flow-
sheet of the total process is shown in Figure 11. This flowsheet
represents an AFBC process, adapted from the Rivesville boiler design
[Pope, Evans and Robbins, Inc. (PER), 1974]. Points of environmental
emissions are indicated as dotted ovals on the flowsheet.*
There are six general sources of emissions apparent in Figure
11:
(1) Mining, processing, and transportation of limestone prior
to arrival for use at the FBC plant. Emissions can arise from mining
operations (e.g., dusts created by blasting), crushing and screening
operations which create dusts, transportation operations (e.g., fugi-
tive dusts created by loading crushed limestone into RR cars, trucks
and ships), etc.
(2) Mining, beneficiation, storage, and transportation of coal
prior to use at the AFBC plant. Environmental impacts of these oper-
ations are discussed elsewhere in this report.
(3) Storage and handling of coal and limestone prior to feed-
ing. Emissions can arise from open solids storage piles (e.g. , fugi-
tive emissions of wind-blown dust, leaching due to rainwater) and
from such handling steps as coal drying and crushing (in the Rives-
ville design, efforts have been made to prevent the dust from these
operations from being emitted to the environment).
(4) The steam cycle. Emissions include drift from any cooling
tower, and liquid effluents from boiler blowdown and feedwater treat-
ment.
(5) Stack gas emissions.
(6) Solid waste, in the form of spent limestone bed materi-
al** withdrawn from the combustor, and particulate carry-over
(largely flyash, with some entrained spent sorbent) that is removed
from the flue gas by the particulate control devices. In the specif-
ic case of Figure 11, the material collected by the particulate
*While there are some differences in the distribution and quan-
tities of pollutants to be expected in the various wastes generated
by the AFBC and PFBC processes, the environmental impact of the two
processes appears to be similar so that discussion of pollutants
applies to all FBC processes unless otherwise noted.
**See the Solid Wastes section for details on the composition of
this material.
172
-------
t AIR \
REMISSIONS!
( EFFLUENTS \
'.SOLID MASTE/
V
COAL MINING
BENEFICIATION
STORAGE
TRANSPORTATION
T
u>
/ AIR EMISSIONS \
' EFFLUENTS J
\ SOLID WASTES^/
AIR
V EMISSIONS/'
LIMESTONE
MINING,
PROCESSING,
TRANSPORTATION
l
LIMESTONE
HANDLING
/
J
1
\
\
f \
I LEACHATES }
( A" \
V EMISSIONS /
COAL
COAL
COAL
COAL
STORAGE
DRYER
CRUSHER
BUNKER
" \
LEACHATES ,
V /
SOURCE: Adapted from Henechel 1977.
/" SOLID WASTE
/ (LEACHATES, >
V FUGITIVE EMISSIONS) '
MAKEUP
WATER
FIGURE 11
SCHEMATIC DIAGRAM OF EMISSION SOURCES WITHIN
ATMOSPHERIC-PRESSURE FLUIDIZED BED COMBUSTION PLANT
-------
includes not only carry-over from the corabustor, but also dust vented
from the coal dryer and the limestone separator. SoLid waste may
translate into fugitive emissions and leachate, in the form of wind-
blown dust off disposal piles, rainwater run-off into surface water
systems, and rainwater percolation through the disposal piles into
the soil and ground water#
The emission sources resulting from the solids storage and han-
dling system, and from the steam cycle, are not unique to fluidized
bed combustion, but are reasonably typical of any coal-fired combus-
tion system driving a steam turbine. Accordingly, the emissions from
those two sources will not be covered further in this section but are
discussed elsewhere in this report. Subsequent discussion in this
section will focus on the stack gas and solid waste emission sources
associated with the FBC processes. In addition, a brief discussion
of the emissions associated with limestone mining, processing and
transportation is presented.
Not considered in this report are the effects of thermal pollu-
tion (which are common to all fossil energy systems).
STACK GAS EMISSIONS
Overview
The major impact on air quality resulting from the operation of
all FBC systems can be attributed to the gaseous/particulate products
of combustion released from the stack.
Other air quality impacts may result through the emission of
fugitive particulates and gases from various system locations (as
shown in Figure 11). The potential for fugitive particulate emis-
sions is inherent in all direct combustion systems and primarily
arises from the handling and storage of solid feeds and residues as
well as from operations such as coal and sorbent preparation. This
problem may be of greater significance in FBC systems than in conven-
tional coal combustion systems because of the characteristics and
anticipated dry handling of FBC residues. System leaks and component
"looseness" can represent an additional source of fugitive emissions,
both gaseous and particulate, and is of special concern in pressur-
ized FBC systems. This source should be eliminated, however, through
proper system design and operating practices.
Historically, the gaseous pollutants that received the most
attention in direct combustion processes such as FBC included S0X,
N0X, CO, and gaseous hydrocarbons. These and other potential con-
174
-------
stituents of FBC stack gas are discussed in the following subsec-
tions .
SO-? Emissions
Data available to date suggest that atmospheric fluidized bed
combustors should be able to meet the current NSPS for large coal-
fired steam generators, even with fairly high-sulfur coals, if ade-
quate quantities of sorbent are injected. Thus, the method used
to control SO2 emissions from fluidized bed combustors involves
the use of an appropriate sorbent, usually limestone (predominantly
calcium carbonate), or perhaps dolomite (containing both calcium and
magnesium carbonates).
The fluidized bed combustor would be operated with the sorbent
as the noncombustible bed material. Fresh sorbent would be added
continuously, along with the coal, in order to maintain the capture
activity of the sorbent bed. Spent sorbent would be drained from the
bed as necessary to maintain the bed height.
A typical graph showing projected sulfur removal as a function
of fresh sorbent addition rate to an atmospheric fluidized bed com-
bustor is shown in Figure 12. Figure 12 was generated through use of
a kinetics model developed by Westinghouse, and based upon laboratory
thermogravimetric analysis data. It was confirmed through use of
data from experimental combustors. The sorbent addition rate is
expressed in terms of the moles of calcium in the limestone feed
divided by the moles of sulfur in the coal (Ca/S molar ratio). Sev-
eral curves are shown in the figure. The center curve is for Greer
limestone (Morgantown, W. Va.), a sorbent that is used at Rivesville.
The upper curve for Carbon limestone (Lowe1Isvilie, Ohio), and the
lower curve for Grove limestone (Stephens City, Va.), represent one
of the more reactive limestones tested, and one of the less reactive
limestones, respectively.
Studies have indicated that the effectiveness of a sorbent in
removing SO2 depends upon a number of combustor variables. In
addition to the Ca/S molar ratio, the effectiveness depends heavily
upon gas-residence time in the bed, as determined by gas velocity and
bed depth and upon sorbent particle size. Other significant varia-
bles include sorbent type, as indicated by the curves in Figure 12,
and bed temperature.
Figure 12 was generated by assuming a gas velocity of 6 ft/s,
a bed depth of 4 ft, a sorbent particle size of 420-500 , and a bed
temperature of 1500°F. These conditions are felt to be reasonably
typical of what might be expected in an atmospheric fluidized-bed
combustor designed for cost-effective SO'2 control. Design of a
175
-------
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oo
co
100
90
80
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o
co
o
=3
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cc
I—
70
60
50
o
£ 40
Q-
M
i—i
Z3
00
30
20
10
FLUID BED
OPERATING CONDITIONS:
1 atm (101.3kPa)
420-500 txm LIMESTONE PARTICLES
BED HEIGHT 4FT. (1.2m)
VELOCITY 6 FT/SEC (1.8m/sec)
1500°F (815°C)
-20% EXCESS AIR
CARBON LIMESTONE
GREER LIMESTONE
LIMESTONE 1359
1 2 3 4 5 6 7
Ca/S MOLAR RATIO
SOURCE: Henschel 1977.
FIGURE 12
PROJECTED DESULFURIZATION PERFORMANCE OF ATMOSPHERIC
FLUIDIZED BED COAL COMBUSTOR,
BASED UPON MODEL DEVELOPED BY WESTINGHOUSE
176
-------
combustor for operation at different conditions could, of course,
result in performance different from that indicated in Figure 12.
It is useful to express the information in Figure 12 in terms of
the quantity of sorbent with which a combustor operator will be deal-
ing. Table 1 shows the amount of sorbent required, based upon the
curve for Greer limestone in Figure 12, to meet the current NSPS for
large steam generators, as a function of coal sulfur content. The
table also indicates the quantity of solid residue that will result.
As a final point, it is emphasized that the data which have been
used to develop and verify the model represented by Figure 12, have
been generated on relatively small-scale experimental equipment. The
largest atmospheric fluidized bed boiler that has provided a substan-
tial SO2 control data has been a Department of Energy 500-lb coal/
hr or 5000-lb steam/hr fluidized bed module (FBM) at Alexandria, Va.
Substantial SO2 control data from the Renfrew, Scotland, Rives-
ville, and Alliance units are not yet available.
Although sorbent performance in large boilers is not expected
to differ drastically from the performance that would be predicted
based on the small-scale data and the Westinghouse model, there may
be some features of the larger units that could influence performance
in a manner not apparent from the small-scale results. Reduced wall
effects on the fluidization; different coal distribution patterns
within the bed owing to coal-feeding technique; and the long-term
buildup of fines in the bed, owing to recycle, are several possible
factors that might influence sorbent performance in large units.
Nitrogen Oxides
Emissions of N0X from both atmospheric and pressurized FBC
have been shown to be well below the current EPA standard of 0.6 lb/
MBtu for bituminous coal-fired boilers. Tests on a variety of labor-
atory and pilot-scale AFBC combustors indicate N0X levels generally
in the range of 250 to 450 ppm (i.e., around 0.3 to 0.6 lb/MBtu) at
about 20 percent excess air. Fewer results on N0X emissions have
been reported for PFBC, but available data suggest that emissions
will be approximately half of those in AFBC. As a comparison, modern
pulverized coal boilers operating with low excess air and staged com-
bustion emit 300 to 400 ppm N0X (Abelson 1977).
Any combustion process results in the formation of N0X from
both the combination of nitrogen and oxygen contained in the combus-
tion air (thermal fixation) at elevated temperature and from the oxi-
dation of nitrogen chemically bound in the fuel. The primary factors
determining the quantities of NOx formed are the following: com-
bustion temperature; excess air level; residence time at combustion
177
-------
TABLE 1
SORBENT REQUIREMENT TO MEET SO
EMISSION STANDARD OF
1.2 lb/106 Btu (520 ng/J) IN
ATMOSPHERIC FLUIDIZED BED COMBUSTORS
PERCENT
COAL SULFUR
CONTENT
PERCENT
REQUIRED
RETENTION LEVEL
LIMESTONE FEED
QUANTITY OF
SOLID WASTE
(kg/kg Coal?*
(Ca/S Molar
Ratio*)
(kg sorbent/
kg/Coal)
0.8
0
0
0
0.10
2.0
61
1. 75
0.16
0.24
3.0
74
2.2
0.30
0.37
4.0
80
2.4
0.44
0.49
5.0
84
2.5
0.57
0.60
ASSUMPTIONS: Coal higher heating value 13,000 Btu/lb (7,200 cal/g)
Coal ash content 10%
Sorbent 68% CaCO^ (Greer limestone)
From the curve for Greer limestone in Figure 12.
Coal ash plus spent sorbent.
£
SOURCE: Henschel 1977. The value 1.2 lb/10 Btu is a maximum
emission rate adopted by current (6-79) regulations
for power plants.
178
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temperature; amount and percent conversion of fuel-bound nitrogen;
and unit size (for conventional boilers).
The relatively low temperatures associated with the FBC process
as well as somewhat lower excess air values as compared to conven-
tional coal combustion enable the achievement of very low thermal
N0X emissions. In a fluidized bed boiler, fuel-bound nitrogen
plays the major role in total N0X emissions. The nitrogen level in
coal is fairly constant from one coal to another, normally in the
range of 1.0 to 1.5 percent. The fraction converted to N0X is low,
on the order of 15 percent. The amount of N0X emitted is typically
less than the amount initially formed during combustion. This has
been attributed to a series of destructive reactions, one of which
involves reduction by carbon monoxide, i.e.:
2C0 + 2NO 2C02 + N2
As noted earlier, data indicate that even lower NOx emissions
are achievable in pressurized FBC. A possible explanation of this
effect is the increased collision rate with reducing species that
occurs under pressure, resulting in higher reaction rates for N0X
destruction.
As in the case of SO2 emissions, NOx emission levels need to
be confirmed by obtaining data on large FBC units.
Other Gaseous Pollutants
Emissions of carbon monoxide increase as combustion temperatures
and excess air levels are decreased. Therefore, CO emissions from
FBC systems should exceed those of conventional coal-fired boilers.
Data indicate however that CO levels from FBC systems are generally
low (Abelson 1977).
Gaseous hydrocarbon emissions have been measured only on occa-
sion with respect to FBC systems. Experimental data show typical
values (reported as ppm of methane) on the order of 1000 ppm for AFBC
and 100 ppm for PFBC (Abelson 1977). Clearly these values represent
only a portion of the total organic emissions; of equal importance
are condensed organics. Preliminary measurements of the Exxon mini-
plant PFBC flue gas have yielded the following data on various
combustion gas inorganic constituents (Table 2) and organic constitu-
ents (Table 3). These levels require verification in large FBC
units.
Gaseous hydrocarbons (as well as CO) may be controlled readily
by increasing excess air levels or by the addition of secondary air
in the combustor freeboard zone (i.e., above the bed).
179
-------
TABLE 2
ANALYSIS OF PFBC FLUE GAS
INORGANIC CONSTITUENTS
Subs tances
CO
C02
°2
Concentration
g/m^ (ppm)
61,734(53)
24 x 106
5.5%
H2SO4 Mist +
so2
NH3
CN
F
CI
NOx as N02
so3
2079(5)
74,813(28)
501(0.6)
1.2
10,120(13)
54,824(33)
148,442(70)
As
Be
Cd
Hg
Pb
Sb
Se
Te
<2
<0.4
0.1
0.85
<1.2
<1.7
<1.4
<1.7
SOURCE: Murthy et al. 1978.
180
-------
TABLE 3
ANALYSIS OF PFBC FLUE GAS
ORGANIC COMPOUNDS
Substances
Concentrations
ng/m3
Anthracene/phenanthrene
53
Methyl anthracenes
5
Fluoranthene
26
Pyrene
9
Methylpyrene/fluoranthene
1.0
Benzo(c)phenanthrene
0.2
Chrysene/ben(a)anthracene
3.8
Benzo fluoranthenes
1.0
Benz(a)pyrene
0.5
HC > C6 - C12, g/m3
1740
hc > c12, g/m3
58
Total HC's, g/m3
2196
SOURCE: Murthy et al. 1978.
181
-------
The potential release of trace elements to the atmosphere as
vapors represents another area of concern in processes for the direct
combustion of coal such as virtually all elements below atomic number
92 are contained, in at least trace amounts (< 100 ppm), in coal as
well as in FBC sorbents. Many of these elements will volatilize at
combustion temperatures, and can be released to the atmosphere in the
gaseous phase. Inventory studies on conventional coal-fired plants
have shown that elements such as mercury (Hg), fluorine (F), chlorine
(CI), bromine (Br), and to a lesser extent, arsenic (As) and selenium
(Se), are released in vapor form. Fluidized bed combustion, however
because of its lower temperatures, has the potential for greater re-
tention of the relatively volatile trace elements by reducing their
volatilization compared to combustion in conventional coal-fired
boilers. Also, the presence of sorbent in the bed contributes to
trace element retention by absorption, particularly for the halogens.
Material balance data from an Argonne National Laboratory bench-scale
pressurized combustor indicate retention of mercury, fluorine, bro-
mine, and arsenic in the solid residue (Abelson 1977).
Particulates
Particulate emissions from a fluidized bed combustor under
normal operating conditions may consist of the following: coal ash
unburned coal particles (essentially carbon), and reacted absorbent
(CaSO^, CaSQ^* MgO, and possibly small amounts of CaS03 and CaS).
Particulate emissions occur as a result of elutriation of these
materials from the fluidized bed. Essentially all particles below a
critical size will elutriate from the bed, with this critical value
increasing with increasing superficial velocity. Fines elutriated
from the bed can derive from the coal and sorbent feed streams. Ad-
ditionally, fines can result from decrepitation of the sorbent par-
ticles during calcination and/or sulfation.
The ability of atmospheric fluidized bed combustion systems to
meet the current particulate NSPS for large coal-fired steam genera-
tors (0.1 lb/10** Btu, or 43 ng/J) has not yet been demonstrated.
However, from a practical standpoint, it may be anticipated that con-
trol of particulates from fluidized bed combustors will be similar to
control from conventional boilers burning low-sulfur coal.
The existing, relatively small experimental combustors from
which substantial data have been published have generally operated
only with one or two stages of conventional cyclones to remove parti-
cles from the flue gas. The cyclones are generally not adequate to
achieve the level of control required by the standard; an additional
stage of cleanup is probably required. The large combustion units
which are being designed, and which are now coming on stream, have
182
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been designed to include adequate particulate control equipment.
The data from these large units will demonstrate particulate emission
control capability of atmospheric fluidized combustion systems.
Typically, the flue gas particle loading after the cyclones may
be expected to be in the range of 0.5 to 3.0 lb/10^ Btu (215 to
1300 ng/j), depending upon the number of stages of cyclones and the
cyclone efficiency assumed. Thus the final stage of cleanup would
have to be 80 percent to 97 percent efficient in order to meet the
standard. In the initial design for Rivesville (PER 1974)), the
loading after effectively one cyclone stage was assumed to be 2.5
lb/10^ Btu (1075 ng/J); the estimated particle size distribution,
based upon FBM data, was 50 percent smaller than 7 microns and 90
percent smaller than 25 microns. This size distribution has been
confirmed by other investigators.
The primary alternatives being considered to serve as the final
particle control device are electrostatic precipitators and baghous-
es. The performance of precipitators will be affected by the low
SO2/SO3 levels expected in fluidized bed combustor off-gases.
Following in situ particle resistivity measurements in the fluidized
bed module (FBM), PER has concluded that a precipitator would prob-
ably have to be operated hot—650°F (343°C) or above—in order to
achieve acceptable performance (PER 1974).
Among the final cleanup devices to be tested on large fluidized
bed boilers are a 750°F (399°C) precipitator at Rivesville and bag-
houses on the 100,000 lb steam/hr (45,400 kg/hr) Georgetown Univer-
sity boiler and on the 6 MW Atmospheric Component Test and Integra-
tion Unit being built by DOE at the Morgantown Energy Technology
Center.
Preliminary data are available from the EXXON PFBC mini plant on
the toxic and volatile metal content in the suspended particulate in
FBC flue gas, and are presented in Table 4. It should be noted that
the bulk of this particulate matter would be collected as solid waste
by any effective particulate collection system. Additionally, veri-
fication of the quantities of these pollutants is needed on full-
scale equipment.
SOLID WASTES
General
Solid residues from the FBC process are comprised of spent sorb-
ent (unregenerated or regenerated) and collected particulates from
the combustor flue gas and from the regenerator off-gases (if
183
-------
TABLE 4
INORGANIC ANALYSIS OF PARTICULATE EMISSIONS
Size Range, (jl
Substance
1-3
3-10
Volatile and
Toxic Elements, g/g(fl)
As
45
36
Be
15
11
Cd
<2.1
1.3
Hg
0.02
<0.02
Pb
44
43
Sb
4.0
2.3
Se
27
22
Te
<0.5
<0.5
Major
Elements, g/g
Al
200,000
200,000
Fe
60,000
20,000
Si
200,000
200,000
K
3,000
1,500
Ca
30,000
30,000
C (total
12,000
11,000
carbon)
Anions, weight percent
ci-
0.011
0.007
F"
0.031
0.032
C03=
<0.2
<0.2
so4=
9.4
8 • 7
S03=
0.001
0.004
S"
<0.03
<0.03
NO3"
<0.001
<0.001
no2~
<0.001
<0.001
(^Atomic Absorption Spectroscopy
Method used except for As which
was determined colorimetrically
•
SOURCE: Murthy et
al. 1978.
184
-------
employed). The chemical and physical properties of these residues
differ markedly from those of bottom ash and fly ash from conven-
tional coal-fired boilers. A major difference is the high concen-
trations of calcium and magnesium compounds present in FBC residue
resulting from the use of limestone or dolomite SO2 sorbents.
Solid waste management is of special concern for FBC systems
because of the potentially large quantities of spent sorbent gener-
ated. Preliminary estimates have shown that a 1000 MW FBC plant not
employing sorbent regeneration might be expected to produce about
2000 tons per day of spent sorbent (Abelson 1977).* This is in
addition to the 300,000 tons of ash produced per year from the same
plant burning a 12 percent ash coal. The amounts of solid residues
generated by AFBC and PFBC systems are approximately the same but are
considerably larger than the (dry) quantity produced by a convention-
al coal-fired plant of similar size employing flue gas desulfuriza-
tion (FGD) (Abelson 1977).
Spent Sorbent Characterization
Spent sorbent is a dry particulate solid comprised mainly of
coal ash, calcium sulfate, unreacted calcium oxide and (when dolomite
is used) magnesium oxide. Very minor amounts of calcium sulfite and
calcium sulfide can also be present. Because of the lower tempera-
tures associated with FBC, the spent sorbent particles, which may
range from 1/4 inch down, are less vitrified or glassy than conven-
tional bottom ash. Also, as discussed earlier, trace elements may be
concentrated in the FBC solid residues. Some data, in fact, indicate
that four relatively volatile elements, mercury, arsenic, fluorine,
and bromine, are retained to a greater extent in FBC solid residue
than in conventional coal ash (Abelson 1977). Another property of
spent sorbent which must be addressed in handling and disposal is the
presence of unreacted lime. Minor damage incidents have already been
reported due to the highly exothermic reaction produced when this
material comes in contact with water (Abelson 1977).
FBC spent sorbent also differs considerably from FGD scrubber
sludge associated with conventional coal-fired systems. Sludge from
the lime-limes tone scrubbing process is composed primarily of calcium
sulfite, calcium sulfate, unreacted calcium carbonate, flyash, and
approximately 50 percent water. Owing to the absence of CaS03,
spent sorbent is not expected to show the undesirable thixotropic and
poor compaction properties associated with the scrubber sludge, even
if exposed to water.
*This estimate is based on an assumed Ca/S ratio. Actual spent
sorbent waste generation depends on the percent sulfur in the coal
and the efficiency of sorbent performance.
185
-------
The nominal spent sorbent compositions projected for three basic
fluidized bed combustion concepts are shown in Table 5 (U.S. En-
vironmental Protection Agency 1978a). Table 6 compares the com-
positions of actual spent sorbents with their projected values. The
most significant difference exists in the case of the pressurized,
once-through system where the unsulfated sorbent exists as a mixture
of CaC03 and CaO instead of CaO alone, as projected. The size dis-
tribution of spent sorbent from the bed will be similar to the sorb-
ent feed size distribution.
The spent sorbent fines appearing in the flyash will depend upon
sorbent attrition rate, bed elutriation rate, and fines recycle (if
applied). The coal ash, in general, will all be elutriated from the
combustor. The quantity of sorbent fines is estimated to range from
0.25 to 1 times the coal ash content of th^ flyash for a nominal 10
percent ash coal (U.S. Environmental Protection Agency 1978a).
Spent Sorbent/Ash Land Disposal
Environmental impact criteria have not yet been established for
the land disposal of spent sorbent. Leaching and activity tests were
developed to permit the projection of environmental impact from land
disposal. Criteria for determining the environmental impact of the
residue, as well as standardized leaching tests, may be developed
separately by EPA in the near future under the Resource Conservation
and Recovery Act (PL 94-580).
In the absence of other standards for comparison at the present
time, drinking water standards and leachate from a natural gypsum
were selected as reference standards for the leachate tests.
Leaching and activity tests were performed on atmospheric and
pressurized fluidized bed combustion systems; once-through and regen-
erated spent sorbent; bed and carry-over materials; and processed and
unprocessed spent sorbent.
Leaching and activity tests enable the following tentative con-
clusions to be drawn (U.S. Environmental Protection Agency 1978a):
• No water pollution is expected from the leaching of those
trace-metal ions for which drinking water standards exist,
since the leachate meets drinking water standards.
• An insignificant amount of magnesium is leached out, even
for dolomite sorbent.
• Sulfide may not be a problem for the once-through sorbent,
since the sulfide concentration in the leachate is below
detection limits.
186
-------
TABLE 5
PROJECTED CHARACTERISTICS OF FBC SPENT SORBENT*
Sorbent Spent Sorbent Composition,
Ratio mole % (weight!)
Process Sorbent (Ca/S) CaS04 CaS CaO CaC03 MgO Balance
Atmospheric Pressure
FBC
Once-through
100% load
Limestone
3.48
25
(43.7)
0
(0)
75
(54)
0
(0)
0a
(0)
1.7 3C
(2.3)
Pressurized Boiler
Once-through
Dolomite
1.09
80
(64.1)
0
(0)
20
(6.6)
0
(0)
1.19b
(28.1)
2.11c
(1.2)
Adiabatic Combustor
Once-trhough
100% load
Dolomite
1.74
50
(46.7)
0
(0)
50
(19.2)
0
(0)
1.19b
(32.7)
2.11c
(1.4)
Pressurized Boiler
Once-through
100% Load
Limestone
2.18
40
(60.6
0
(0)
60
(37.4)
0
(0)
0a
(0)
1.73c
(2)
Atmospheric FBC
One-step regenera-
tion 100% load
Limestone
0.75/0.81
24d/12.8®
(43.1/26.1)
0d/1.2e
(0/1.3)
76d/86®
(54.6/70.1)
0
(0)
oa
(0)
1.73C
(2.3/;
Pressurized Boiler
Once-through
turndown to
minimum load
Dolomite
1.45
60
(47.6)
0
(0)
0
(0)
40
(23.4)
1.19b
(27.8)
2. llc
(1.2)
SOURCE: U.S. Environmental Protection Agency
*Plant Design Parameters:
Plant Size: 600 MWe
Coal: 4.3% Sulfur
Sulfur Removed Efficiency (%)
Power Plant: 82.6
Once-Through Combustion: 87
aMgO included with balance of components
''moles MgO/mole Ca
cgrams per mole calcium
^spent sorbent from combustor
espent sorbent from regenerator
-------
TABLE 6
COMPARISON OF CHEMICAL COMPOSITIONS OF ACTUAL SPENT SORBENTS FROM
FLUIDIZED BED COMBUSTION UNITS WITH THE PROJECTED VALUES*
Actual Spent Sorbent Projected Composition
(Molar Fraction Ca-Based) (Molar Fraction Ca-Based)
Process Conditions CaSO, CaO CaCO„ CaS CaSO, CaO CaCO„ CaS
4 3 4 3
Atmospheric Pressure,**
Limestone Sorbent, 0.44 0.54 0.02 <0.003 0.25 0.75 0 0
Once-through
Pressurized,
oo Limestone sorbent, 0.11-0.35 0-0.18 0.60-0.73 <0.003 0.40 0.60 0 0
00 Once-through
Pressurized,
Dolomite Sorbent, 0.47-0.71 0-0.23 0.15-0.42 <0.003 0.80 0.20 0 0
Once—through
Pressurized,
Dolomite Sorbent, 0.16 0.82 0.02 <0.003 0.34 0.61 0 0.05
Regenerative
*Table B-l, Appendix presents details of process conditions for samples studied. Table II-5 presents data on the
basis for projected values.
The only sample available is an unidentified PER sorbent with unknown history and a typical sulfation level.
SOURCE: U.S. Environmental Protection Agency 1978a.
-------
• The total dissolved organics are below detection limits.
• Residual activity, reflected by heat release upon exposure
to water, has not been observed to be significant with spent
sorbent from once-through pressurized operation. The heat
release property of spent sorbent, however, is a function
of the FBC operating conditions—for example, temperature,
stone residence time, degree of sulfation and calcination,
and degree of dead-burning.
• Heat release from the spent sorbent in the atmospheric FBC
system is judged an environmental concern for direct dispo-
sal. This is due to the large amount of calcium oxide pre-
sent in the spent sorbent. It is small, however, compared to
the heat rejected by the Power Plant condenser.
• Moderate heat release has occurred with the spent sorbent
from the regenerative pressurized FBC system. This, also,
may be an environmental concern.
• Potential concerns in the leachates are the high concentra-
tions of calcium, sulfate (SO4), pH, and total dissolved
solids (TDS), which are above drinking water standards.
• The addition of 20 wt % ash to the spent sorbent improves
leachate quality. Codisposal of spent sorbent and ash, thus,
can reduce the adverse environmental impact.
• The environmental impact is reduced by room temperature pro-
cessing.
A preliminary comparison of environmental impacts of the various
FBC processes is shown in Table 7.
Further testing on the solid residues from large-scale units is
necessary before firm conclusions can be drawn regarding the environ-
mental impact of disposal of solid residue from fluidized bed combus-
tors.
In addition to potential impacts on surface and groundwater
quality posed by leaching from disposed FBC solid residues, other
impacts may also be created. For example, because of the large quan-
tities of solid residues produced, large land areas will be required
for disposal and transportation and handling requirements for waste
products will be increased. Methods of disposal and waste processing
that minimize the potential for ground and surface water contamina-
tion and that minimize the extent of land disrupted will have to be
developed or improved. These may range from stabilization of resi-
dues prior to burial (e.g., to reduce permeability and reactivity)
189
-------
TABLE 7
PRELIMINARY INDICATIONS OF ENVIRONMENTAL IMPACT
FROM THE FBC SOLID WASTE DISPOSAL
SAMPLE
PROCESS
SORBENT TYPE
ENVIRONMENTAL PARAMETERS
HEAT RELEASE*-
SPONTANEOUS TEMP. RISE
(3g/20 ml)
TRACE
METAL
TOTAL
DISSOLVED
SOLIDS
TOTAL
ORGANIC
CARBON
pH CALCIUM SULFATE
SULFIDE
Bed Material
Pressurized FBC,
once-through
Limestone
<0.2°C
Bed Material
Pressurized FBC,
once-through
Dolomite
<0.2°C
WM
Bed Material
Pressurized FBC,
regenerative
Dolomite
To Be Determined
Mm
To Be
Determined
Bed Material
Atmospheric FBC,
once-through
Limestone
To Be Determined
Flyash
Pressurized FBC,
once-through
Limestone
<0.2°C
s/s//
vy/V/
1
Mixture of Bed
Material and
Flyash
(Unprocessed)
Pressurized FBC,
once-through
Dolomite/Limestone
<0.2°C
ill
Processed
Compacts from
Bed Material/
Flyash
Mixtures
Pressurized FBC,
once-through
Dolomite/Limestone
<0.2°C
1PP
Gypsum
Natural
<0.2°C
1
l
Based on results from limited samples available and subject to the procedures specified in the section on "Activity."
Q Do not meet either the drinking water or gypsum leachate criteria.
n Pass gypsum leachate criteria but not drinking water standards.
n Pass both drinking water and gypsum leachate criteria.
SOURCE: U.S. Environmental Protection Agency 1978a.
-------
to the use of lined landfills where leachate is collected and subse-
quently treated.
In order to reduce the magnitude of this disposal problem and
also to reduce the quantities of fresh limestone or dolomite that
must be supplied to the process, regeneration and reuse of spent sor-
bent would be highly desirable. An additional benefit would be that
the sulfur captured by the sorbent might be recovered in marketable
form (e.g., sulfuric acid). Such regeneration processes are current-
ly under development and have been demonstrated on the bench-scale
and sub-pilot-scale levels. However, there are significant technical
problems still to be resolved and an assessment of the secondary en-
vironmental impacts of regeneration must still be made.
Several possible uses for spent sorbent are being investigated
as alternatives to disposal by landfill. Among these are: use as an
agricultural fertilizer and soil conditioner; use as a gypsum substi-
tute in the manufacture of wallboard and other products; and, use as
a filler material in the manufacture of cement and cinder blocks and
for roadbed construction. Again, the environmental impacts associ-
ated with each utilization option must be evaluated.
EMISSIONS FROM LIMESTONE MINING, PROCESSING,AND TRANSPORTATION
OPERATIONS
Based on the data for Greer limestone shown in Table 1, the
limestone requirement in an AFBC operation has been calculated based
on the present utility boiler NSPS of 1.2 lb SO2/MM Btu, for vary-
ing coal sulfur contents. This data is shown in Table 8, for a power
plant consuming 8000 TPD of a 12,000 Btu/lb coal (equivalent to a
1000 MWe FBC plant).
Assuming an average of 3 percent sulfur in the feed coal, a 1000
MWe plant annual limestone requirement would be approximately 600,000
TPY (based on once-through limestone usage with no regeneration).
This represents less than 0.1 percent of the total annual pro-
duction of crushed and broken limestone and dolomite produced in the
U.S. for industrial use in 1977 (706,521,000 tons in 1977) (Gunn
1978). One hundred, 1000 MWe FBC units would still consume less than
10 percent of the present annual U.S. limestone production, so that
the projected environmental impact of increased limestone usage with
the advent of FBC would be expected to be quite small.
Limestone used in FBC operations is ground and screened to about
-6 to -8 mesh. This operation can either be carried out at the lime-
stone mining and preparation facility or at the FBC facility. If the
191
-------
TABLE 8
LIMESTONE SORBENT REQUIREMENTS FOR AN AFBC
TO MEET EPA S02 EMISSION STANDARD BASED ON PILOT PLANT DATA*
Sulfur Content in Coal, % 1 2 3 4 5
Limestone Required to Meet
1.2 lb/mm Btu, TPD 124 900 1948 3000 4120
Ca/S ratio from Table 1 based on Greer limestone.
**Limestone is 100% CaC03. The value 1.2 lb/106 Btu is the maximum
SO_ emission rate allowed by current {June 1979) U.S. Environmental
Protection Agency regulations for power plants.
192
-------
grinding and screening were not suitabley enclosed, some fugitive dust
could be expected from these operations. Fugitive dust emissions
from uncontrolled limestone grinding and screening operations are
estimated at about 5 to 6 lb/ton (U.S. Environmental Protection Agency
1978b).
Two FBC operational factors not considered in the above discus-
sion may be the requirement to use only certain grades of limestone
and dolomite which are highly reactive (as is presently indicated in
the lab and pilot scale tests) with respect to FBC chemistry, and are
not contaminated or encapsulated with considerable amounts of silica
(requiring the use of much greater amounts of limestone per pound of
sulfur in the coal). The first factor could have an appreciable
environmental impact on a number of local limestone mining and pro-
cessing situations (where appreciable expansion of capacity would
be needed) and the second factor could require the use of a much
greater percentage of limestone production capacity for FBC than is
presently anticipated. Further studies in these areas are needed.
193
-------
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of fluidized bed combustion—background data for the ERDA direct
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Bianco, J.H. 1978. An engineering study of the regeneration of sui-
ted additives from a fluidized bed coal tried power plan, Burns and
Roc Industrial Services Corporation Paramus, New Jersey.
Buck, V. 1978. Industrial application, fluidized bed combustion,
Georgetown University, Proceedings of the 5th International Confer-
ence on Fluidized Bed Combustion December 12, 1977, McLean, VA:
The MITRE Corporation.
Curtiss Wright Corporation. 1977. Presentation on PFB Pilot Plant to
ERDA, July 197 7.
Ehrlich, Shelton. 1979. Electric Power Research Institute, Palo
Alto, CA, personal communication.
Elliott, D.E. and Virr, M.J. Small scale applications of fluidized
bed combustion and heat transfer. In Proceedings of the Third
International Conference on Fluidized Bed Combustion EPA 650/2-73-
053.
Goblirsch, Gerald M. and Sondreal, E.A. 1977. Effects of operating
parameters on the sulfur retention of alkaline ash during fluidized
bed combustion of North Dakota lignite, Proceedings of the
Fluidized Bed Combustion Technology Exchange Workshop, Vol. II,
CONF-770447-P-2, U.S. ERDA 1977.
Henschel, D. Bruce. 1977. Environmental emissions from coal-fired
industrial fluidized bed boilers, IERL, OEMI, ORD, U.S. En-
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presented at Conference on Engineering Fluidized-Bed Combustion
Systems for Industrial Use, Columbus, Ohio.
Henschel, D. Bruce. 1978. Emissions from FBC boilers, Environmental
Science and Technology. 12:534-538.
Gunn, B. 1978. Personal communication. U.S. Bureau of Mines,
Washington, D.C.
Hoke, R.C. 1975. Emissions from pressurized fluidized bed coal
Combustion, Exxon R&E Company. Proceedings of the 4th Inter-
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Hoke, R.C. ; Bertrand, R.R.; Nutkis, M.S.; Kinzler, D.D.; and Ruth,
L.A. 1977. Studies of the pressurized fluidized-bed coal com-
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Johnson, Allen J. and Auth, George H. 1951. Fuel and combustion
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Klett, M.G; Szwab, W.; and Clark, J.P. 1977. Particulate control for
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Mesko, J.E., 1974. Multicell fluidized bed boiler design, construc-
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Mesko, J.E. 1978. Technological development priorities of
atmospheric fluidized bed combustion, Pope Evans and Robbins, Inc.
In Proceedings of the 5th International Conference on Fluidized Bed
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Murthy, K.S; Allen, J.M.; Sharp, D.A.; and Duke, K.M. 1978. Multi-
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Skinner, D.G. 1970. The fluidized combustion of coal, a review of
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Stringfellow, T. and Branam, J.G. 1978. Startup and initial opera-
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U.S. Department of Energy. 1977a. Direct Combustion Research and
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197
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Part 4
Magnetohydrodynamics
-------
TABLE OF CONTENTS
Page
LIST OF ILLUSTRATIONS 200
LIST OF TABLES 201
SECTION I - TECHNOLOGY DESCRIPTION 203
INTRODUCTION 203
OPEN-CYCLE MAGNETOHYDRODYNAMICS 2Q3
Process Chemistry 206
Technology Status 207
Commercialization Barriers 210
CLOSED-CYCLE MHD 210
SECTION II - POLLUTANTS AND DISTURBANCES 214
SOURCES OF EMISSIONS 214
Introduction 214
State of Knowledge 218
NATURE OF POLLUTANTS 222
Introduction 222
Air 222
Water 231
Solid Waste 232
REFERENCES 233
199
-------
LIST OF ILLUSTRATIONS
Figure Number page
1 Conceptual Plant Arrangement 204
2 Open-Cycle Coal-Fired MHD System 205
3 Closed-Cycle Plasma MHD 211
4 Closed-Cycle Liquid Metal MHD 212
5 Effluent Streams for a Typical MHD
Power Plant 215
6 Tomlinson/Tampella Seed Regeneration
Process 220
7 Kinetic History of Nitric Oxide in
Coal-Burning Central Station MHD
Power Plant (Case of 3000°F) 225
8 Kinetic History of Nitric Oxide in
Coal-Burning Central Station MHD
Power Plant (Case of 2000°F) 226
9 NOx Concentrations as a Function of
Residence Time for .85 Stoichiometric Ratio 227
10 Measured and Predicted N0X Emissions
in Experimental MHD Facilities 228
200
-------
LIST OF TABLES
Table Number
Page
1
Evaluation of Seed Recovery Processes
208
2
Potential Environmental Problems with
MHD Components - CDIF
216
3
Potential Environmental Problems with
MHD Components - ETF
217
4
Comparative Emission Factors for Coal-
Burning Power Plants
224
5
Comparison of Slag and Flyash from
Conventional Boiler and MHD Systems
(Eastern Coal)
230
201
-------
SECTION I - TECHNOLOGY DESCRIPTION
INTRODUCTION
Magnetohydrodynamics (MHD) generates electricity directly from
thermal energy without the step of conversion from heat to mechanical
energy as encountered in conventional steam electric generation. An
electrically conducting gas is forced through a duct at high speed in
the presence of a magnetic field, thereby inducing a voltage drop
across the gas stream.
MHD programs exist in this country and abroad, with the major
distinction that the U.S. emphasizes the use of coal as primary fuel
while foreign programs, such as Poland and U.S.S.R., emphasize natur-
al gas and fuel oils in addition to coal.
It is expected that the MHD power-generating plants would be
significantly more efficient and environmentally acceptable than
any other process. The MHD plant efficiency is expected to be about
50 percent, compared to 33 to 40 percent for conventional fossil-
fueled plants. A conceptual arrangement of an MHD plant is shown in
Figure 1.
There are three types of MHD systems: open cycle, closed-cycle
plasma, and closed-cycle liquid metal.
OPEN-CYCLE MAGNETOHYDRODYNAMICS
The Open-Cycle Magnetohydrodynamics (OCMHD) converts heat energy
of coal to electricity directly without the need for flue gas desul-
furization, and its successful development can lead to substantial
increases in overall plant efficiency. However, to obtain the high
overall plant efficiency, OCMHD must be used as a topping cycle to
another heat conversion system because of the relatively low enthalpy
extraction of MHD generators. At present, conventional steam bot-
toming is proposed.
The MHD power plant consists of two distinct subsystems, the MHD
topping section and the steam bottoming section. As shown in Figure
2, pulverized coal is burned in the combustor with a fuel-to-air
ratio of 1:1. The fuel-rich combustion minimizes the probability of
nitrogen oxides formation. However, to obtain the high operating
temperature (4800°F), for proper operation, the combustion air must
be preheated to about 2500°F. Alternately, air enriched to various
oxygen levels could be used with modest levels of preheating, up to
1100°F, using any coal. A large portion of the slag (85 percent) is
tapped out of the combustor. The remaining portion is transmitted
203
-------
WHC jEXERATQB —
Vit'.M lOV
p-jlv£=:ze^ :a»; «ji£
BOIllft SCRtCH
•**»«*« MALL CONST. 1 ? • 10
TJW GAS APPKO»
VfLOC 1T1 f ROM
3KKT 50' per Set S'-
?900° 38' per/set 1)0 -
2000° ?8' p<"-/s« SO' -
TO TW S'STEK
iwwsfcmp
SUBSTATION
IHVtfiURS
SLAG SCRtES
^ ¦
\
SOURCE:
Dicks 1978.
FIGURE 1
CONCEPTUAL PLANT ARRANGEMENT
-------
N>
o
Ul
SOURCE: Fossil Energy Research Program of the
Energy Research and Development Administration,
FY 1978, ERDA 77-33, 1977.
AC POWER
AC POWER
COOLING
STEAM
TURBINE
GENERATOR
INVERTER
CONDENSER
STACK
i steah i
2300K
2800K
IB 2000K
MAGNET
SLAG
SEPARATOR
AND
RADIANT
BOILER
HIGH
TEMPERATURE
AIR
PREHEATER
STEAM
SUPERHEAT
AND
REHEAT
LOW
TEMPERATURE
Ai R
PREHEATER
LIQUID
SEED
CONDENSER
SOLID
SEED
EXTRACTOR
COMBUSTOR
ECONOMIZER
MHD CHANNEL
DIFFUSER
MAGNET
SEED I.
[RECYCLE
COMPRESSED
AIR
1650K
SEED
REGENERATION
COAUStAG
AIR/GAS
SEED SYSTEM
ELECTRICAL
WATER/STEAM
SULFUR
AND
PARTICULATES
FIGURE2
OPEN-CYCLE COAL-FIRED MHD SYSTEM
-------
through the system with the combustion products. Although the tem-
perature at the exit of the combustor and entrance to the MHD section
is relatively high (>4800°F), the gas is still not sufficiently
ionized. A seed must be introduced at this point to enhance its
conductivity. The seed proposed is potassium carbonate (K2CO3).
Approximately 1 percent, by weight, of seed in the gas is required to
achieve the proper plasma conductivity.
The seeded gas and remaining slag enter the MHD channel, where
the gas is expanded from approximately 8-to-10 atmospheres at the in-
let to little more than 1 atmosphere at the outlet. The MHD chan-
nel is rectangular in cross section. A magnetic field from a magnet
(superconducting) enters and exits from two opposite sides, and the
other two sides are equipped with electrodes to collect the current
generated from the interaction of the moving conducting gas and the
magnetic field. This d.c. current is inverted to a.c. and fed into
the power grid. The seed performs another interesting function: it
combines with the sulfur in the coal to produce potassium sulfate,
thus preventing the formation of oxides of sulfur (S0X).
The combustion gases that are still at high temperature (4000°F)
then enter the air preheater where additional slag is removed. It
should be noted, however, that there is still uncertainty on how to
build such an air preheater. Also, early commercial plants might not
have a directly fired high-temperature air preheater. Following the
air preheater is a standard steam generating plant (3600 psi/1000°F/
1000°F). Instead of using a steam generating plant, the thinking in
current research is to provide steam pressure of about 2400 psi in
order to use the cooling water from the combustor, generator and
diffuser. Additional air is introduced in a low-temperature air
preheater to burn the remaining fuel. Following this is the steam
economizer, a precipitator, and the stack. The seed is recovered as
solids after the steam superheater and as a solid dust in the
precipitator which precedes the stack. Because of the relatively
high cost of the seed, it is recovered for reuse and for certain
processes; pure sulfur is a product of this operation (Farah and
Harlow 1976).
Process Chemistry
Prior to burning, coal is dried and crushed before being fed to
the combustor. The water-cooled combustor operating with preheated
air produces combustion gas products at temperatures in excess of
4600°F. The coal is seeded with potassium carbonate (K2CO3),
alone or mixed with potasium sulfate (K2SO4), to achieve adequate
levels of electrical conductivity in the combustion products. The
mixture is burned in the combustion chamber with oxygen-enriched air.
The K2CO3 added as a seed will react with SO2 formed from the
206
-------
sulfur in the coal, eliminating the need for expensive sulfur-removal
systems. Following recovery of K2SO4, a process iB required to
regenerate K2CO3 and produce a sulfur product that can be
disposed of. There are several recovery processes, however none is
established as best suited for MHD. Seven potential processes have
been evaluated. Table 1 summarizes the advantages, disadvantages,
and commercial status of these potential recovery techniques.
Technology Status
The principal difficulties of the OCMHD technology arise from
the fact that the working fluid must have a sufficiently high conduc-
tivity to allow efficient operation. To obtain sufficient ionization
in the working fluid, the temperature must be high; however, even
stoichiometric temperatures are not sufficient to result in a high-
conductivity plasma, and seed must be added. This creates the prin-
cipal obstacle to commercialization: the high temperature requires
materials that must withstand it. The fact that there are no moving
parts in the generator portion of the MHD system relieves some of the
requirements on the materials, but the fact that the system must
operate in a utility grid for long periods with only regular main-
tenance intervals requires that the materials have long life under
the erosive and corrosive action of the working fluid and seed/slag
mixture. The presence of the seed/slag mixture in the steam plant
further complicates the design of the superheater and boiler in this
plant. In the MHD channel, where electrodes are imbedded in the
walls and electrically isolated from each other by ceramic insula-
tion, the requirement is for 2,000 to 5,000 hours of electrode life
as well as for long-life insulators and seals between the two. Be-
sides addressing the problems of materials and seed recovery, there
is a need for efficient and economic methods for designing and con-
structing large high-field superconducting magnets.
To date, experimental MHD generators have been built and the
most important accomplishments are:
• 100 hours of continuous operation at a relatively low 100 kW
power range with moderate slag carryover and improved recov-
ery of seed and slag from the gas stream
• 550 hours in channel test at V.S. (AVCO) with continuous
periods of 250, 150, and 150 hours
• 250 hours in the MW power range with a clean fuel—this was
accomplished on the USSR's U-25 generator (power placed in
the Moscow grid)
• one-half hour without slag at 20.4 MWe on the U-25
207
-------
TABLE 1
EVALUATION OF SEED RECOVERY PROCESSES
PROCESS
TECHNICAL EVALUATION
COMMERCIAL STATUS
Pro
Con
Engle-Precht
No thermal
reduction
Lose one mole MgSO^
for each mole K2SO4
High potassium loss
0s40%) . Potential
water pollution
problems.
Commercial process
in Germany
Double
Alkali
No thermal
reduction
Dilute solutions.
Large evaporative
load, 50x10^ lb
H20/hr for 1000
MWe.
Commercial process
for conventional
power plants but
modifications
necessary for MHD
Formate
Simple
process
using
common
materials
Ca(OH)2
CO utilization
unknown. May
require coal
gasifier. CO2
must be
removed.
Commercial process
in Germany, 1930s
PERC
Dry con-
version
Low CO and CO2
utilization.
Pilot plant
experiments
Aqueous
Carbonate
Oper-
ations
demon-
strated
Non-commerc ial
equipment.
Design based on
sodium not
potassium.
New type equipment
being developed by
Atomics Inter-
national, EPA,
Empire State
Electric Energy
Research Corp.
Tomlinson-
Tampella
Com-
mercial
process
Design based on
sodium not
potassium.
Commercial
Direct
Reduction
One step
process.
Dry Op-
eration.
Material
handling
Minimized.
Not developed.
Not developed
SOURCE: Matty et al. 1979.
208
-------
• one minute at 32 MWe on the U-25, also without slag
• 400-hour test on materials for direct-fired preheater appli-
cation with temperatures above 3000°F
In summary, the major accomplishments in the MHD program in-
lude:
• successful completion of 20MWt, 500-hour endurance tests
under electrode loading conditions simulating commercial
service and achieving order-of-magnitude improvement in elec-
trode corrosion/erosion resistance
• successful subsonic generator operation at a high-magnetic
field (5 tesla), representing the largest (30 MWt) high-
field test ever run
• slag rejection in excess of 95 percent with carbon conversion
of 97 percent achieved in a first-stage prototype of a two-
stage combustor
• achievement of 95 percent sulfur removal from high-sulfur
coal as well as N0X reduction to 20 ppm
• 1,000 hours of cumulative testing at 2700°F on a direct-fired
regenerative air preheater element under heat transfer, flui-
dynamic, and seed/slag conditions simulating MHD service
• design principles confirmed ,for large super-conducting
magnets by operation of a 40-ton, 5-tesla magnet at design
conditions
From an energy production standpoint, the enthalpy extraction of
present experimental facilities has been somewhat less than predict-
ed but within the acceptable range for the unit size. This has been
attributed to the small scale of the experiments where wall losses
are excessive. It is expected that at utility-plant scale (1,000
MW), the needed high enthalpy extraction will be achieved.
Major anticipated accomplishments for FY 1980 include:
• completion of facility activation at the Component Development
and Integration Facility in Montana (CDIF)
• testing operation at the Coal-Fired Flow Facility (CFFF) at the
University of Tennessee Space Institute
209
-------
• channel testing at the Soviet U-25 facility with the U.S.
channel to be delivered in late FY 1979
• testing in the High Performance Demonstration Experiment
(HPDE) at the Arnold Engineering Development Center (AEDC)
(U.S. Department of Energy 1979)
Commercialization Barriers
In addition to the technical barriers mentioned above, there are
some major nontechnical barriers that must be overcome before MHD be-
comes commercialized. These arise because MHD plants are a radically
new technology and that they may need to be in 1,000 MWe range for
economical, efficient operation.
To citizen groups, large plants mean large land areas, hence
large environmental intrusion. The MHD plant will require water, a
transportation system for the coal, electrical substations, etc. In
addition, the utilities will be asked to depend on the operation of
new concept plants for a large portion of their power.
CLOSED-CYCLE MHD
The closed-cycle MHD processes being investigated are the
closed-cycle plasma and the closed-cycle liquid metal. The basic en-
ergy conversion process of these processes is the same as that of the
open cycle, namely, motional electromagnetic induction. However, the
closed-cycle processes use a working fluid in a closed-loop system
and receive the heat energy indirectly from a primary source through
a heat exchanger. The primary heat source can be obtained from com-
bustion of coal or other fossil fuels, or from a nuclear reactor if a
suitable one is available. Because of closed cycling of working
fluid, there is more latitude available in selecting a working fluid
and in obtaining electron densities to give sufficient conductivity,
resulting in lower required temperatures than for open-cycle MHD.
The closed-cycle plasma process uses noble gas (e.g. argon) as a
working fluid. The noble gas is seeded with easily ionized material
such as cesium. The closed-cycle plasma process is shown in Figure
3.
The closed-cycle liquid metal process is very similar to the
closed-cycle plasma MHD, except that a gas liquid metal bath is used
as a working fluid instead of the noble gas. Because liquid metal
systems have high electrical conductivities compared to total gas
systems, lower temperatures and magnetic fields are possible. This
could result in smaller plant and higher extraction efficiencies.
Figure 4 shows the closed-cycle liquid metal process.
210
-------
FIGURE 3
CLOSED-CYCLE PLASMA MHD
-------
FIGURE 4
CLOSED-CYCLE LIQUID METAL MHO
-------
Presently, the goal is to continue performing feasibility
studies of the generator, heat exchanger, and materials in these
processes. Their development not as advanced as the open-cycle MHD
pending resolution of basic issues that present Btudies are
addressing.
213
-------
SECTION II - POLLUTANTS AND DISTURBANCES
MHD processes are expected to generate pollutants similar to
those of other direct combustion processes. However, because of ex-
pected higher overall efficiencies of MHD power plants, less coal is
required per unit of electricity generated. Therefore, pollutants
and their environmental impacts are expected to be less then those of
conventional coal-fired plants. The following discusses the sources
of the emissions and nature of pollutants associated with MHD tech-
nology.
SOURCES OF EMISSIONS
Introduction
Pollution from coal-fired MHD plants ranges from problems
similar to direct coal combustion such as dust emissions to such
ill-defined problems as fugitive gaseous emissions from equipment
leaks and pump seals, which may require special control systems.
Magnetism and heat from MHD technology could cause physiological and
safety problems to humans, especially within the plant area.
The effluent streams for a typical MHD plant, identifying the
potential emissions for the various process steps of the technology,
are presented in Figure 5. It must be emphasized that the stream
characterization is not complete and available information may not be
representative of commercial applications. All present data on MHD
pollutants are based on theoretical models and experimental results
from small facilities. In addition, the nature and amount of wastes
will vary depending on the type of coal and seed used, operational
design of plant, size of operation, and seed regeneration process.
To gain confidence in the ability to predict emissions from actual
commercial power plants, a development program is now in place which
is structured to progressively increase the size of the test com-
ponents and compare the test results with analytical models. A 20
MWe heat seed recovery (HRSR) test train will be tested at the Uni-
versity of Tennessee Space Institute, followed by a 250 MWe com-
ponent testing at the engineerihng test facility. Besides NOx,
S0X, and particulate emissions, the MHD flow train will be instru-
mental in studying emissions of carcinogenic and chemically toxic
substances. Tables 2 and 3 list the potential environmental problems
to be examined for the various activities of the component develop-
ment and integration facility (CDIF) project and the engineering test
facility (ETF) subscale prototype plant.
Wastes from coal storage, handling, crushing, and classification
processes can be handled using available techniques for controlling
dust emissions, disposal of mineral wastes, and handling run-off
214
-------
FUGITIVE
RUNOFF DUST
hO
SOURCE: U.S. Department of Energy 1978.
FIGURE 5
EFFLUENT STREAMS FOR A TYPICAL MHD POWER PLANT
-------
TABLE 2
POTENTIAL ENVIRONMENTAL PROBLEMS
WITH MHD COMPONENTS—CDIF
ACTIVITY OR
COMPONENT
POTENTIAL ENVIRONMENTAL PROBLEMS
TO BE EXAMINED
Coal handling,
preparation
and storage
Dust, particulate matter, noise, water vapor
due to coal drying
Seed handling
and preparation
Particulate matter, noise, fugitive dust
Compressors,
coal and seed
feed systems
Noise, vibrations, particulate matter, ex-
plosion hazard
Metallic heater
(low temperature
preheater)
Noise, exhaust of combustion gases (CO2, CO,
H2O, S02, etc.)
Vitiated heater
(high temperature
preheater)
Noise, N0X, CO2, CO, H2O, sulfur products,
combustion products in main air supply, heat
Combustor (oil)
Noise, N0X, C02, CO, H2O, seed volatilization,
sulfur products in main air supply, heat,
explosion hazard
Combustor (coal)
Noise, N0X, C02, CO, H2O, slag, sulfur
products, trace elements in gases, seed
volatilization, particulate matter, hydro-
carbons, explosion hazard
MHD Channel
Noise, products of erosion of electrodes and
walls, molten slag and molten seed
Magnet-
Effect on humans, safety problems
Exhaust gas
cooling and
clean up
systems
Exhaust gases, high water vapor, particulate
matter, liquid and solid waste removal, trace
elements, N0X, if quick quench is used,
scrubber sludge
Cooling towers
Cooling, water use, water vapor
Settling ponds
Water vapor, land use, disposal of solid waste
SOURCE: U.S. Department of Energy 1978.
216
-------
TABLE 3
POTENTIAL ENVIRONMENTAL PROBLEMS
WITH MHD COMPONENTS—ETF
ACTIVITY OR
COMPONENT
POTENTIAL ENVIRONMENTAL PROBLEMS
TO BE EXAMINED
Coal handling,
preparation and
storage
Seed handling
and preparation
Compressors, coal
and seed feed
systems
The same as in CDIF, except the components
are larger in size and capacity
High temperature
preheater
N0X, slag
Combustor
MHD Channel
Magnet
The same as in CDIF, except the components
are larger in size and capacity
Radiant boiler(s)
and slagk separator
N0X, slag deposition, seed material, slag
removal
Liquid seed
condenser
Seed separation and removal
Steam superheat
and reheat
Low temperature
air preheater
Economizers
Standard steam plant components, erosion and
corrosion due to seed material and fly ash
Solid seed
extractor
Seed separation and extraction
Seed regeneration
Disposal of sulfur and particulates, evapor-
ating ponds, water vapor
Scrubbers and
precipitators
Solid waste disposal
Cooling Towers
Cooling water use, water vapor
SOURCE: U.S. Department of Energy 1978.
217
-------
water from storage piles. The control of air emissions, solid waste,
and magnetic fields may present more difficult problems. In fact,
because of the very high operating temperatures unique to MHD, new or
improved control techniques may need to be developed. (U.S. Depart-
ment of Energy 1978).
Among the potential sources of pollutions are: the MHD combus-
tor, MHD channel, seed handling, and exhaust gas cooling and clean-up
systems. The effluents of particular importance to MHD operations
are the N0X emissions formed at high combustion temperatures in the
vitiated heater and the coal combustor. In addition, the alkali seed
added to enhance the electrical conductivity of the gas could result
in production of wastes if recovery is incomplete or inadequate.
It should be noted that the MHD process utilizing source seed
material such as the potassium carbonate provides a built-in method
of controlling sulfur dioxide emissions. This results in acceptable
SO2 emissions. Other pollutants which may be contained in the
effluent streams include sulfur products, carbon monoxide, carbon di-
oxide, trace elements, wastewaters, thermal effluents, seed volatili-
zation products, particulate matter (debris, fines, ash), organics,
and radioactive compounds (U.S. Department of Energy 1978).
Noise pollution and emissions from erosion of electrodes and
walls are other important pollutants pertinent to MHD systems. The
noise sources are the compressors, coal and seed feed systems,
heaters, MHD combustor, and MHD channel. The source of electrodes
and wall erosion emissions is the MHD channel.
State of Knowledge
Environmental control technology related to MHD processes is
only at the experimental stage (only for the open-cycle MHD process
on which development and experimentation are being performed). Be-
cause of the unique components of MHD and the very high operating
temperatures, new or improved techniques may be needed for monitor-
ing, evaluating, and controlling effluents of MHD systems. In order
to operate an MHD plant economically, development of highly efficient
equipment for recovering a major portion of the seed is necessary.
The kind of equipment will depend on the type and cost of the coal
and feed seed (the feed seed is a feature of MHD, distinct from
conventional coal combustion systems). For commercial operations,
new techniques have to be developed.
Experimental work to date indicates that seed and particulate
matter in the gas could be removed with very high efficiency by
conventional electrostatic precipitators, bag filters, or scrubbers.
Furthermore, it has been verified experimentally that because the
218
-------
alkali seed has high chemical affinity to sulfur, sulfur is removed
from the gas together with the seed (Bienstock et al. 1973).
Collection and separation of seed have been studied extensively at
the University of Tennessee Space Institute (UTSI) and the Pittsburgh
Energy Technology Center. A recent assessment of seven possible seed
recovery techniques was performed by the UTSI. The advantages and
disadvantages of these techniques are summarized in Table 1. The
analysis indicates that some techniques are more advanced than others
(Matty et al. 1979). Some have been used in the U.S. in the pulp and
paper industry and in Germany in the formate process of potash. The
following is a summary of the UTSI evaluation.
"As requested by DOE, The University of Tennessee embarked on
a technical study to evaluate a number of regenerative systems which
could be considered for further development as seed regeneration con-
cepts for the MHD system. As reported to DOE, the most technically
advanced system at this time is a system which has been in commercial
operation in the pulp and paper industry for many years. This system
is known as the Tomlinson-Tampella Process. This identification has
been made by UTSI personnel since the system combines a Tomlinson re-
ducing furnace, commonly used in the Kraft pulping process and a com-
mercial chemical conversion system—the Tampella Process.
"In this process (Figure 6) the spent seed (potassium sulfate)
is mixed with coal and burned under reducing conditions (approxi-
mately 65% air) in a Tomlinson recovery furnace. In this furnace the
following reaction takes place:
The molten mixture of potassium sulfide, potassium carbonate, and
potassium sulfate (smelt) flows from the bottom of the furnace into a
dissolving tank where the smelt is quenched and dissolved in water to
form "green liquor." Subsequently, in a clarifier, ash introduced
from the coal used in the reduction furnace is removed. The green
liquor is then contacted with flue gas in a precarbonation step where
the following reaction takes place:
"The precarbonated liquor flows to a H2S stripper column and
is mixed with bicarbonate (KHCO3) solution. The liquor in the
stripper is heated in a reboiler to facilitate H2S removal and
crystallization as shown by the following reaction:
I^SO^ + 4C0 —~ K2S + 4C02
2K2S + C02 + H20 —*-
2KHS + K2C03
khco3 + KHS + h2o —~
k2co3*h2o + h2s
219
-------
COAL SEED
TOMLINSON
RECOVERY
FURNACE
h2s
STRIPPER
PRECARBONATOR CARBONATOR / h2S TO CLAUS
fO
ro
° DISSOLVING
TANK
TAMPELLA PROCESS
SOURCE: Dicks 1978b„
FIGURE 6
TOMLINSON/TAMPELLA SEED REGENERATION PROCESS
-------
"The H2S-steam mixture is cooled to condense and remove the
water. The H2S gas then passes to a Claus reactor where it is con-
verted to elemental sulfur.
"The K2CO3.H2O crystals from the above reaction are separ-
ated from the mother liquor, dried and reused in the MHD system. The
mother liquor flows to the carbonation tower where it is contacted
with flue gas to form KHCO3 as shown by the following reaction:
k2co3 + co2 + h2o —2KHC03 "
In addition the study states that:
"In view of significant experience with sodium sulfate/sodium
carbonate in the pulp and paper industry, it is expected that elec-
trostatic precipitator efficiencies in the order of 99.5 percent will
be achieved for potassium sulfate removal. Of course, this must be
further confirmed during operation of the total system and a precipi-
tator will be located in the 8 lb/sec flow train in the UTSI facility
(Dicks et al. 1978)
Basically two routes available for control of N0X emissions
(Hals 1978). One route is to minimize N0X in the gas so that it is
acceptable for direct emission to the air. The second is to maximize
N0X in the gas so that recovery of fixed nitrogen becomes economi-
cally attractive. Most of the work has been performed on the first
route. The UTSI developed an economically attractive solution for
minimizing N0X formations (Strom 1978). Test results indicate
that N0„ emissions should be effectively controlled below NSPS
levels (U.S. Department of Energy 1978). In addition, UTSI work
indicates that low stoichiometrics carbon which in conventional
direct combustion would be high is not present. This absence of char
is attributed to high temperatures of MHD combustion. It should be
noted that instead of char, CO is formed (Dicks et al. 1978).
As far as efficient removal of fine particulate matter, develop-
ment of control technologies may be needed. Improvements of conven-
tional techniques (electrostatic precipitators, wet scrubbers fabric
filters) and new techniques for control of particulate matter are in
various stages of R&D (U.S. Environmental Protection Agency 1977;
1978a).
Conventional control techniques such as flaring should be effec-
tive in controlling organic compounds present in gas emissions. Sim-
ilarly, conventional control technologies are expected to adequately
control water effluents, thermal discharges, run-off, and leachate
from solid waste disposal areas. This needs to be tested and veri-
fied at advanced MHD facilities.
221
-------
Finally, monitoring, evaluation, and control of magnetic fields
effects need to be analyzed. These magnetic fields are much higher
than those that have adverse effects on biological systems (U.S.
Department of Energy, 1978). The effects of these high-strength
magnetic fields on the health and safety of plant workers and the sur
rounding environment is a debatable issue requiring more investiga-
tion. Several techniques are available for controlling these fields
in the plant area by using methods such as shielding and exclusion
areas during operation.
NATURE OF POLLUTANTS
Introduction
The goal of MHD is to directly convert coal thermal energy into
electricity, thus increasing power plant efficiencies to about 50 per-
cent from the 33 to 40 percent of conventional plants. Because of the
higher overall plant efficiencies, it is expected that the level of
MHD effluents will be much lower than those of conventional direct
combustion producing the same amount of electric power. However, it
should be noted that consideration should be given to the higher
emissions of nitrogen oxides (N0X) resulting from high combustion
temperatures.
It should be noted that available data are not sufficient to
verify MHD effluent levels because currently there are no operating
coal-fired MHD systems except the experimental work at the University
of Tennessee Space Institute. Although knowledge of wastes and emis-
sions for MHD is sketchy, it is known that wastes will be generated
during each main process stage. Many of these wastes are largely con-
trollable or convertible to environmentally acceptable forms.
The following sections describe the potential pollutants by
major categories: air, water, and solids. They also summarize the
state of knowledge pertinent to experimentation with open-cycle MHD
systems.
Air
Fugitive emissions are difficult to assess because there is no
experience operating MHD plants of commercial size. These emissions
may result from sources such as valve stems, flanges, loading racks
equipment leaks, or pump seals. Fugitive emissions present potential
health and safety hazards and must be evaluated through the MHD tech-
nology development and demonstration phases.
222
-------
The primary concerns with MHD air emissions are the stack emis-
sions, especially the N0X concentrations, which are higher than the
o.nes of conventional combustors. These high N0X levels are a result
of intrinsic MHD high operating temperatures. Conversely, the S0X
concentrations are likely to be much lower than those of conventional
coal-fired power plants because of the MHD inherent process feature of
seed additives which remove sulfur from the working fluid (U.S. De-
partment of Energy 1978). The following paragraphs discuss the stack
air emissions of N0X, S0X, particulate matter, trace elements, and
other effluents.
If pulverized coal is burned in the MHD combustor with fuel-to-
air ratios (larger than unity), the probability of nitrogen oxides for
formation is minimized. However, if operated at less than unity
fuel-to-air ratios, MHD could produce up to 10 times the N0X levels
produced by conventional coal combustion (Strom 1978; Bienstock
1971; Shaw 1978). These high N0X concentrations would be unac-
ceptable from an environmental point of view because of their direct
effect on animals and plants. Allowable emissions of N0X are 0.7
lb. per million Btu of heat input or about 400 to 500 ppmv* de-
pending on the type of coal. Predictions of N0X emissions have
ranged from about 50 to more than 400 ppmv because of differences in
assumptions and estimation techniques (Strom 1978; Shaw 1978)
Several studies indicate that minimization of nitrogen oxides tech-
niques could reduce the level of N0X in the stack gas to about 25
percent of the EPA allowable NOx levels (Table 4). The N0X re-
duction throughout the power plant using solely a two-stage combustion
for NOx control is described for the case of 3000°F and 2000°F air
preheat with fuel-air ratio of 1.1 in Figure 7 and Figure 8 (Hals
1975). Similarly, other studies and experimentation have supported
the above findings regarding N0X emissions levels and formation
(Dicks 1978). The most recent work at the University of Tennessee
Space Institute indicates that by reducing the stoichiometric ratio of
air to fuel from 95 percent to 85 percent, the residence time to
minimize N0X emissions decreases from 3 or more seconds to less than
1.5 seconds (Figures 9 and 10) (Epstein 1978). This reduced level is
acceptable to present-day commercial designs (Dicks et al. 1978).
Additional experimentation and further research and development on
N0X reduction techniques are of prime importance especially if more
stringent N0X standards are established by EPA (N0X Review 1978).
It should be noted that these standards could be met by using the
preferred system operation consisting of operating, the combustor with
rich fuel, cooling the gas slowly in a radiant boiler, and adding ad-
ditional downstream air to complete combustion (Epstein 1978).
*PPMV ¦ Parts per million by volume.
223
-------
TABLE 4
COMPARATIVE EMISSION FACTORS FOR COAL-BURNING POWER PLANTS
(BASIS FOR COMPARISON COAL CONTAINING 31
SULFUR BURNED WITH AIR)
POLLUTANT
EXISTING
STEAM^1)
MHD
EPA
STANDARD
S02 (lbs/106 Btu)
4.587
0.045 - 0.018^
1.2
N0x (lbs/N02/106 Btu)
0.81
0.19 - 0.065^
0.70
c.
Particulates (lbs/10 Btu)
1.054
0.10 - 0.01(4)
0.20
^Emission factor from Public Health Service Publication
No. 999-AP-42.
^Based on experimental demonstration at U.S. Bureau of Mines
and Avco Everett Research Laboratory, Inc.
^Based on experimental demonstration at U.S. Bureau of Mines,
Avco*Everett Research Laboratory, Inc., and in Japan. (Later
experiments at UTSI are also consistent with the capability
to reduce NO .)
x
^Based on experimental demonstration at Avco Everett Research
Laboratory, Inc., in U.S.S.R., and England.
SOURCE: Hals 1975.
224
-------
MHD-STEAM POWER PLANT WITH TWO STAGE COMBUSTION
FOR DIRECT REDUCTION AND CONTROL OF NITROGEN OXIDES
basis: combustion of coal with air PREHEATED TO 3000°F
SOURCE: Hals 1975.
FIGURE 7
KINETIC HISTORY OF NITRIC OXIDE IN COAL-BURNING CENTRAL
STATION MHO POWER PLANT (CASE OF 3000*F)
225
-------
MHD STEAM POWER PLANT WITH TWO STAGE COMBUSTION
FOR DIRECT REDUCTION AND CONTROL OF NITROGEN OXIDES
BASIS: COMBUSTION OF COAL WITH AIR PREHEATED TO 2000°F
I
SOURCE: Hals 1975.
FIQUREB
KINETIC HISTORY OF NITRIC OXIDE IN COAL-BURNING CENTRAL
STATION AND MHD POWER PLANT (CASE OF 2000°F)
226
-------
700
0-
0-
Z
o
<
cc.
o
o
X
o
z
600
500
400
—A
300
200
100
PRESENT EPA
STANDARD
25 METERS
(dia) I"
INLET CONDITIONS:
TEMPERATURE - 2250K
PRESSURE - 1 ATM
N0X CONCENTRATION
- EQUILIBRIUM
WALL CONDITIONS:
EMISSIVITY -1.0
TEMPERATURE - 1500K
PROPOSED EPA
STANDARD
16 METERS (DIA)
11 METERS (DIA)
(.15 lb/106)
jC
1 2
RESIDENCE TIME IN RADIANT BOILER (SECONDS)
SOURCE: Templemeyer 1978.
FIGURE9
NOx CONCENTRATIONS AS A FUNCTION OF RESIDENCE TIME
FOR .85 STOICHIOMETRIC RATIO
227
-------
3000
-
G
r«ii
2500
-
O UTS I DATA
• PERC DATA
2000
-
\©
ANL PREDICTIONS
——— 2m BOILER
ANL PREDICTIONS
10m BOILER
1500
•
1000
MHD RANGE
•
PRESENT EPA STANDARD
©\
i
\
\\o
500
CALIFORNIA PROPOSED
STANDARD
' '
\ v\
\ \C^v
X *J.
i
PiO
1,2 1.1 1.0 0.9 0.8 0.7
RATIO OF OXIDANT TO THEORETICAL OXIDANT
SOURCE: Templemeyer 1978.
FIGURE 10
MEASURED AND PREDICTED NOx EMISSIONS IN EXPERIMENTAL MHD
FACILITIES
228
-------
The MHD process utilizing potassium carbonate as a seed additive,
provides a built-in method of controlling sulfur dioxide emissions.
Potassium seed material added at the combustor results in the forma-
tion of liquid or solid potassium sulfate in the fuel gases, which may
be later removed in downstream components. This is a very efficient
reaction, resulting in significant reductions of the SO2 emissions
(Templemeyer 1978). Experimental results indicate that SO2 removal
efficiencies resulting from seeding can exceed 99 percent for coal
containing 2.2 weight percent sulfur (Bienstock et al. 1973).
Furthermore, comparative experiments indicate that SO2 emissions
could be reduced to much lower levels than EPA standards using coal
containing 3 percent sulfur burned with air (Table 4). In the pulp
and paper industry, sodium carbonate has been shown to react effec-
tively with SO2 emissions to form sodium sulfate, reducing the
levels of SC>2 emitted to the atmosphere. Recent experiments at UTS1
indicate that the potassium sulfate has been forming by providing ap-
propriate temperature and time for reaction, and that MHD will meet
the S0X emissions standards (Matty et al. 1978; Dicks et al. 1978).
However, because experimentation and evaluation of seed regeneration
techniques are continuing and because more development and testing are
needed, the status of SO2 emissions still warrents extensive data
collection and analyses to determine the MHD ability to meet EPA
standards (U.S. DOE 1978). The necessity to monitor SO2 stack
emissions and testing will increase if more stringent New Source
Performance Standards are established (U.S. EPA 1978b).
The primary particulate matter in the MHD exhaust gases are ex-
pected to be flyash with some unrecovered seed additives. Flyash
emissions are expected to contain larger proportions of fine particles
(3 microns) than the ones of conventional coal-fired power plants,
thus presenting more health hazards if not controlled. However, it
should be noted that the MHD total flyash emissions are expected to be
much lower than the ones of conventional plants because the major
fraction is removed as liquid slag from the system (U.S. DOE, 1978;
Schmidt 1976J Nader 1978).
Table 5 compares some typical measured compositions in conven-
tional boiler and MHD systems. It indicates that: "The aluminum and
silicon will be selectively rejected at the combustor exit and that
MHD-system flyash has a different composition from that of convention-
al plants. In particular, it will be rich in potassium sulfate..."
(Templemeyer 1978)." The table also shows that the presence of a
magnetic field appears to result in the formation of a larger number
of fine particulates. It should be noted that at the present time,
those are neither ambient air nor emission standards for sulfates.
The ambient standards are under discussion; however, they do not seem
to pose a problem for MHD plants (Rowe 1978). As far as the possible
particulate from unrecovered seed additives, it has been demonstrated
229
-------
TABLE 5
Comparison of Slag and Flyash from Conventional Boiler
and MHD Systems (Eastern Coal)
Conventional Coal-Fired
Compound Boiler MHD Coal-Fired System
Flyash
Combustor Slag
Flyash
Si02
39.80
40.42
23.56
AI2O3
21.20
27.01
14.00
Fe2°3
24.70
10.41
9.81
CaO
4.55
2.60
1.50
Na20
0.28
0.70
0.78
C
-
0
5.91
CuO
-
0.06
0.23
K2SO4
-
3.05
8.23
k2o
2.25
0.05
-
MgO
1.04
5.0
3.0
TiO
1.24
1.0
0.8
P205
0.31
0.4
0.4
Moisture
-
0.1
0.5
SO4
0.72
0
0.60
SOURCE: Tempelmever 1978.
230
-------
on a commercial scale that sodium sulfate particulate is readily and
efficiently removed from flue gases leaving Kraft-type recovery units
(Dicks et al. 1978). It is expected that similar removal efficiencies
will be achieved with MHD.
Impacts of trace elements emitted from MHD plants depend on type
of coal, method of combustion, plant size, weather conditions, and
emission control technologies (U.S. DOE 1978). Most of the trace
elements are expected to be retained; flyash and slag will be removed
by control devices; such as with cold-side electrostatic precipita-
tor. It is claimed that more than 99 percent of fine flyash could be
controlled (Ondov 1979). However, there is concern that signifi-
cant quantities of trace elements, particles, or volatized matter,
will still be emitted into the atmosphere (U.S. DOE 1978). The trace
elements that may be of concern include mercury, arsenic, zinc, bar-
ium, cadmium, vanadium, and selenium. Technology research, develop-
ment, and evaluation are necessary to assure that most trace element
emissions of MHD are effectively controlled (Matray 1976),
Emissions or organic compounds and carbon monoxide from MHD
plants are expected to be insignificant (U.S. DOE 1978). Recent ex-
perimental results at the UTSI indicate that flue gas contains no de-
volatilized char, which usually occurs at high levels in conventional
combustion. Only carbon monoxide was formed during these tests (Dicks
et al 1978). Monitoring for carbon nonoxide and heavy molecular
weight hydrocarbons is being undertaken at MHD test facilities to
determine their levels and the need for control (U.S. DOE 1978).
As with other coal-fired technologies, radioactive emissions from
MHD plants will depend on the radioactive content of coal and the ef-
ficiency of emissions control systems. However, MHD should, result in
a lower level of radioactive emissions per unit of energy output be-
cause its thermal efficiency is higher than that of conventional
coal-fired technologies (U.S. DOE 1978).
Water
As in conventional power plants, water is mainly used in MHD
power plants for cooling purposes. It is expected that MHD will
require less water than conventional systems because of its higher
thermal efficiency. Furthermore, water is used for the wet scrubber
system for particulate control and associated solid waste disposal at
the CDIF. At advanced MHD facilities, water will be used to extract
potassium sulfate from flyash/spent seed residue collected by control
equipment and in the spent seed recovery. During the seed extraction
and regeneration, there is a potential for leaching of trace matter
contained in the seed and flyash mixture (U.S. DOE 1978). It should
be noted that when the MHD generator is combined with a gas turbine
bottoming plant, there is no need for water to condense steam.
231
-------
The principal sources of water pollution are from boiler clean-
ing, cooling systems, and feed water treatment processes. These are
similar to those of conventional boilers. In addition, run-off and
leaching solid waste disposal sites could result in water pollution if
control measures are inadequate. At present, there is no data on the
leachability of trace elements and compounds contained in the slag and
flyash (U.S. DOE 1978).
Solid Waste
The solid waste from MHD plants will be unique as it will contain
potassium compounds (K2 SO^, K2 CO3, and/or KOH) resulting
from seedings; the slag collected from the combustor and other process
components will have different properties, and the flyash collected in
the emission-control devices will mainly have fine particles (Fisher,
1978). The trace elements adhering to fine particle surfaces may be
more toxic to biological systems as a result of leaching and fugitive
dust emissions (Dreesen 1977; Theis 1977).
As previously mentioned, no seed regeneration process has yet
been established; thus the final solid waste impacts from MHD plants
are still uncertain subject to further extensive development and eval-
uation (Matty, et al. 1979). For the MHD development work of the
component development and integration facility in Montana, spent seed
will be collected in the quench water and deposited in evaporation
ponds with no regeneration or recycling. The pilot-scale engineering
test facility and the commercial demonstration plant will present
different solid waste disposal and storage problems because dry col-
lection systems will be used.
232
-------
REFERENCES
Bienstock D. 1971. Environmental aspects of MHD power generation.
The 1971 Intersociety Energy Conversion Engineering Conference,
Boston, Massachusetts.
Bienstock, D.; Bergman, P. D.; Henry, J. M.; Demeter, J. J.; and
Plants, K. D. 1973. Air pollution aspects of MHD power genera-
tions. In 13th Symposium on Engineering Aspects of MHD, Stanford
Univers ity.
Dicks, J. B., Jr. 1978. Development program for MHD direct coal-
fired power generation test activity, annual report 1977, The
University of Tennessee Space Institute.
Dicks, J. B.; Strom, S. S.; Markant, H. P.; Probert, P. B. 1978.
Coal-fired MHD power generation including balance of plant. Univer-
sity of Tennessee Space Institute.
Dreesen, D. R. 1977. Comparison of levels of trace elements extrac-
ted from fly ash and levels found in effluent waters from a coal-
fired power plant. Environmental Science and Technology 11(10).
Epstein, J. 1978. Control of nitrogen-oxide emissions in coal-fired,
OCMHD power plants. U.S. DOE Environmental Control Symposium,
Washington, D.C., November 1978.
Farah, 0. G., Harlow, M. 1976. EDP for magnetohydrodynamics power
systems. The MITRE Corporation, WP 12985, 1976.
Feldman, H. F. 1970, Markant, H. P.; Attig, R. C. 1979. "Kinetics of
recovering sulfur from spent seed in an MHD power plant." Env. Sc.
and Techn., vol. 4. No. 6.
Fisher, G. L. 1978. Physical and morphological studies of size-
classified coal fly ash. Environmental Science and Technology
12(4).
Hals, F. A. 1969. MHD power generation economic and environmental
implications. In Proceedings of 10th Symposium on Engineering
Aspects of MHD, MIT.
Hals, F. A. 1975. Conservation and environmental implications of
open cycle MHD. AVCO Everett Research Laboratory, Inc., Everett,
Massachusetts.
233
-------
Jackson, W.D. 1976. MHD Electrical Power Generation; Prospects and
Issues, AIAA Paper No. 76-309, AIAA 9th Fluid and Plasma Dynamics
Conference, San Diego, CA, July 14-16, 1976.
Matray, P. 1976. The bioenvironmental impact of trace element emis-
sions from a magnetohydrodynamics (MHD) facility: a literature
review and recommendations. Montana Energy and MHD Research and
Development Institute In-House Document 3F:76N9.
Matty, R. E.; Strom, S. S.; Materi, G. E. 1979. Evaluation of alter-
native seed regeneration processes applicable to a coal-fired MHD
power plant. The University of Tennessee Space Institute.
Nader, J. S. 1978. Field measurements and characterization of emis-
sions from coal-fired combustion sources. 71st APCA Annual Meeting,
Houston, Texas.
N0X Review. NSPS for utility boilers considered. NOx Control
Review, Spring, p. 5.
Ondov, J. 1979. Elemental emissions from a coal-fired power plant:
comparison of a Venturi well-scrubber system with a cold-side elec-
trostatic precipitator. Environmental Science and Technology 3, No.
5.
Rowe, M. 1978*. Potential ambient standards for atmospheric sulfates.
Journal of the Air Pollution Control Ass. 28, p. 772.
Schmidt, E. W. 1976. Size distribution of fine particulate emissions
from a coal-fired power plant. Atmospheric Environment.
Shaw, H. 1978. Environmental assessment of advanced energy conver-
sion technologies. Government Research and Engineering Co., New
Jersey.
Strom S. S. 1978. Controlling N0X from a coal-fired MHD process.
In 13th Intersociety Energy Conversion Engineering Conference, San
Diego, California.
Tempelmeyer, K. E. 1978. Control of sulfur dioxide and particulate
emissions in MHD power systems using high sulfur coal. U.S. DOE
Environmental Control Symposium, Washington, D.C., November 1978.
Tetra Tech Inc. 1977. Energy fact book 1977. Tetra Tech Inc.,
Arlington, Virginia.
Theis, T. L. 1977. Sorptive behavioral of trace metals on fly ash in
aqueous systems. Environmental Science and Technology 11(12).
234
-------
U.S. Department of Energy. 1978. Environmental development plan mag-
netohydrodynamics program FY-77.
U. S. Department of Energy. 1979. Fossil energy program summary
document, DOE/ET-0087.
U. S. Environmental Protection Agency. 1977. EPA/DOE Symposium on
High Temperature High Pressure Particulate Control. Washington,
D.C.
U. S. Environmental Protection Agency, IERL/EPA. 1978a. First
International Symposium on Transfer and Utilization of Particulate
Control Technology. Denver, Colorado.
U. S. Environmental Protection Agency. 1978b. Environmental Protec-
tion Agency regulatory agenda. Federal Register, Vol 43(67).
235
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Part 5
Coal-Oil Mixtures
-------
TABLE OF CONTENTS
Page
LIST OF ILLUSTRATIONS 238
LIST OF TABLES 238
SECTION I - TECHNOLOGY DESCRIPTION 239
INTRODUCTION 239
PROCESS SEQUENCE 241
TECHNOLOGY STATUS 245
SECTION II - POLLUTANTS/DISTURBANCES 248
SOURCES OF EMISSIONS 248
Introduction 248
State of Knowledge 248
Potential Emission Sources 251
Physical Disturbances 253
NATURE OF POLLUTANTS 253
Introduction 253
Air 253
Water 254
Solids 254
Transient Pollutants 255
Emissions from On-Going COM Testing
Program 256
Interlake 256
REFERENCES 261
237
-------
LIST OF ILLUSTRATIONS
Figure Number Page
1 Conceptual Diagram of COM Preparation
and Combustion 240
2 NEPSCo's COM Preparation Plant 243
3 Coal-Oil Mixture Overall Plan Schedule 247
4 Potential Emission Sources and Fates
from COM Technology 249
LIST OF TABLES
Table Number Page
1 COM Technology Projects 242
2 COM Processes 244
238
-------
SECTION I - TECHNOLOGY DESCRIPTION
INTRODUCTION
The coal-oil mixture (COM) concept, first proposed in 1879, is
a developing technology designed to conserve scarce oil and gas sup-
plies by replacing up to 50 percent of fuel oil with pulverized coal
and burning it in units formerly using oil alone or gas.
Figure 1 shows a conceptualized diagram of the COM technology.
This technology basically involves the preparation of COM by pulver-
izing the coal, mixing it with fuel oil, and then pumping it to an
existing oil/gas fired combustor. The coal particle size and con-
centration in the mixture will vary with the application. Burner
modifications, bottom ash removal equipment, soot blowers, and pol-
lution control devices might have to be added, depending on the ex-
isting equipment available and particular requirements of the instal-
lation under consideration.
Successful combustion of COM has been achieved in short-term
tests in existing boilers and furnaces, confirming the feasibility of
burning COM fuels in such equipment. Burning of COM continuously for
extended periods of time with higher reliability is being investi-
gated to determine the extent to which this retrofit technology can
be implemented practically.
Potential advantages of burning COM include the following:
• near-term solution to increased coal utilization
• only short-time delays in retrofit conversion
• minimum risk technology and least cost direct substitution of
coal for oil/gas relative to other coal conversion
technologies
• handling, storage and combustion similar to fuel oil
• utilization of remaining life of existing oil/gas fired
combustors
• ability to prepare COM off-site and to employ existing oil
transportation and distribution networks
• provides fuels flexibility and emergency preparedness
• lessening of environmental impact when contrasted with
burning coal directly
239
-------
FIGURE 1
CONCEPTUAL DIAGRAM OF COM PREPARATION AND COMBUSTION
-------
The Department of Energy's COM program currently is based on
two demonstration projects and an in-house development project.
Table 1 lists these projects and shows their main features. The
New England Power Service Company (NEPSCo) project is the first to
undergo demonstration testing and is scheduled to start in June 1979.
Figure 2 shows NEPSCo's coal-oil mixing facility, which consists of a
new sheet metal building attached to the existing boiler house. The
approximate dimensions are 60 x 80 x 20 feet.
PROCESS SEQUENCE
The COM technology basically involves two major processes:
preparation of the coal-oil mixture and then its combustion in ex-
isting combustors. The generalized COM preparation process takes
place at low temperature (150-200°F) and atmospheric pressure, and
involves the following simple mechanical operations: pulverization of
the coal, mixing the coal and oil (with/without additives), and stor-
age of the resulting mixture. In general, the COM preparation plant
can be considered to operate as a centralized preparation and dis-
tribution facility continuously producing COM. The preparation plant
and the combustor (boiler/furnace) will operate independently; COM
storage will be the link between the two facilities.
COM can be prepared by several different processes which are
a till in various stages of development (Foo, Jamochian, and Sabadell,
1978). The major features of COM preparation such as coal grinding,
coal/oil/additive mixing, types of additives, and coal size distribu-
tions are all different for the currently-funded DOE projects. A
summary of the major characteristics of these processes is shown in
Table 2. At this point in the development, it is not possible to say
which of these processes will provide the best fuel characteristics
at the least cost. Furthermore, it is conceivable that more than one
process may be required depending on the needs of a particular appli-
cation. For example, in the blast furnace application, the coal
particle top-size can be much greater than for a boiler, resulting in
different fuel characteristics.
The outputs resulting from the application of COM are the same
as the standard products of the existing installation, namely elec-
tricity or process steam from boilers, and pig iron and low Btu gaB
from blast furnaces. The waste outputs also are similar to the
current flue gas and solid wastes. A description of inputs and
outputs, and equipment for each process is included in Appendix D.
241
-------
DEVELOPER
(SITE)
APPLICATION
INTERLAKE
(Chicago, 111)
NEPSCOd)
(Salem, Mass)
PETC^2) (In-House)
(Bruceton, Pa)
Blast Furnace
Injection
Utility Boiler,
Oil-Fired,
Designed Coal
Industrial Boiler,
Oil-Fired,
Designed Oil/Gas
(1) NEPSCO = New England Power Services Co.
(2) PETC = Pittsburgh Energy Technology Center
TABLE 1
COM TECHNOLOGY PROJECTS
PERCENT COAL COM PRODUCTION
TEST UNIT CAPACITY CONCENTRATION CAPACITY (TON/HR)
1200 Tons Iron/Day 50 12
625,000 lb/hr 30 49
Babcock and Wilcox
24,000 lb/hr 40-50
Nebraska Watertube
-------
Source: Courtesy of New England Power Service Company,
Salem, Massachusetts
FIGURE 2
NEPSCO'S COM PREPARATION PLANT
243
-------
TABLE 2
COM PROCESSES
DEVELOPER
COM PREPARATION
INTERLAKE
• Wet Grinding of Coal/Oil in a Disperser
• Coal Particle Size <3 mm
• Gel-Type Additive (.Petrolite)
NEPSCO
N3
• Dry Grinding of Coal
• Coal Particle Size <70|jim
• Mechanical Mixing
• With/Without Additive
PETC
(In-House)
Alternative Approaches
With/Without Additives
INPUT FUELS
OIL COAL
Number 6 Illinois
Number 6
Dome s t ic and
Foreign
District 7
(Va., W. Va.)
District 8
Va., W. Va., Ky
Number 6
Bituminous
Subbituminous
-------
TECHNOLOGY STATUS
Recent tests support the feasibility of the COM technology. The
COM program at General Motors (GM) which was jointly funded by
DOE,the Electric Power Research Institute (EPRI) and other private
organizations was successfully completed July 1977 (Brown 1977). Two
hundred fifty thousand gallons of 50 percent coal (pulverized to less
than 70 microns), 43.3 percent No. 6 oil, 6.5 percent water and 0.2
percent additive were burned over 494 hours of testing in a package
oil-fired boiler rated at 120,000 pounds per hour and 250 psra steam.
The boiler never worked at full load (only up to 75 percent of capac-
ity) because of a lack of demand for steam, but results indicate that
COM burns much like No. 6 oil for 35-to-50 percent coal concentra-
tions, and boiler ash buildup was about 1 percent of fuel ash so the
furnace floor soot blower was not used. The problems encountered
were (1) instability of the COM which caused some combustion varia-
tions and (2) erosion of COM circulation pump internals, control
valves, and orifices.
Florida Power Corporation, in partnership with Dravo Corpora-
tion, has run limited tests on COM production and combustion in an
oil-fired utility boiler producing 2.5 x 10® lb/hr of steam at 1005F
(Rodriguez and Sell 1978). The COM used contained 45 percent coal,
pulverized to less than 40 microns particle size, and the mixture
contained no additives. The results indicate burning similar to No.
6 oil. The major problem encountered was high erosion of the jet
mill pulverizer internals.
PETC conducted tests in a 100 hp package fire-tube boiler
designed for oil (Demeter et al., 1978). The COM contained 20
percent coal pulverized to 90 percent through 200 mesh, and the
mixture contained no additives. The results after 1000 hr firing
indicate flame stability equal to that obtained with No. 6 oil,
carbon burnout essentially complete (99%), absence of slag deposit
and acceptable corrosion rate. One problem encountered was the
greater than normal erosion of the standard (oil) burner nozzles.
Therefore, in spite of problems in particular areas, overall
test results obtained so far are promising. The problems which have
been identified appear to be solvable by state-of-the-art technology,
and COM combustion appears to offer a potential near-term solution
for partial conversion from oil and gas to coal.
The coal conversion portion of the National Energy Act (NEA)
establishes that for existing noncoal-capable units, DOE may require
the use of COM.
245
-------
Figure 3 shows the overall COM plan schedule. Commercialization
of this technology is expected to start in the early 1980's and to
reach full development by 1986. The principal initial market for COM
is based on retrofitting of existing oil-fired utility and industrial
boilers. It is estimated that for this market alone, the oil saved
is 260 x 10& bbls/ye ar for 100 percent capacity converted (Foster
1978).
246
-------
activity"
CY
1976
i
1979 1982
¦ "
1985
TECHNOLOGY SUPPORT
~
PROTOTYPES
~
T
FUNDED DEMONSTRATIONS
IT
~
to
42*
PLANNED DEMONSTRATIONS
A
T
COMMERCIALIZATION
~
~
SOURCE: Foster 1978.
FIGURE 3
COAL-OIL MIXTURE OVERALL PLAN SCHEDULE
-------
SECTION II- POLLUTANTS/DISTURBANCES
SOURCES OF EMISSIONS
Introduction
The preparation and combustion of COM have the same environ-
mental implications associated with the conventional combustion of
coal or oil. Little or no data are yet available on the quantity and
composition of waste emissions from COM and this information must be
obtained from the scheduled demonstrations before the COM program
proceeds to full commercialization by the early 1980s.
Figure 4 shows the potential emissions sources and their fates
for the different steps of the COM process. Because of the simple
nature of this technology, which involves mechanical mixing of coal
and oil at low temperatures (150-200°F) and atmospheric pressure, the
potential for fugitive emissions is very low. Wastes from coal
preparation can be handled using available techniques. The control
of wastes from the combustion process will depend on each applica-
tion, but in general should not be different from the wastes
currently being discharged.
Transient pollutants which may result from process upsets,
should be relatively minor for the simple coal-oil mixing process.
The major potential will be from spills/leaks during storage and
transportation. The effects of these transient pollutants should be
the same as for conventional oil systems.
State of Knowledge
There lis very little or no data available on emission
characteristics of COM combustion. The results of recent testing are
summarized below.
During the GM demonstration tests (Brown, 1977) stack
measurements were performed in a commercial scale industrial instal-
lation burning a COM of approximately 50 percent coal content. The
results indicate the following:
1) The average particulate concentration was 0.41 gr/acf at
273°F and 6.3 percent moisture by volume.
2) The average particulate emissions from the boiler were 91.5
lbs/hr.
3) CO2 averaged 10.7% and O2 averaged 8.8 percent, by
volume.
248
-------
ATMOSPHERE
FIGURE 4
POTENTIAL EMISSION SOURCES AND FATES FROM COM TECHNOLOGY
-------
4) The bulk resistivity of the particulate was in the range of
1 to 9 x 10^ Ohm-cm.
5) The particle size distribution (Anderson) was between 2 and
10 micrometers.
6) Acid dew point readings averaged 235°F.
In general, the results were as expected for a unit burning a fuel
having ash and sulfur contents in proportion to the coal and oil con-
tent of the mixture. It was concluded that these stack emissions
could be treated by standard technology.
Acurex conducted emission measurements for COM (30 percent coal)
combustion in a subscale facility simulating an industrial package
boiler (Busch and Brown, 1978). While carbon monoxide (CO), carbon
dioxide (C02)> sulfur dioxide (S02) and nitric oxide (NO) data
were taken, NO data was practically the only one discussed. Problems
with the SO2 analysis rendered the data practically useless. Gen-
erally CO and CO2 levels reflected good combustion burnout. The NO
levels for the mixtures fell in an intermediate range between the
parent fuels. Conventional control technology, i.e., staged firing,
utilized presently for pulverized coal combustion is, in general, ef-
fective in reducing NO emissions from COM combustion. However, be-
cause of some results which do not fully reflect similarities to
either pulverized coal or residual oil combustion, it was observed
that NO emissions based on the corresponding emission levels exhib-
ited by the parent fuels will not be valid in some cases. Syner-
gistic effects might be possible and should be considered.
PETC conducted preliminary combustion and emission studies of
COM (with mixtures of 20 and 30 percent coal content) in a 100 hp
firetube package boiler (Demeter et al. 1978; Ekman et al. 1978). The
results can be classified as pertaining to a pilot plant scale, and
indicate that COM behaves very much like the base No. 6 fuel oil. CO
was slightly higher than for oil but was acceptably low indicating
good combustion performance. Carbon conversion efficiencies were 99
percent and boiler efficiency was equal to or greater than with No.6
oil. Sulfur dioxide levels followed the increasing sulfur content in
the COM. The nitrogen oxides levels did not follow the increase of
fuel nitrogen. The opacity reading increased for COM reflecting the
increased ash content.
Florida Power (Rodriguez and Sell 1978) collected ambient air
samples of total suspended particulate matter (TSP) during their
brief testing period. The results show a good correlation between
particulate values and percentage ash in the slurry for all coal
contents (0 to 40 percent) in COM. Particle size distribution showed
250
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a larger particle size than the coal in the slurry (<40 microns).
This could be due to agglomeration of the ash particles which would
indicate a higher precipitator performance.
Potential Emission Sources
A brief description of the COM process streams which are
potential sources of waste is given below:
1) Coal storage: A 30-day coal storage capacity is usually
desirable.
liquid streams and constituents
- rain runoff and leachate: acids, organics, sulfur,
soluble metals and suspended solids
air streams and constituents
- oxidation and combustion: smoke, fumes, volatile
compounds
- windblown: coal dust
The problems originated by COM coal storage are no different
than other coal storage processes and should be treated with the
conventional applicable coal-handling techniques.
2) Coal preparation: Coal as received is reduced to the
required size by breakers and crushers. Grinding to the
required process size is the final stage of the coal
preparation.
• liquid stream and constituents
- wastewater: suspended solids and leachate
• air stream and constituents
- coal dust
• solid stream and constituents
- rock, debris, gangue, coal
Controls are available for all potential emissions.
3) Coal preparation air pollution control: The air pollution
control system is the same used for conventional air emis-
sions control. The main control module in COM is for
particulate control.
251
-------
• air stream and constituents
treated gases: particulates, and nitrogen compounds,
hydrocarbons, trace elements
• solid stream and constituents
- particulates from particulate removal: coal dust
4) Solid waste control: The main control module will be
landfill. The choice of a specific process will depend upon
the waste generated and the location of the plant. The
stability, leachability and pollution potential of the solid
wastes should be similar to conventional coal preparation
plants.
5) COM (combustion pollution control): The pollution control
system is the same used for conventional combustion emis-
sions control. The main control module in COM is for
particulate control. S0X may be a problem depending upon
the totalsulfur content of COM.
• air stream and constituents
- treated gases: particulates, S0X, N0X. C0X,
hydrocarbons, trace elements, flyash, bottom ash, and
slag
6) Auxiliary processes: Auxiliary processes might include
compressed or liquid gas handling, e.g., air, CO2, or
n2.
• air stream and constituents
- combustion products: sulfur and nitrogen compounds,
particulates, CO2, N£, CO ...
• liquid stream and constituents
- oils, suspended solids
• solid stream and constituents
- ash and fines
These environmental problems are similar to existing installations.
7) Phase separation: The main phase separations involve
solid/gas.
• solid stream and constituents
- particulate coal
- ash or slag
252
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Physical Disturbances
Because of its retrofit nature COM technology will introduce
minimal physical disturbance into the existing installations creating
only secondary impacts if any.
A potential physical disturbance that should be considered is
the case of a centralized COM preparation plant installed in a new
location. In urban areas where facilities or land for handling coal
may not be available, COM would be supplied from a centralized COM
preparation plant which could be remotely located within approxi-
mately 100 miles. COM would be prepared at the facility and then
transported (as oil would be) for storage at the combustion site. In
general, the effects would be the same as for any industrial complex,
and may include destruction of terrestrial habitat, negative visual
effects, changes in land-use pattern, and noise.
NATURE OF POLLUTANTS
Introduction
The potential impacts and the nature of the pollutants resulting
from the COM technology are expected to be the same as those from
conventional handling and combustion of coal or oil. The major
impact will result from the operation of the combustion system. The
design of the particular plant, its pollution control devices and its
environmental location will determine the extent of occurrence of
pollution situations, but in any case the effects will be less than
from a comparable coal burning plant.
In the following sections, the nature of the pollutants are
described for each category: air, water, or solid waste.
Air
Gaseous emissions will result mainly from raw material handling
and pretreatment, and combustion of COM. Particulate matter can be
generated as fugitive dust from coal-handling operations. Sulfur
oxides, nitrogen oxides, cabon oxides, hydrocarbons, particulates and
trace elements will result from the fuel combustion process.
The sulfur in the fuel will leave as S0X from the stack,
although if it is scrubbed it will end up as sulfate.
The nitrogen oxides will result from the combustion process and
will leave from the stack.
253
-------
Hydrocarbon emissions occur by evaporation, fugitive emissions
and incomplete combustion. Carbon monoxide is produced from
incomplete combustion. Other gaseous compounds that can be emitted
from the combustion process are trace elements that vaporize.
Radioactivity due to the coal source may be emitted with the same ef-
fects as in comparable conventional coal-fired installations.
Potential pollutants other than those identified above may ex-
ist. The exact pollutants will depend on the coal/oil composition.
The fate of these constituents will be determined by the process,
control devices and overall design (fugitive emissions).
Sulfur emissions can be controlled by use of standard de-
sulfurization techniques. Nitrogen oxides may be reduced by modified
combustion techniques. Solids resulting from particulate control are
disposed as landfill.
The addition of chemical additives for stabilization purposes
could contribute to atmospheric emissions different from those found
in conventional coal/oil combustion. However, their concentration
will be approximately 0.2 percent by weight and should not contribute
specifically to emissions. Most additives are composed of organic
materials, i.e., soaps, starches, etc., which are combustible and
should not present unusual problems. However, some additives are
proprietary and will require special testing to ensure that no
hazardous emissions will occur.
Water
Wastewater may result from moisture in the coal, spraying of
coal storage piles, water for additive solution, effluents associated
with water treatment, the steam cycle and cooling tower blowdowns,
and water leaching of ash.
Leachate from coal storage may transmit fine coal particles,
humic acids, sulfuric acid, and inorganic ions and introduce them
into the soil, surface and groundwater.
These effects as well as thermal impacts from COM combustion are
expected to be essentially the same as those which would result from
a comparable facility using conventional coal combustion.
Solids
The potential solid wastes from COM may constitute 20 percent of
the mass of coal raw material received by the plant. The major solid
wastes are refuse from coal cleaning and ashes from the combustion
process. Refuse consists largely of rock, mineral matter, and coal
254
-------
particles. Ash consists of metallic oxides and trace element
compounds.
Because of its natural origin, coal contains trace quantities of
almost all elements, which may be present in elemental form or
combined in organic and inorganic compounds. The major pollution
effect will result from COM combustion. The fate of these trace
elements is expected to be the same as in conventional coal-fired
installations and appear in the solid wastes.
Coal-derived organic compounds such as polycyclic aromatic
hydrocarbons (PAH) and dioxins should be considered as potential
emissions in coal burning. But if as expected, they are absorbed on
particulate matter then particulate control devices should be able
to remove most of these organic compounds.
Collected solid wastes stored in settling ponds may produce
significant leachates about which little is known. Trace amounts of
a very large number of elements may appear in ash including some
toxic elements such as mercury, cadmium, and arsenic. Landfilling
will have to consider potential contamination of the surrounding
area.
Other solid effluents may include materials resulting from
sulfur scrubbing, i.e., sulfates. Fugitive dust from coal piles,
filtercake, and evaporated solids from water regeneration chemicals
may also be produced.
COM waste disposal can probably be handled in accordance with
current ash disposal methods.
Transient Pollutants
Accidental releases of pollutants are possible due to process
upsets and accidents. Typical examples of these types of emissions
might be the following:
coal handling - broken belt, spills
coal screening - breakdown, dust
oil handling - breakdown, spills
additive handling - breakdown, spills
slurry preparation - breakdown, spills
ash removal - dust
255
-------
piping and pumps - breakdown, leaks
furnaces - flameouts, start up
sampling - purges, leaks
transportation - breakdown, spills
The potential for these transient pollutants and their effects
are expected to be similar to the same situation in conventional
coal/oil systems, For instance, storage and transportation of COM
should be considered similar to oil handling, and since, in general,
oil handling is already part of the existing installation, no
significant increase in spill potential appear likely. Standard
procedures such as a drainage basin around the storage tank would
minimize any such hazards.
Emissions from On-Going COM Testing Program
As described above in Technology Description, the first COM
demonstration testing of the ongoing DOE program will be performed by
NEPSCo and is scheduled to start in June 1979. Consequently, there
is little information available on actual rates of emission. Esti-
mates performed for the environmental assessment of each project are
presented below.
Inter lake (Ekman et al. 1978)
For a production rate of 1200 tons per day of pig iron, the
estimated COM fuel injection will be 22,300 gallons per day, corres-
ponding to 102,500 pounds per day of coal, 11,500 gallons per day of
No. 6 fuel oil, and 58 gallons per day of proprietary additive.
Based on these figures, the emissions for each waste stream origi-
nated by COM were estimated and compared to the currently produced
wastes.
Air Emissions:
The nature of the blast furnace process does not permit the
chemical contaminants (i.e., SO2) from the combustion process of
the COM auxiliary fuel to escape in the effluent gases.
Even though the coal grinding takes place under contact with
oil, some emission might result. If 0.01 percent of the coal handled
is released as dust, then 0.5 pounds per day of dust would be emitted
from the baghouse, which would have a collection efficiency of 95
percent.
256
-------
Solid Wastes:
The ash from the coal will be captured in the slag that collects
on top of the iron on the hearth. For a 9 percent ash in the coal,
approximately 9,200 additional pounds of slag would be produced per
day. This would be an increase of approximately 1 percent over the
slag currently produced.
Any increase in flux materials due to COM will also be captured
in the slag, which might cause a slight additional increase in the
current amount of slag production.
NEPSCo (U.S. Department of Energy 1977)
NEPSCo will burn COM in Unit 1, which has a generating capacity
of 80 MW. The unit is one of four units at that site and is used for
base-load service. The proposed COM rate of consumption is approxi-
mately 6,000 gallons per hour, corresponding to approximately 15,500
pounds of coal and 4,500 gallons of oil per hour.
Air Emissions:
The calculated emissions of total suspended particulates (TSP),
sulfur oxides and nitrogen oxides are shown below.
Emissions
Pollutant (lbs/10^ Btu)
TSP 0.03
S0X 1.6
N0X 0.8
A variance from the S0X standard has been requested for the 1-year
demonstration period.
Fugitive emissions of volatile hydrocarbons may result from
storage of the mixture at the site. The COM storage tank has a
capacity of 16,000 barrels, which is small compared with the
630,000-barrel total storage capacity at the Salem Harbor Station.
Also, since coal would be mixed with the oil, the possible
evaporation would be less than in a similar tank containing oil
alone. Therefore, the effect of volatile hydrocarbons would be
minimal when compared to the present conditions. Furthermore, proper
tank design should prevent any vapor loss to the environment.
257
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Water Streams:
COM operation would require approximately 80 gallons of water
per hour, which is less than 0.4 percent of the current water demand.
Oil handling is already part of the on-site operation, so no
increase in spill potential appears likely. Open coal storage
already exists, so no increase in runoff should occur.
Solid Wastes:
Approximately 17 tons of ash would be produced daily. This will
be disposed of in an approved sanitary landfill.
PETC (U.S. Energy Research and Development Administration 1977)
The proposed COM feed rate will depend on the coal source and
will vary approximately from 1,400 to 1,700 pounds per hour. The
corresponding requirements of coal and oil will be approximately 600
and 900 pounds per hour, respectively.
Air Emissions:
Fugitive coal dust emissions from coal handling and grinding are
expected to be slight because of enclosed system design control
measures.
The estimated total emissions resulting from the combustion of
COM would be:
Emissions
Pollutant (lb/106 Btu)
TSP 0.08
S0X 0.4 7
N0X 0.52
Sodium bicarbonate would be used as a sorbent at a rate of 3
pounds per 1 pound of S0X produced. Maximum consumption of sodium
bicarbonate would be approximately 105 pounds per hour.
Water Streams:
Water requirements for COM operation would not change the
present consumption uses and discharges of the plant site.
258
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Solid Wastes:
The total solid waste collected from the boiler and stack would
be approximately 170 pounds per hour. Approximately 70 percent of
this waste would be spent sorbent products and sodium bicarbonate,
and 30 percent would be ash. This waste would be disposed in a
commercial landfill designed to handle industrial wastes that present
potential leaching problems.
259
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REFERENCES
Brown, Jr., A., ed. 1977. Final report of the General Motors
corporation powdered coal-oil mixtures (COM) program. FE-2267-2.
Busch, C. F., and Brown, R. A. 1978. Parametric study of coal-oil
mixture combustion. In First International Symposium on coal-oil
mixture combustion proceedings, 7-9 May 1978, at St. Petersburg
Beach, Florida CONF-7805141. M-78-97. McLean, VA: The MITRE
Corporation, pp. 183-196.
Demeter, J. J.; McCann, C. R.; Bellas, G. T.; Ekman, J. M.; Bienstock,
D. 1978. Combustion coal-oil slurry in a 100 hp firetube boiler.
Combustion, pp. 31-37
Ekman, J. M.: McCann, C. R.; Mathur, M. P.; and Bienstock, D..1978.
Parametric study of coal-oil mixture combustion. In First Interna-
tional Symposium on coal-oil mixture combustion proceedings, 7-9 May
1978, at St. Petersburg, Florida, CONF-7805141. M-78-97. McLean, VA:
The MTTRF. Corporation, pp. 101-112.
Foo, 0. K., Jamgochian, E., and Sabadell, A. J. 1978. Coal-oil mixture
RD&D program plan. MTR-8034. McLean, VA: The MITRE Corporation.
Foster, C. B. 1978. Overview of the U.S. DOE coal-oil mixture program.
In First International Symposium on coal-oil mixture combustion
proceedings CONF-7805141. M-78-97. McLean, VA: The MITRE Corpora-
tion, pp. 9-20.
Hart, D., and Aurand, D. 1977. Environmental assessment of a facility
for the combustion of a coal and oil mixture in a blast furnace at
Interlake. MTR-7468. McLean, VA: The MITRE Corporation.
Keyser, N. H., and Marlin, L. A. 1977. Injection of coal-oil mixture
into a commercial blast furnace. In proceedings of the coal-oil
mixture combustion technology exchange workshop, 29 October 1976,
at Washington, D.C. CONF-761019. M77-8. McLean, VA" The MITRE
Corporation, pp. 79-87.
Rodriguez, L. and Sell, F. 1978. Florida power corporation/Dravo
corporation coal/oil composite fuel program. In First International
Symposium on coal-oil mixture combustion proceedings, 7-9 May 1978,
at St. Petersburg Beach, Florida CONF-7805141. M-78-97. McLean, VA:
The MITRE Corporation, pp. 51-65.
U.S. Department of Energy 1977. Environmental assessment facility
for the combustion of coal-oil mixture. New England Power Service
Company. DOE/EA-006.
U. S. Energy Research and Development Administration. 1977. Environ-
mental Assessment of a Coal-Oil Slurry Combustion Test Facility,
Pittsburgh Energy Research Center, Bruceton, Allegheny County, PA,
Division of Coal Conversion and Utilization, CIA/CCU77-4.
261
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Part 6
Cocombustion with Municipal Solid Waste
-------
TABLE OF CONTENTS
Page
LIST OF ILLUSTRATIONS 265
LIST OF TABLES 268
SECTION I - TECHNOLOGY DESCRIPTION 271
INTRODUCTION 271
TECHNOLOGY CLASSIFICATION 273
PROCESS DESCRIPTION 280
RDF Production 280
Cofiring RDF with Coal 286
TECHNOLOGY STATUS 293
Introduction 293
Commercialization 293
Technology Development 293
Technological Barriers 2
-------
TABLE OF CONTENTS (Concluded)
PaSe
LANDFILLED SOLIDS AND LEACHATE CONTAMINATION 356
TRANSIENT POLLUTANTS 36!
REFERENCES 365
264
-------
LIST OF ILLUSTRATIONS
Figure Number Page
1 RDF Preparation and Energy Production 272
2 Suspension-Fired Boiler Modified for RDF 276
Cofiring
3 Spreader Stoker Boiler Modified for RDF 277
Cofiring
4 Production Process for Various Types of 278
RDF
5 Process Flow Diagram for Fluff RDF Produc- 281
tion and Materials Recovery
6 Energy Balance for Hypothetical RDF Pro- 282
duction Plant
7 Schematic of Hammermill 284
8 RDF Receiving and Firing Facilities 287
9 Disposition of Recovered Materials and 297
Waste Products from RDF Production
Particle Concentration versus Day by 3Of)
Location - Outagamie County
11 Particle Concentration versus Day by 306
Location - Baltimore County
12 Particle Size Distribution for Air 315
Classifier Cyclone Discharge
13 Particulate Size Distribution for Hammer- 316
mill Cyclone Discharge
1^ Particulate Size Distribution from Coal + 319
RDF Cofiring (Uncontrolled Particulates
- Stoker Firing) - Columbus, Ohio, Munici-
pal Electrical Plant
265
-------
LIST OF ILLUSTRATIONS (Continued)
Figure Number
15
16
17
18
19
20
21
22
23
24
25
26
27
Page
Particulate Size Distribution from Coal 320
+ RDF Cofirinp (Uncontrolled Particulates
- Suspension Firing) - Union Electric Plant,
Missouri
Controlled Particulate Emissions as a Func- 321
tion of Boiler Load for Varying Cofiring
Ratios - Suspension Firing - Union Electric
Plant, Missouri
Uncontrolled Particulate Emission Rate 324
Stoker Firing - Ames, Iowa
Controlled Particulate Emission Rate 325
Stoker Firing - Ames, Iowa
Cyclone Collection Efficiency - Ames, 326
Iowa
Particulate Emission Rate as a Function 327
of RDF Ash Content
N0X Stack Emission - Union Electric 335
Plant - St. Louis, Missouri
SO2 Stack Emission - Union Electric Plant - 337
St. Louis, Missouri
N0X Stack Emissions as a Function of RDF 339
Heat Input and Boiler Load - Ames, Iowa
SO2 Stack Emissions as a Function of RDF
Heat Input and Boiler Load - Ames, Iowa 340
Chloride Emissions as a Function of RDF Heat 341
Input and Boiler Load - Ames, Iowa
Hydrocarbon Emissions as a Function of RDF 343
Heat Input and Boiler Load - Ames, Iowa
Aldehydes and Ketones Emissions as a Func- 344
tion of RDF Heat Input and Boiler Load -
Ames, Iowa
266
-------
LIST OF ILLUSTRATIONS (Concluded)
Figure Number Page
Cyanide Emissions as a Function of RDF 346
Heat Input and Boiler Load - Ames, Iowa
^ Phosphate Emissions as a Function of RDF 347
Heat Input and Boiler Load - Ames, Iowa
267
-------
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
LIST OF TABLES
PaSe
Refuse Combustion for Power Generation 274
Coal-Burning Plants Only
Properties of Refuse-Derived Solid Fuels 279
Comparison of Fluff RDF and Coal (Dry Process)
288
Compositional Analysis of RDF 289
Average Ames Solid Waste Classification 290
by Weight
Chemical Analysis of Coal and Coal + RDF 291
Status of Cofired Systems 294
Wastes Generated from Processing Operations 298
Airborne Dusts from Refuse Processing 302
Organic and Inorganic Percentages of Dusts 303
from Refuse Processing Operations
TLV of Metals Analyzed versus Concentration 307
Airborne Microorganisms around Waste PrQ^ 308
cessing Facilities
Reported Concentration of Airborne Micro- 309
organisms within Resource Recovery Plants
Bacterial and Viral Emissions from Classi- 311
fier and Hammermill Cyclones
Concentration of Bacteria and Viruses in 312
Suburban Air
Bacterial Emissions from RDF Storage Fa- 313
cility
Particulate Emissions from Air Classifier 314
and Hammermill Cyclones
Uncontrolled Particulate Emission from 318
Columbus Municipal Electric Plant
Comparison of Particulate Emissions from 323
Stoker and Suspension-Fired Boilers
268
-------
LIST OF TABLES (Continued)
Table Number Page
20 Trace Elements in Coal and RDF 328
21 Trace Elements in Air Classifier Discharge 330
22 Comparison of Trace Elements Concentrations 331
of Coal and Coal + RDF Emissions
23 Trace Elements in Uncontrolled and Con- 332
trolled Emissions from Cofiring^
(Union Electric Plant, St. Louis,
Missouri)
24 Trace Elements in Uncontrolled Emissions 333
from Cofiring, Columbus, Ohio Municipal
Electric Plant)
25 Stack Gas Analysis - Controlled Emissions 335
(Columbus, Ohio Municipal Electric Plant)
26 Chloride Emissions (Union Electric Plant, 338
St. Louis, Missouri)
27 Organic Compounds in Stack Emissions (Ames, 345
Iowa Resource Recovery Project)
28 Pollutants in Washdown Activity 348
29 Bottom Ash Properties and Accumulation 350
Rates
30 Compositional Analysis of Bottom Ash 351
31 Trace Elements in Bottom Ash 352
32 Sluice Water Bacterial Contamination for 353
Coal + RDF Firing Conditions
33 Ash Pond Effluent Analysis 354
34 Compositional and Chemical Analysis of Land- 357
filled Inerts and RDF
35 Trace Elements in Landfilled Fiyash (Union 358
Electric Plant, St. Louis, Missouri)
36 Trace Elements in Landfilled Flyash (Colum- 359
bus, Ohio Municipal Electric Plant)
269
-------
LIST OF TABLES (Concluded)
Table Number Page
37 Leachate Analyses 360
38 Leachate Dilution Requirements to Meet 362
Drinking Water Standards
39 Sources of Transient Pollutants 363
270
-------
SECTION I - TECHNOLOGY DESCRIPTION
INTRODUCTION
The shortage of environmentally acceptable landfill sites and
the need to extend existing landfill life has spurred interest in
disposal of municipal solid wastes (MSW) through energy and material
recovery processes termed resource recovery. Furthermore, the cur-
rent emphasis on conserving fossil fuels has resulted in an increased
interest in the use of MSW as a fuel supplement in existing utility
and industrial boilers. The process of rendering municipal solid
wastes suitable for cocombustion with conventional fuels such as coal
has led to the extraction of recyclable materials such as ferrous
metals, glass fractions, and aluminum. Figure 1 shows a plant using
this resource recovery and energy-producing concept that is now being
constructed for the city of Akron, Ohio.
The disposal of waste in an environmentally acceptable manner
can be met through the cocombustion process, but as a practical
reality, the basic conditions of economic viability and social accept-
ability must be met. Economic benefits realized from energy savings,
reduction in disposal costs, reduction of the drain of virgin mater-
ials and fossil fuels are strongly in favor of cocombustion processes
as a viable.resource recovery system. Increasingly, utility com-
panies can look to refuse-derived fuel (RDF) not only as a relatively
inexpensive supplement but as a low-sulfur fuel which can be cocom-
busted with lower grade coal, whereas if used by themselves, these
coals might result in excessive sulfur oxide emissions.
Resource recovery plants processing municipal solid waste to
produce RDF are relatively new; major strides in technology develop-
ment have taken place only during the past 5 years. Full-scale
operating experience is limited and technical-economic questions
remain. Techniques for producing RDF are developing rapidly with a
view toward producing a fuel that can be readily used in existing
coal-firing equipment.
Electric utilities dominate the potential for the applicability
of the cocombustion process because of their size per unit and prox-
imity to major urban areas, the source for an adequate, continuous
MSW supply at a reasonable cost for collection and transportation.
In addition to the utility market, a substantial outlet for RDF could
be found through multiple industrial users. The total national
capacity of coal-fired utility boilers is nearly three times that of
coal-fired industrial boilers. Large utility boilers can accept the
RDF output of plants of 500 tons per day and larger. This would
equate to a raw refuse output of 700 tons per day or the equivalent
refuse from a population of about 250,000 people. The cocombustion
271
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• 1
-------
process requires modification of boilers to accept RDF, i.e., addi-
tional firing ports for RDF, installation of grates to allow for com-
plete combustion of RDF in suspension-fired boilers, and increased
ash-handling capabilities. From an economic standpoint, the addi-
tional capital cost of these modifications seems reasonable when
weighed against the prospect of financing a new facility producing
power from refuse firing alone. Also, existing utilities have made
major investments in air pollution control devices, thus major ad-
ditional capital expenditures for abatement equipment are not anti-
cipated for cofiring. However, the cofiring of RDF with coal might
produce increased particulate loading on emission control equipment
and increased boiler corrosion and maintenance problems, which will
require resolution through information gained from operating ex-
perience .
The potential of cocombustion of RDF with coal can be gauged by
examining Table 1. Potential energy supply from refuse can replace
7.4 percent of the total energy requirement being supplied by coal.
The outlook for cocombustion processes is therefore promising and
will depend on the active participation of utilities and industry.
To a large extent, the rapid acceptance and growth of this technology
will depend on developing technical-economic systems that will enable
utilities and industry alike to ensure reliable power generation,
minimize capital investment costs, and comply with environmental re-
gulations.
The data presented in the following discussion are obtained
from experiences at four coal-RDF cofiring facilities. Total cumu-
lative operating experience with cofiring RDF is only about 5 years.
Limited data are available for many of the experimental parameters
discussed. Conclusions drawn from these data must be used carefully
when assessing health and environmental impacts until more complete
data are available.
TECHNOLOGY CLASSIFICATION
Cocombustion of coal with a refuse-derived fuel (RDF) system
designates a processing system that renders municipal solid waste
(MSW) suitable as a fuel supplement to coal-fired boilers. The RDF
is prepared by subjecting MSW to a series of mechanical operations
employing size reduction and classification techniques that produce a
combustible fraction having a higher heating value of 5,000-6,000
Btu/lb, which is about half the heating value of coal. RDF can be
produced so that it has physical characteristics that are compat-
ible. Consequently, several types of RDF are produced to enable easy
storage, transport, and firing with existing coal-firing mechanisms.
273
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TABLE 1
REFUSE COMBUSTION FOR POWER GENERATION
COAL-BURNING PLANTS ONLY
N>
->
(b)
(a)
Potential
Rated
Energy
Area
Refuse
Energy Supply
Capacity
Rqmt.
Pop.
Generation
From Refuse
MW
1012 —
yt-
Millions
^6 tons
vr
¦ 1012 Siu
yr •
(a/b%)
ALABAMA
9560.3
458.2
1.82
1.29
11.66
2.5
CALIFORNIA
-
-
16.82
11.97
107.75
10.3
CONNECTICUT
3002.0
164.5
2.63
1.87
16.89
DELAWARE (Wilmington)
827.5
53.5
0.55
0.39
3.53
6.6
FLORIDA
5449.7
187.0
6.09
4.32
38.91
20.8
GEORGIA
9662.0
497.4
2.37
1.66
15.01
3.0
ILLINOIS
16228.3
877.0
9.43
6.68
60.12
6.9
INDIANA
12239.7
630.6
3.76
2.64
23.78
3.8
KANSAS (Kansas City)
2262.8
89.3
1.38
0.98
8.84
9.9 (also
KENTUCKY
11653.2
581.3
1.48
1.03
9.35
1.6 in
MAINE (Portland)
-
-
0.21
0.14
1.34
-
MARYLAND
5541.3
369.4
5.68
4.04
36.42
9.9
MASSACHUSETTS
3533.3
188.2
6.29
4.47
40.29
21.4
MICHIGAN
11875.5
676.0
6.89
4.87
43.90
6.5
MINNESOTA (Mpls.-St. Paul)
2018.8
106.1
1.99
1.42
12.80
12.1
MISSOURI
11366.5
532.6
4.62
3.29
29.61
5.6
NEBRASKA (Omaha)
774.2
38.9
0.58
0.41
3.70
9. 5
NEW HAMPSHIRE (Manchester)
638.0
36.3
0.40
0.28
2.57
7.1
NEW JERSEY
5194.9
263.8
4.84
3.46
31.15
11.8
NEW YORK
10134.5
503.9
17.33
12.34
111.08
22. 0
NORTH CAROLINA
11462.0
703.0
1.69
1.16
10.47
1.5
OHIO
28145.1
1263.6
9.89
6.95
62.58
5.0
PENNSYLVANIA
21555.9
1093.7
11.11
7.88
70.97
6. 5
RHODE ISLAND (Providence-
49.5
Pawtucket, Warwick)
145.9
10.6
0.82
0.58
5 .27
TENNESSEE
1004 3.7
459.4
2.22
1.57
14.15
3.1
VIRGINIA
4174.3
217.7
1.85
1.31
11.80
5.4
WEST VIRGINIA
10583.3
599.3
0. 54
0.36
3.29
0.5
WISCONSIN
5609.8
262.6
3.47
2.45
22.08
8.4
211419.7
10775.6
125.37
88.93
800.45
7.4
SOURCE: Gordian Associates, Inc. 1974.
-------
Cocombustion processes can be classified by the method of com-
bustion of the RDF with the primary fuel, coal. Essentially, for
coal-fired equipment, two basic fuel-feed systems are utilized:
• Suspension firing of pulverized coal is used in large
utility boilers. The RDF is blown in through separate
nozzles located in each corner of the furnace about 2 feet
above the coal nozzle. Pulverized coal-firing generates a
large fire ball of heat into which the RDF is introduced.
Figure 2 shows a suspension-fired boiler suitably modified
for RDF cofiring.
• Spreader stoker firing employs mechanical or pneumatic feed
mechanisms that distribute coal over a travelling grate, on
and above which combustion of the fuel occurs. RDF is
normally pneumatically blown into the boiler with the
entrance nozzles containing deflectors to distribute the RDF
to the rear face of the boiler much as a spreader would do.
Figure 3 shows a spreader-stoker boiler modified for
RDF firing.
Cocombustion processes can also be classified on the basis of
RDF physical and particle properties. Figure 4 shows the production
process of various types of RDF that can be used in cocombustion
processes with coal, and Table 2 presents some important properties
of the fuels described.
• Fluff RDF is MSW that has been processed so that it will
burn efficiently in suspension as it falls through the fire
ball (center of turbulent flame patterns) of a boiler
furnace. In actual practice, about 60 percent of RDF burns
in suspension, indicating the need for some type of grate to
retain uncombusted fluff RDF which can then be completely
burned on the grate. Fluff RDF can be fired into the large
utility-class boilers (greater than 500 million Btu per hour
input and 50 megawatts of power output), including both
suspension-fired and cyclone-fired boilers, and in certain
stoker- and spreader stoker-fired boilers.
Fluff RDF can be defined as having a particle size of from
1/4 inch to 2 inches with heavy inorganic and organic
fractions removed. Larger RDF particles might not burn as
efficiently. Fluff RDF has an approximate heating value of
5,000 Btu/lb and a moisture and ash content of about 30 per-
cent and 20 percent, respectively.
275
-------
INITIAL
SUPERHEAT
ECONOMIZ
COAL FEEDERS
SOURCE: Parkhurst 1976.
FIGURE2
SUSPENSION-FIRED BOILER MODIFIED
FOR RDF COFIRING
276
-------
DISTRIBUTOR
AIR FAN
FIGURE 3
SPREADER-STOKER BOILER MODIFIED FOR RDF COFIRING
-------
FIGURE 4
PRODUCTION PROCESS FOR VARIOUS TYPES OF RDF
-------
TABLE 2
Properties of Refuse-Derived Solid Fuels
Property Fluff RDF Powder RDF Densified RDF
Heating Value (Btu/lb) 5000-6500 7000-7800 5000-6500
Bulk Density (lb/ft3) 5-9 25-32 35-42
Moisture (%) 20-30 2-3 20-30
Average Size (inches) 1/4-2 .033 1
Ash (%) 19 10-12 19
Wet Process
Fluff RDF
3500
35-42 (dry)
50
<0.06
20
-------
• Powder RDF results from chemically embrittling the cellu-
losic fraction of fluff RDF and pulverizing the resultant
material so that 80 percent by weight of the material will
pass through a 20-mesh sieve (0.33 inch or 0.841 mm). Dust
RDF has a heating value of 7,000-7,800 Btu per pound and
contains about 12 percent ash and 2-3 percent moisture.
Powder RDF finds greatest application in large
suspension-fired utility boilers and also when fired as a
suspension in oil. Better combustibility and higher
utilization rates of RDF are seen as advantages.
• Densified RDF, abbreviated as d-RDF, is made by processing
fluff RDF in a pelletizer or briquetter by mechanical extru-
sion and compaction. Densifying RDF will minimize storage
and handling problems associated with fluff RDF and dust
RDF. Densified RDF could be cofired at higher rates than
fluff RDF in stoker and spreader stoker boilers. The heat
value of densified RDF would be similar to that of fluff
RDF.
• Fluff RDF - Wet Process. A relatively new approach to
preparation of RDF from MSW centers around the wet pulping
cleaning and dewatering of refuse to 50 percent moisture
content prior to use as a supplement to coal-fired steam
generators. The heating value of wet fluff RDF is ap-
proximately 3,300 Btu/lb with a moisture content of ap-
proximately 50 percent and an ash content of 15 to 20 per-
cent. The wet fluff must be further dewatered to 20 percent
moisture content so that the fuel can be efficiently fired
in suspension or spreader stoker fired boilers.
PROCESS DESCRIPTION
RDF Production
The main purpose of RDF production is to reduce municipal wastes
to a form that can be readily combusted with coal in a steam and/or
power generating facility. The process yields a fuel of more consis-
tent physical and chemical characteristics, thus enabling better con-
trol of the combustion process. Figure 5 represents a typical proc-
ess and material flow diagram for fluff RDF production. Figure 6 re-
presents the energy balance for a hypothetical 1,000 ton/day RDF
preparation facility, indicating the economic viability of the con-
version process with respect to energy efficiency.
The following sections describe the unit processes shown in
Figure 5. Although there can be many variations to this process
280
-------
LANDFILL
25%
TOTAL SOLID WASTE
75%
AUTOS,SELF HAULERS
ETC.
2%
Rejects to Reclaim
or Landfill —
TRUCKS
{
SCALE
TIPPING FLOOR I
| 100%(Refuse Processed)
MANUAL SEPARATION
| 98%
FIRST STAGE SHREDDING
To
Landfill
*
Rejects-
Sh%
To
Fuel
To
Reshred
t
1 96%
FERROUS
MAGNETIC SEPARATION
| 93%
SECOND STAGE SHREDDING
I 93% 78%
FUEL
AIR CLASSIFICATION Lights
| ^ 1% Residual
1%
4"
MAGNETIC SEPARATION
| 14%
TROMMEL SCREEN
1%
-W
Mostly
Combustible"*"
Material
S\
Fines
3%
"NONF
-4|3%
ELECTROMAGNETIC
ALUMINUM SEPARATORS
ELECTROMAGNETIC IMETALS i/AX
ERROUS SEPARATORS ~
-5/8 GLASS
SAND, GRIT
SECONDARY
ALUMINUM SEPARATOR
~ 1/ffi
ALUMINUM
MIXED NON-
FERROUS METALS
PROCESS FLOW DIAGRAM
SOURCE: Electric Power Research Institute 1977.
FIGURE 5
PROCESS FLOW DIAGRAM FOR FLUFF RDF PRODUCTION
AND MATERIALS RECOVERY
281
-------
X 109BTU/DAY
8.9 O
RAW REFUSE
1000 T/D 0 44b0 BTlj/Lfcj1
HP REQUIRED TO
OPERATE PROCESS
„ ~ EQUIPMENT
0,66 ° $700HPO
x 109BTU/DAY
LIGHT FRACTION FUEL
TO UTRITY Q g 26
NONFERROUS FRACTION
TO LANDFILL ^ „ Cft
55 T/D 0 5276 &TU/U *Q °'59
FERROUS METALS
TO SECONDARY MARKET ^ A
64 T/B 6 234 6TU/LB >Q °-03
GLASS, CERAMICS, ETC.,
TO LANDFILL . ^ ^
98 T/D 0 102 BTU/LB °-02
ENERGY lossfs
"O 0.12
NOTE :
HEAT CONTENTS, RATHER THAN
SENSIBLE HEATS, OF INPUT/OUTPUT
STREAMS ARE SHOWN, BECAUSE
DIFFERENCES DUE TO SENSIBLE
HEATS ARE SMALL COMPARED
WITH HEAT CONTENTS.
NET THERMAL EFFICIENCY
= 8.26 - 0.66 = 85%
—o—
Energy Balance, MSW Solid Fuel
SOURCE: Levy and Rego 1976-
FIGURE 6
ENERGY BALANCE FOR HYPOTHETICAL RDF PRODUCTION PLANT
282
-------
sequence, the basic system components are typical of many RDF-
producing facilities.
Receiving Area Operations
Raw solid waste is normally transported to the plant's receiving
area in packer or transfer trailer collection trucks. The trucks can
be weighed on a scale and the refuse discharged onto a tipping floor.
On the floor, front-end loaders mix and direct refuse onto a receiv-
ing conveyor that transports the raw solid waste to a first stage or
primary shredder. Some separation of refuse does occur on the floor.
Large appliances, bulky items, and material capable of jamming or
clogging machinery are separated.
Primary Shredding
Shredding converts the heterogeneous refuse to a more homogen-
eous state. The shredded waste is easier to separate into salable
components, easier to convey and handle, and generally less odorous.
The shredder is technically a hammermill. Horizontal or vertical
rows of hammers swing around a shaft and grind the solid waste
against an iron grate. Primary shredding under this configuration
would typically yield particle diameters of 4 to 8 inches (Figure 7
shows a typical hammermill).
Fluff RDF is produced by further processing the coarse RDF.
This is typically accomplished by secondary shredding followed or
preceded by air classification. The resulting fluff RDF product
would have a particle diameter of 1 to 2 inches.
Secondary Shredding
The secondary shredding operation is similar to primary shred-
ding with the major difference being in the hammer design. Secondary
shredder hammers are lighter but threaded and are shaped to affect
the degree of size reduction required. Secondary shredding typically
reduces the refuse particle size to 1 to 3 inches.
Air Classification
Air classification can precede or follow secondary shredding and
is used to separate the heavier incombustibles from the light combus-
tibles. This classification process yields the refuse-derived fuel
that can be used as a fuel supplement to coal-fired boilers.
Essentially, the classifier is a chute in which the upward cur-
rent of air can be affected by induced draft or forced-draft mecha-
nisms. This causes the lighter material to be entrained in the
exhaust gas stream, while the denser materials drop to the bottom.
283
-------
VERTICAL FEED CHUTE AND
EXPLOSION RELIEF DUCT
FENWALL
EXPLOSION
SUPPRESSION
BOTTLE
FENWALL
EXPLOSION
SENSOR N
ROTOR
ROTOR SIDE PLATE
PINNED HAMMERS \ REMOVABLE ACCESS DOOR
SHREDDER DISCHARGE CONVEYOR
CUTAWAY OF DISCHARGE GRATE
SOURCE: Helmstetter and Haverland 1978.
FIGURE 7
SCHEMATIC OF HAMMERMILL
284
-------
By controlling air velocity and the cross-sectional area of the
chute, the percentage split between heavy and light fractions can be
controlled. The light fraction contains paper, textiles, food parti-
culates and other organics, all of which are combustible. Light
incombustibles like aluminum foil, pulverized glass and fine grit are
often entrained in the air flow. The heavier fraction contains fer-
rous and nonferrous metals, glass, dirt and other incombustibles.
Certain heavier combustible materials like plastics and woodchips
also end up with the heavy fraction.
By removing the heavier materials the resultant fuel is easier
to transport, has a higher heating value (approximately 5,000
Btu/lb), a smaller particle size, about 1 to 2 inches, and a lower
ash content. Approximately 65 to 85 percent of the input refuse can
be recovered as RDF.
Ferrous Fraction Recovery System
Recovery of the ferrous fraction of the MSW can provide impor-
tant revenues. Magnetic separation is a proven method for ferrous
recovery with a better than 90 percent efficiency. Typically, the
ferrous fraction is removed following primary shredding.
Several types of magnet systems have been employed, each with
considerable success. One approach is to pass the primary shredded
fraction under a revolving magnetic belt that picks up the ferrous
metal and discharges it on a recovery conveyor. This type of magnet
system has three stages of attraction: a pickup magnet that provides
the initial attraction, a transfer magnet that ensures the ferrous
materials move properly along the belt, and a final discharge magnet
that allows debris to drop from the metal before depositing the re-
covered product on the conveyor.
Degrltting
A recent modification at one RDF facility was the installation
of disc screens to remove glass and grit. These constituents have
caused severe erosion problems in equipment and transport lines at
nearly all RDF facilities. At this facility, primary shredded refuse
is conveyed on belts to a disc screen that consists of a series of
star-shaped metal plates that bounce the large pieces of refuse over
the top and allow the smaller pieces to drop through. Of the mater-
ial that constitutes the underflow, 90 percent is under 1 1/2 inches.
The overflow material is 6 to 8 inches in diameter. The underflow
material is further processed in a secondary degritter that separates
the grit and dust from the 1 1/2-inch pieces. The grit is conveyed
to a reject bin for the landfill. The 1 1/2-inch-diameter material
bypasses the secondary shredder and returns to the process flow.
285
-------
RDF Storage and Feed System
Most systems employ a combination of mechanical and pneumatic
conveyors for transporting the RDF. Storage bins range in
configuration from live bottom hoppers to conical storage silos.
In those cases where the RDF production facility is at some dis-
tance from the utility, the RDF can be loaded onto trailer trucks and
hauled to the utility where it is unloaded into a receiving surge
bin. The bin serves to smooth and distribute the flow of the fuel
from each batch-type delivery into pipelines leading to the boiler.
The bin conveyors feed the RDF into a transport system which conveys
the fuel to the firing ports of the boiler furnace.
Alternate RDF Production Systems
There are several possible combinations of the basic unit opera-
tions described previously, and these combinations aim at maximizing
the heat value of the fuel, recovering saleable metal fractions, and
generating a more stable, easily fired fuel. Also, processes are
directed towards producing fuels that are easily transported and
stored.
Cofiring RDF with Coal
*
The combustion of RDF with coal requires the modification of
boilers to accept RDF, which is normally pneumatically blown into the
furnace. Figure 8 shows a schematic of RDF-receiving and -firing
facilities for the case of RDF being fired off-site.
Introduction
Processing of MSW to RDF raises the heat value of refuse from
4,500 Btu/lb to between 5,000-8,000 Btu/lb depending on the RDF proc-
ess utilized. A comparison of the properties of fluff RDF and coal
is shown in Table 3. Compositional analysis of refuse-derived fuel
from the St. Louis demonstration facility and the Columbus, Ohio, re-
source recovery plant is shown in Table 4, whereas Table 5 shows a
compositional analysis of raw refuse and RDF for the Ames, Iowa, re-
source recovery plant. A chemical analysis of various grades of coal
and coal plus RDF mixtures is shown in Table 6.
Fuel Composition
In one of the suspension techniques, pulverized coal is tangen-
tially shot into the boiler from the corners. This tangential firing
creates a fireball that is a whirling mass of intense heat (2400°-
2800°F) above the furnace hearth. Fluff or dust RDF has been fired
286
-------
SELF-UNLOADING
-TRANSPORT
TRUCK
7*5
BELT CONVEYOR
BLOWER
PNEUMATIC FEEDER
SURGE .BOILER FURNACE
BIN /
BLOWER
PNEUMATIC FEEDER'
TO PRECIPITATOR
BOTTOM ASH
SOURCE: Rof 1975.
FIGURE8
RDF RECEIVING AND FIRING FACILITIES
287
-------
TABLE 3
Property
Heating Value
(Btu/lb)
Bulk Density
(Lb/Ft3)
Moisture
Average Size (In.)
Ash
Carbon
Hydrogen
Nitrogen
Oxygen
Sulfur
COMPARISON OF FLUFF RDF AND COAL
(DRY PROCESS)
Per Pound
Fluff RDF Coal
5,000-6,500
5-9
20-30%
1/4-2
%
19.
28.
6.9
0.6
45.
0.2
11,500-14,300
42
3-12%
3-11
6.2-81
4.3-6.0
1.0-1.7
4.8-17.4
0.6-4.3
Per Million Btu
Fluff RDF Coal
106
31-60 lb
Lb
29-38
43-56
11-14
.9-1.2
64-90
2.5-.35
106
2-10 lfc
Lb
2-10
43-70
3-5
.7-1.5
15
.4-3.7
SOURCE
: Levy and Rego 19 76.
288
-------
TABLE 4
COMPOSITIONAL ANALYSIS OF RDF
Constituent
Weight percent in refuse
St. Louis
(a)
Columbus
Sample
Sample 2^)
Paper
Textiles
Wood
Metal
Plastics:
Polyethylene
Polystyrene
Polyvinyl chloride
Polyurethane
Cellophane
Composities
Glass
Glass and Sand
Sand
Building materials
Gravel/plaster
Roofing
Total
85.7
1.1
0.8
2.0
0.9
0.1
0.9
1.0
7.5
67.4
4.1
2.8
0.6
2.1
1.2
0.6
0.1
20.1
1.0
100
100
57.8
3.9
3.6
1.2
3.0
0.7
0.8
0.8
0.1
0.5
3.6
13.8
10.2
100
(a) Air classified in addition to magnetic separation.
(b) Magnetic separation only.
Source: Vaughn et al. 1978.
289
-------
TABLE 5
AVERAGE AMES SOLID WASTE CLASSIFICATION BY WEIGHT
Cardboard
Paper
Plastics
Wood
Glass
Ferrous metal
Non-ferrous metal
Natural organics
Cloth
Tar
Miscellaneous
(sand, grit, rock, dust, etc.)
Incoming raw
Refuse (C-2)
16%
35
4
6
8
3
.2
5
1.5
1
20
RDF
From plant
20%
33
5
8
4
.5
1
3
1.6
.6
23
Based on approximately 600 samples.
Date: December 197 7.
SOURCE: City of Ames, Iowa 1978.
290
-------
TABLE 6
N>
vO
CHEMICAL
, ANALYSIS
OF COAL
AND COAL +
RDF
KiMaHar
Lbw lulfw
rtgh-ntlfur
St Louis
St. Louis
»¦»-¦ «»
QAnbM
Kth nlfii
H(Molf«
H|h ndfat
cod
cot!
cod
refute
refuse ~ cod
cod
refute
eod
eod
cod
Bta/lb, frocr
12.100
133 SO
11,920
5.550(»)
10,ISO
10,625
5375W
11,580
11,850
12,070
Mrterid
Composition, weight percent
S
3.29
OM
2^a
OXS
236
5.24
030
3.16
239
2J2
a
OC2
0.15
0X3
0.9
0X4
0X14
0.64
0X3
C
61.64
74.53
61j69
41.5
61X
S7.8
42*
64.0
H
4.45
537
5.28
5.7
5.6
5J1
6.33
4.91
HjO
6.48
1X1
6.74
28.1
7.1
4.63
26.6
5.86
3 A
3J
Ash
IS.2
10.9
13.1
19.2
18.4
19.3
26.5
12.0
10.25
10.1
Si
4.5
4.5
2
5.8
3
3-S
6.6
1-2
ft
2
OS
2
06
2.4
5-10
as
1-2
Al
2
2
IJ
OJ
1A
1-3
tt7
IX
Ci
1
0X3
ai
2A
OJ
0X7
4.0
0.2
0.1
0X6
oxs
02
0.06
0X3
03
OXS
Na
-------
above the point of coal feed so that it burns as it falls through the
fireball. When firing fluff RDF, it has been determined that the
installation of dump grates at the bottom of the furnace section is
necessary to allow for complete combustion of the RDF because only
about half of the fluff RDF will burn in suspension.
The cost of adapting a tangentially fired boiler to handle RDF
may normally be expected to be minimal because such units will permit
the insertion of solid waste firing ports without affecting pressure
ratings. Horizontally fired boilers require modification. Cyclone-
fired boilers would require different treatment, conceivably by com-
mingling RDF and pulverized coal. Generally, cofiring has only a
minor effect on the boiler combustion control system, which can be
easily adapted to accommodate RDF feed quality and quantity. In sus-
pension boilers, RDF feed rate is normally equivalent in heating
value to about 10 percent of the coal.
Stoker Cofiring
The second type of cofiring facility is the lump coal stoker-
fired furnace. The various types of stokers are single retort,
spreader stoker, and chain and traveling grate stokers. Stoker
grate-type boilers are fed stoker coal, approximately 1 1/2 inches
in size. If RDF is to be used in a stoker boiler, then RDF should be
compressed into dense nuggets about the size of crushed coal for
easier feeding. Stoker firing of fluff RDF was successfully demon-
strated for 2 years at the Ames, Iowa, resource recovery plant, thus
not limiting the RDF quality to densified RDF. RDF was successfully
fired at up to 50 percent of total heat input at Ames. The densifi-
cation of RDF for use in stoker-fired boilers would entail relatively
easier introduction into the large proportion of stoker-fired equip-
ment. The conversion costs to accept fluff RDF may be expected to be
lower for a stoker fired boiler than a suspension boiler. In stoker-
fired equipment, a feed ratio of 1:1 RDF:coal on a heat value basis
would be equivalent to a weight ratio of 2:1 RDF: coal, since RDF has
half the heating value of coal.
Boiler Performance
The three primary concerns with cofiring RDF with coal are the
increase in boiler corrosion, bottom ash, and air emissions. Co-
firing also reduces boiler efficiency, primarily as a result of un-
heated transport air introduction in the RDF feed processes. Typical
efficiency loss is in the range of 1.5 to 2.0 percent for between 10
percent and 20 percent supplemental firing.
Supplemental firing also results in a slight increase in flue
gas velocities which could increase erosion potential if flyash
292
-------
particulates increase. The increase in ash depends on the percentage
of supplemental firing. If the ash content of RDF is twice that of
coal and the heating value half that of coal, the ash loading would
increase 3 percent for each 1 percent of supplemental firing.
TECHNOLOGY STATUS
Introduction
Technical confidence gained from pilot and full-scale operating
experience will enhance the growth of a technology. This growth will
depend on the rapidity with which solid fuel preparation processes
can be commercialized to meet the utility's fuel specification for
cofiring.
Commercialization
Table 7 presents a listing of RDF-coal, cofiring projects that
are underway, committed, planned, or under study.
Technology Development
It appears that for the foreseeable future, the major thrust of
development efforts will be towards:
• developing economically optimized RDF process configurations
that yield fuels that can be readily fired in existing util-
ity boilers with minimal modification and higher RDF loading
• developing RDF processes with a view towards reducing in-
combustible fractions so that fly ash and bottom ash par-
ticulate loading can be reduced during cofiring, and ash
purity will dictate its disposal or reuse status
• developing RDF processes so that prepared fuels can be
stored, transported, and fired at utilities which are greater
than pipeline-conveying distances from the RDF plant
• developing designs for fuel free systems, air pollution abate-
ment systems, and ash-handling facilities so that they are
readily adaptable to cofiring applications
• developing design improvements based on performance feedback
from existing plants so that maintenance problems asso-
ciated with RDF production transport and handling are
reduced
293
-------
TABLE 7
Location
Albany, New York
Ames, Iova
Participants
City of Albany3 and
10 surrounding com-
munities, Smith &
Mahoneyc
City of Ames3 *
Gibbs, Hall, Durham
& Richardson, Inc.
STATUS OF COFIRED SYSTEMS
(CO-COMBUSTION WITH COAL ONLY")
Capital
Status Capacity Costs
of Development TPD ($ Million)
Groundbreaking in Oct.
77, in operation by Spring
1980. RDF will go to
boiler plant owned by
N.Y. Office of General
Services.
Operational since 1975
Ames Municipal Power
Plant Fires 100% of the
RDF produced.
750
200
22
NJ
V0
JN
Brockton-East Bridge-
Water, Massachusetts
Chicago, Illinois
(Southwest Supplemen-
tary)
East Bridgewater Ass. .
A.D. Little 4 Combustior
Equipment Associates^
City of Chicago3*5
Ralph M. Parsons
Consoer, Townsend
& Associates
Operational since 1976.
Presently not in opera-
tion due to mechanical
problems. Scheduled to
be fully operational in
summer 79. RDF to be
fired by commonwealth
Edison's Crawford Power
Plant
1000
Milwaukee, Wisconsin City of Milwaukee3
Amaricology/WMl^
Bechtel, Inc.0
In shakedown, partially 1600 18
operational. Test fir-
ing RDF at Wisconsin
Electric Power Company
Combustion
Process
Problems
2 spreaderstrokers; one N/A
suspension fired about
650 psi 800°F steam.
Suspension fired boiler Insufficient waste dump
used since 3978. Pre- grate ash, etc.
sently firing 6-7 TPH of
RDF to a maximum of 50%
of total heat input at
full load. Steam capa-
city is 360,000 lb/hr.
Never operated for tests N/A
until January 1979. Runs
intermittently.
Two suspension-fired Ash handling systems gets
boilers (combustion engi- plugged by unburned re-
neering). RDF has heat fuse. Boiler efficiency
content of 5500-6000 has not been determined
Btu/lb. RDF has mois- in 20 years.
ture of 15 -20%. RDF
has density between 9
and 23 lb/ft^. 1002
load - 10% RDF fired on
heat value basis. 50%
load - no RDF fired.
Steam 2100 psig & 1050
psig.
Suspension-f ired N/A
2 - 300 MW boilers.
-------
TABLE 7 (Concluded)
to
vo
Ln
Location
Monroe County, New York
(Rochester)
Norfolk-Portsmough,
Virginia (Metro Area)
"Southeast Public
Service Authority"
St. Louis, Missouri
Ontario, Toronto
Etibicoke Borough
Participants
a
Monroe County
Raytheon Service Co
St. Louis and EPA
Gore and Storrie
Metcalf & Eddyc
Status
of Development
Should be ready to pro-
cess refuse in May 79.
Construction 95% com-
plete. RDF to be sold
to Rochester Gas and
Electric.
Should have go-no-go de-
cision by end of April
1979. RDF will most
likely be sold to the
Norfolk Naval Shipyard
Full scale demonstra-
tion plant, no longer
operating
In design negitation
stage. RDF probably
would be sold to Ontario
Hybro-Lakeview Generat-
ing Station.
Capacity
TPD
2000
1500
Capital
Costs
($ Million)
50.4
100-200
300
1000
23.2
Combustion
Process Problems
Suspension boiler N/A
Probably suspension-fired. N/A
Selling steam to Navy.
Go-no-go decision in
July 1979.
N/A N/A
Probably burn RDF and N/A
coal in a 2-9 ratio
a^
^Owner
Operator
Designer
N/A - Not Available
-------
• developing feasibility of burning RDF in industrial
boilers
Technological Barriers
The major technological issues that delay the inception of this
technology stem from lack of operating experience. Uncertainty with
regard to operation reliability and maintenance and to environmental
problems have delayed implementation. The wider acceptance by utili-
ties of steam and power rather than RDF as a purchased commodity has
to be overcome by producing RDF that is consistent in quality and
meets the specifications of the utility. There are also several
institutional aspects which are impeding development of the utility
and industrial market.
SOURCE CHARACTERIZATION
The environmental impacts associated with the cofiring of RDF
with coal are on balance favorable. This is due in large measure to
beneficial effects such as extension of existing landfill life and
reduction of problems associated with landfills such as refuse fires,
rodent infestation, odor problems, and leachate contaminant, e.g.,
concentrations. Also, the reduction in virgin fossil fuel use and
the separation and reuse of metals is seen as an economic benefit.
The combustion process has conventional pollution and safety
problems associated with the firing of coal for power generation.
The firing of RDF with coal does, however, cause additions to certain
particulate metallic pollutants and gaseous emissions. The cofiring
of coal and RDF also produces increased bottom ash that must be land-
filled, or reused, depending on purity, however, it reduces S0X and
may reduce N0X levels. Some attention has also been paid to
potential microbiological problems in the MSW collection and RDF
processing and separation facilities.
Source of Emissions
Air, water, and solid waste pollutants are emitted from both the
RDF production facility and the RDF cofiring facility. Figure 9
shows a general disposition of recovered materials and waste products
generated from RDF production. Table 8 presents the major pollut-
ants generated from the various operations associated with production
of RDF as well as from the combustion process.
State of Knowledge
Characterization of substances in air, water, and solid waste
effluents has been concentrated primarily on the combustion process
296
-------
SOURCE: Freeman undated.
FIGURE 9
DISPOSITION OF RECOVERED MATERIALS AND
WASTE PRODUCTS FROM RDF PRODUCTION
297
-------
TABLE 8
WASTES GENERATED FROM PROCESSING OPERATIONS
OPERATION
RECEIVING MEDIUM (PRIMARY)
AIR
WATER
LAND
Receiving Area
Dus t, Bact eria
Oversized bulky wastes
Receiving Area
(Floor Washdovm)
Suspended Solids
Dissolved Organics
Bacteria, Viruses
Materials Recovery
Shredding
Dusts, Viruses, Bacteria
Non-ferrous materials,
glass, ceramics, grit
rej ects
Air Classification
Particulates (Organic
and Inorganic), Dust,
Viruses, Bacteria
Cof iring
Particulates (S0X, NOx),
Hydrocarbons, Volatile Metals,
Volatile Organic Compounds
Fly ash (collected in
abatement device), fly
ash contaminants such
as trace elements
Bottom Ash
Removal
Particulate,
Metals Trace
Elements,
Chlorides,
Sulfates, Phos-
phates, Phenolics
Organics
Particulates, Metals,
Trace Elements, Chlor-
ides, Sulfates, Or-
ganics, Phenolics,
Phosphates
-------
of cofiring coal and RDF. Recent evaluation of emissions was con-
ducted on the utilization of shredded and magnetically separated
municipal refuse to supplement high-sulfur coal as a fuel in a
stoker-fired boiler at the Columbus, Ohio, Municipal Electric Plant
(Vaughn et al. 1978). Emissions data based on evaluations of the
Ames, Iowa, resource recovery and energy producing facility is also
available (Even 1977; Hall et al. 1977b, U.S. Department of Energy
1979). Emission evaluation from the RDF preparation plant and cofir-
ing process has also been conducted at the St. Louis, Union Electric
resource recovery and energy producing demonstration project (Fiscus
1977a; 1977b). Physical, chemical, and microbiological analyses of
dusts at the National Center for Resource Recovery's equipment test
and evaluation facility have been published (Duckett 1978b). Based
on the above studies, certain conclusions concernings emissions can
be made.
• Hazardous pollutants such as zinc, copper, and lead, are
emitted in larger concentrations when RDF is fired with
coal.
• Chloride emissions increase when RDF is fired with coal.
• Sulfur dioxide emissions are lower with cofiring than with
coal alone.
• Increased bottom ash generation and associated disposal
problems are associated with cofiring.
• Dust and particulates generated during refuse processing are
primarily fibrous organics. Particulate removal devices are
deemed necessary.
• Bacteria and fungi have been identified as components of
dusts from raw refuse shredding operations. However, the
use of proper control techniques can reduce the con-
centration of these components significantly.
• The use of dust control equipment at Ames caused a marked
reduction in the number of colony-forming bacterial units.
• Boilers equipped with electrostatic precipitators come
closer to meeting emission standards than do boilers equip-
ped with mechanical collectors or wet scrubbers. Cofiring
in conventional boilers may require more efficient particu-
late collection than without RDF..
• A decrease in the performance of the electrostatic precipi-
tator was noted at St. Louis during cofiring. This decrease
299
-------
is attributed to an 8 percent increase in gas flow rate and
increase in flyash and gas composition. The increased emis-
sions were particulates in the less than 10 micron category,
but not less than 1 micron.
• The quantity of water effluent from RDF preparation proces-
ses is small and not of major concern as a water pollution
potential.
300
-------
SECTION II - POLLUTANTS AND DISTRUBANCES
The purpose of cofiring RDF with coal is to productively use a
substance now discarded and to mitigate solid waste landfill disposal
problems. An added benefit is fossil fuel conservation. The envi-
ronmental benefits obtained from fossil fuel and landfill areas con-
servation, materials recovery, reduced leachate contaminant levels
and lower S0X stack emissions must be balanced against increased
particulate, volatile metals, and bacterial and hydrocarbon emis-
sions. Emission standards for cofiring have not been developed and
present Federal standards on coal-fired boilers continue to apply.
It does seem likely that the emissions from the cofiring process can
be brought under compliance, especially for particulate removal.
This would probably require minor additional expenditures for abate-
ment equipment, particularly if ratios of RDF to coal increase.
AIR EMISSIONS
Dusts
Dusts primarily emanate from shredder, air classifier, and com-
bustion operations. Airborne dusts generated from processing refuse
have been reported from pilot studies conducted at NCRR's equipment
test and evaluation facility (ETEF). Table 9 presents the results of
such studies. Dusts above 10 micrometers in particle size are not
considered to reach lower lung passages. Microscopic examination of
these dusts indicate that they are organic fibrous materials with
particulates attached to them. No evidence of asbestos, lead, or
cadmium was detected in the emissions. Table 10 presents the results
of physical/chemical analysis performed on nonrespirable dusts
collected from NCRR's ETEF facility to determine the ratio of organic
to inorganic fractions. It is important to remember that data in
Tables 9 and 10 are derived from pilot plant trials and are designed
only to provide general information on characteristics of dusts. The
actual production of RDF has many variations in unit operations which
could yield different results than those presented for the production
of densified RDF. More recently, characterization of airborne
emissions from MSW processing facilities was done by Midwest Research
Institute at Outagamie County, Wisconsin, and Baltimore County,
Maryland (Midwest Research Institute 1979). Emissions from the
shredders, transfer conveyors, and magnetic separators were cate-
gorized at Outagamie County. At Baltimore County, emissions near the
magnetic separator over the tipping floor, inside the processing
building, and above the shredder were characterized.
Data collected were on particulate concentration, size
distribution, trace metals and asbestos.
301
-------
TABLE 9
AIRBORNE DUSTS FROM REFUSE PROCESSING
3
Concentration (mg/m )
Site
(A)
(B)
(C)
(primary
(aluminum)
(d-RDF
Average
shredder)
separator)
room)
Overall
Before Plant Total
1.60
0.39
0.73
0.91
Operation „ ,
Respirable
1.27
0.25
0.38
0.63
Nonrespirable
0.33
0.14
0.35
0.27
During Plant Total
37.79
13.71
32.86
28.12
Operation pliable
3.97
2.46
3.83
3.42
Nonresp irable
33.82
11.25
29.03
24.70
SOURCE: Duckett 1978a.
-------
TABLE 10
ORGANIC AND INORGANIC PERCENTAGES OF DUSTS FROM
REFUSE PROCESSING OPERATIONS
Site*
% Organic
% Inorganic
% Organic
% Inorganic
Cone.**
mg/m3
a
59.3
40.7
1.5
15.98
71.9
28.1
2.6
51.50
61.3
38.7
1.6
37.04
b
55.0
45.0
1.2
19.24
70.0
30.0
2.3
9.98
50.7
49.3
1.0
7.77
c
58.0
42.0
1.4
44.65
53.9
46.1
1.2
14.72
56.5
43.5
1.3
27.71
*Site Code: a ¦ shredder
b " aluminum magnet
c ¦ d-RDF room
SOURCE: Duckett 1978a.
303
-------
Data on particle concentration indicate that particle concentra-
tion is not a danger at either the Outagamie County or Baltimore
County plants, based on current TLV's. Figures 10 and 11 show
graphically the dust levels at the four test locations at Outagamie
and Baltimore Counties, respectively. The highest level of particle
concentration was at location 4 at Outagamie County on day 2 with
6,617 mg/Nm^. As explained below, the level of trace metal concen-
tration was low enough that the only consideration is nuisance dust,
which has a TLV of 10 mg/m3. The highest average for the 4 days is
5.546 mg/m3, again at location 4, at Outagamie County.
Trace metal analysis at the two locations is shown in Table 11.
In all cases, the amount of toxic metals was well between their
respective threshold limit values.
The results indicate that implant air emissions tests do not
appear to be health hazards (Midwest Research Institute 1979).
Airborne Bacteria
Biological contaminants occur in air as aerosols either as
single clumps of organisms or dust particles with microorganisms
adhering to them. Microbiological analyses suggest that bacterial
concentrations recorded in and around resource recovery plants tend
to be on the high side of the range of concentrations recorded in
other settings. An illustration of this point is provided in Table
12. The data does not allow for direct comparison due to variations
in sampling techniques. However, the trends are worthy of note.
Airborne aerobic bacteria can be classified into pathogenic and
nonpathogenic bacteria and fungi. A more important classification
indicating contamination by human and animal feces, but not neces-
sarily pathogenic, are fecal coliform and streptococci. Table 13
presents data from analysis of microbiological aerosols at resource
recovery plants. Wide variations in aerobic concentrations are due
to location of samplers, origin of refuse, and type of processing
involved. The high ratio of fecal streptococci to fecal coliforms
indicates that enteric organisms have animal rather than human
origin. The studies referenced above and the data collected are
only trend indicators and suffer from a lack of standard sampling
techniques and also from high process variability.
Bacterial emissions have been quantified based on test work done
at the St. Louis, Missouri, RDF demonstration facility. Bacterial
levels were evaluated for:
• air streams emitted from the Air Classifier Cyclone
304
-------
n
Shredder Output
Conveyors 1 to 2
Magnetic Separator
Shredder Input & Drag Conveyor 1 to
I" ^ — I I I I I I 1 I I
1234 1234 1234 1234
Day 1 Day 2 Day 3 Day 4
Location
Test Day
: Midwest Research Institute 1979.
FIGURE 10
PARTICLE CONCENTRATION VERSUS DAY BY LOCATION—
OUTAGAMIE COUNTY
-------
co
o
o>
CO
cn
n3
S-
-M
£
CD
O
c
o
o
a>
r—
U
S-
ftJ
D_
Mag. Sep.
Process Build
Tipping Floor
Shredder
Pi
•
•
•
1
:• i—i
1
¦
*3
a
SOURCE:
12 3 4
Day 2
Location
Test Day
Midwest Research Institute 1979.
FIGURE 11
PARTICLE CONCENTRATION VERSUS DAY BY LOCATION-
BALTIMORE COUNTY
-------
TABLE 11
TLV OF METALS ANALYZED VERSUS CONCENTRATION
TLV
Highest Concentration mg/Nm
Metal
Baltimore County
Outagamie County
Antimony
0.5
0.002
Arsenic
0.5
0.00007
Barium
0.5
0.0018
0.003
Beryllium
0.002
0.000013
Cadmium
0.1
0.0001
0.00014
Chromium
0.5
0.0134
0.00648
Copper
1.0
0.0019
0.00158
Lead
0.15
0.0052
0.018
Mercury
0.05
0.000037
Selenium
0.2
0.000007
Silver
0.01
0.000036
Titanium
0.00134
Vanadium
0.01
0.000296
Zinc
5.0
0.0037
0.00788
Asbestos: The 12 millipore filters from Outagamie County were sectioned
in MIR's laboratory and shipped to an independent laboratory for physico-
chemical morphology electron microscope analysis for asbestos. The three
filters with the most sample were analyzed and no asbestos was found. Based
on two previous similar investigations for asbestos, which found only 0.46%
and 0.0% by weight of sample,—the decision was made not to analyze the
remaining nine filters or test for asbestos at Baltimore County.
St. Louis Demonstration Final Report, MRI Project No. 4033-L, page 64.
U Evaluation of Fabric Filter Performance at Browning Ferris Industries/
Raytheon Service Company Resource Recovery Plant, Houston, Texas, MRI
Project No. 4290-L(13), page 44.
307
-------
TABLE 12
AIRBORNE MICROORGANISMS AROUND
WASTE PROCESSING FACILITIES
Concentration of Microorganisms*
(No. of organisms per ft.3)
Location
Total Aerobic
Organisms
Total
Coliforms
Fecal
Coliforms
Reference
Urban Air
14-170
28, 29
Schools/Offices
95
29
Factories
113
29
Sewage Treatment Plants
9-1200
30-33
Spray Irrigation Systems
46-300
3-9
34, 35
Refuse Collection Truck
7-25,000
0-25
2-5
10, 27
Incineration Plants
40-788
36
Resource Recovery Plants
134-280,000
63-590
4-500
6, 10, 19
*Blanks indicate "not reported".
SOURCE: Duckett, J.E. 1978b.
308
-------
TABLE 13
REPORTED CONCENTRATION OF AIRBORNE
MICROORGANISMS WITHIN RESOURCE RECOVERY PLANTS
Concentration (number of organisms/ft.^)
Total Total Fecal Fecal
Study Aerobes Coliforms Coliforms Streptococci Reference
St. Louis Study 140-28,000 1-6 1-2 1-14 10
Richmond Study 134-360 63-112 4-69 390-540 6
ETEF Study 24,000-280,000 20-590 12-501 330-1850 19
SOURCE: Duckett, J.E. 1978b.
309
-------
• air streams from the Hammermill Cyclone
• air streams from the RDF storage bin
In the early studies, viral emissions were evaluated for the
same streams with the exception of the RDF storage bin. Both
enteroviruses and bacterial viruses were evaluated. Tables 14, 15,
and 16 present the results of bacterial and viral emissions as well
as comparative data for indicated ambient air removed from the plant.
These studies indicated that further test work to evaluate the signi-
ficance of reported bacterial and and viral levels is required to set
exposure limits, and confirm the emission levels reported.
• Bacterial levels were several orders of magnitude higher than
in suburban ambient air samples.
• Bacterial concentrations in the air classifier cyclone
exhaust is the largest emission source. If this source were
controlled for particulate removal, it would reduce bacterial
emission levels.
• Since most municipal solid waste contains some human and
animal waste, the potential for viral exposure exists.
Particulates
Particulate emissions occur during both the production and
cofiring of RDF. To date, quantification of particulate emissions at
the RDF production facility has been limited to specific pieces of
equipment, i.e., the air classifier and hammermill cyclone.
Emissions during cofiring have been quantified for stack emissions
only. The following discussion presents data for these two sources.
RDF Production Facility. Test work conducted at the St. Louis
demonstration resource recovery facility sheds some light on particu-
late emissions from the air classification and shredding operations.
Table 17 shows emissions from the air classifier and hammermill
cyclone. Particulate emissions were evaluated for both regular
refuse grind (1.5 inches mean particle size) and fine refuse grind
(.75 inches mean particle size) RDF production operations. Figure 12
and 13 present particle size distribution data for air classifier and
hammermill cyclone discharge particulates. Based on this data,
certain conclusions can be made.
• Mass emission rates from the air classifier cyclone dis-
charge ranged from 19.9 to 79.9 lbs/hour with an average of
60 lbs/hour, indicating the need to control emissions during
regular grind operations.
310
-------
TABLE 14
U)
BACTERIAL AND VIRAL EMISSIONS FROM
CLASSIFIER AND HAMMERMILL CYCLONES
fccfrU tof «tr«tl—
km nfm FkiI SalasMlla Inttrwlnu tarnotr.tloM
procoii^ Hiu MMiga kcutla collfom prtxne (po«.J Tutl li UC-K] 1. K1 kcuiitftaii b>
Mat Ho. tatm Air flow —factor cwat ctlU 1. coll
tiu/hr) (W/» k/-3 fc»/ht (count./di^3) (nni/di*P) _asLii2!S_ IClZ*rrg/m* rrv/i frv/p3 iVk*/"1
i. AM eyclwit
1
2
3
27,000 2,100
18.1 13.44 0.25 11.f 0.6* (6.700) (530) Ntg.
& t*/ 2 IS * 640,000 164,000
370,000,000 29,000
29.8 13.40 0.49 33.5 1.13 (254,000,000) (20,000) Po». SI ft 24,700 2 17,410 * 24,700 % 17,410 110,000 71,0
240,000,000 > 110,000
29.1 13.40 1.24 14.9 U99 (318,000,000) O 134,000) Foa< ¦ 2 485-48,500 872-87,000 & & 84,000 109,000
k. M ciclwt/
I
730,000,000 2,900
29*8 0.78 1.17 3.3 0.11 (848,000,000) (3,390) To*. C 1 1- 7.35 9 90,000 109,000
2
25.7
3
140,000,000 O,000
0.78 1.10 3.1 0*12 (177.000,000) (45,900) M%. ~ 171,232 - 193,52* & & 27.000 28,000
130,000,000 9,300
25.7 0.78 1.40 3.9 0.15 (180,000,000) (13,100) Be*. ~ 100 - 145 4' 900.000 2,119.000
|/ fetal |»1
-------
TABLE 15
CONCENTRATION OF BACTERIA AND VIRUSES
IN SUBURBAN AIR
Ikit Mo.
Cat Tat* wight
WfM of filters'
-1=H— fc!
821
3.42
Bacteria concentreHon
Fecal
Bacteria collfora
(COIWU/^) (MFN/o1)
(473) (<0.141}
Sa Wnnella
present (poi.) Enterovirus concentration
absent (neg.) Plaques per
and aroup 1/2 filter pad Ffl)/s^
N=R-
< 0.0198
tacterlopliaae for E. coll
Phage per
1/2 filter pad Fhage/a^
< 0.0035
3.30
(17) (< 0.141)
Heg.
< 0.0184
< 0.0035
U>
l—'
N3
1,017
643
3.51
3.52
(28)
(147)
(< 0.141)
(< 0.212)
Heg.
Meg.
< 0.0156
< 0.0247
< 0.003S
< 0.0035
Blank filters
Bacteriological contamination level assuming that 850 m? of sterile air had
passed through blanle flltecfe'
Hone
3.50
7
Neg.
0
Hot run
None
3.31
254
Meg.
0
Mot run
Hone
3.48
< 0.035
Neg.
Hone
3.56
0.035
Neg.
None
3.53
< 0.035
Neg.
a/ Final weight of filter not determined because purpose of test was to determine biological contaalaaae comseatretioaa oa tha Sea is of quantity
of air saapled (at1),
b/ Aastvptloo ada In order to compare blanks vlth actual saaples.
SOURCE: Fiscus 1977.
-------
TABLE 16
BACTERIAL EMISSIONS FROM RDF STORAGE FACILITY
Bacteria concentration
Fecal
No.
Gas sampled at
1.7 n^/min rate
(m3)
Particulate
collected
(R)
Bacteria
counts/gram
(counts/m3)^
coliform
MPN/gram
(MPN/m3 )£/
1
306
6.01
248,000,000
(4,873,000)
1,400
(28)
2
296
8.71
600,000,000
(17,657,000)
29,000
(862)
3
311
1.08
145,000,000
(494,000)
512,000
(1,783)
4
442
52.53^
213,000,000
(25,073,000)
1,600
(191)
Salmonella
present (pos.)
absent (neg.)
and group
Neg.
Neg.
Pos. 0
Neg.
a/ Higher weight collected, probably due to fact that storage bin exhaust fan was on and distributing
conveyor was on, which was not the case in Tests 1 through 3.
b/ Calculated value:
/countsX y /grams of particulate^
graa J ' a3 of gas sampled J
SOURCE: Fiscus 1977.
-------
TABLE 17
PARTICULATE EMISSIONS FROM AIR CLASSIFIER AND HAMMERMILL CYCLONES
AM cyclaw ilxfciftt cha"« "***>
AOS cjrcloo* tfiaclurg*
«m liw («u>
«ki/»
hrtioiUu MMtitntlM
(|/lk)) I.1M
hrtic«Ut« HtuiMM
(kf/kr) 9.0)
•efuM pmtiitai rat*
0%/hr) 32.1
Aliilon rat*
(fcft/*) 0.2*
11.00
0.441
29.0
OvSH
29.0
mw i m ! 11 i rclow
tilt Ito. 4 T»*t Ito. 7
1.497
51.52
1.330
10.95
1.755
07.99
W crclo—
hrticulat* aitiiOM
(k*/hr)
0cf«M proctulat rat*
CM»/kr)
binlM rat*
Ckt/m)
0.005
31.1
1.230
< 0.0009
20.9
0.112
1.371
3.01
20.9
0.70
1.147
3.17
29.0
0.110
0.70
3.00
2 5.7
0.120
1.394
3.90
25.7
SOURCE: Fiscus 1977a.
-------
100.0
p 1 TTT
10.0
a
o
i-
o
<
I—I
Q
a 1.0'
QL
<
D-
t—i i i i i i i—n—it
REGULAR GRIND
Run
O 8
A 9
FINE GRIND
• 26
~ 27
¦ 29
0.1
0.01 0.1
I I I I I L
J—L
1 2 5 10 20 40 60 80 90 95 98 99
WEIGHT % LESS THAN STATED SIZE
X
99.9 99.99
SOURCE: Fiscus et al. 1977.
FIGURE 12
PARTICLE SIZE DISTRIBUTION FOR AIR
CLASSIFIER CYCLONE DISCHARGE
315
-------
100.0
CO
I 10.0
a
a:
LU
s
<
t—H
Q
LU
_l
0
1 1.0
<
a.
REGULAR GRIND
Run
O10
All
FINE GRIND
¦ 28
O.lL
X
I I I I L
II 1 I I I I I i i
_L
0.01 0.1 1 2 5 10 20 40 60 80 90 95 98 99 99.9 99^99
WEIGHT % LESS THAN STATED SIZE
SOURCE: Fiscus et al. 1977.
FIGURE 13
PARTICULATE SIZE DISTRIBUTION FOR
HAMMERMILL CYCLONE DISCHARGE
316
-------
• Eighty percent of the particulates captured in the air
classifier cyclone discharge were greater than 10 microns
for both regular and fine grind operations.
• Emission rates for the air classifier cyclone discharge
during fine grind operations was almost twice (125 lbs/hr)
the average of regular grind emissions.
• Hammermill cyclone discharge (about 7 lb/hr) was consider-
ably less than the air classifier cyclone discharge. Eighty
percent of the particulate matter was greater than 10
microns.
• Air emission control devices will be required on air
classifier de-entrainment cyclones.
RDF Cofiring Facility. Particulate emissions are of concern in
the cofiring combustion process, particularly as they related to
installed abatement devices. Analyses of particulate concentrations
and emission rates in uncontrolled emissions as well as size distri-
bution analyses in stack particulates were made at the Columbus,
Ohio, Municipal Electric Plant. Table 18 and Figure 14 indicates a
greater amount of larger particulates in the uncontrolled emissions
with increasing quantities of RDF fired. ' These data, however, may
have been influenced by less than optimum distribution of RDF on the
furnace grates. Table 18 indicates that the addition of refuse could
result in either an increase or decrease in uncontrollable particu-
late loading. Furnace combustion conditions may be controlling
factors.
Detailed particulate emission data have also be obtained from
the St. Louis demonstration project. The cofiring of RDF at St.
Louis did have an effect on the electrostatic precipitator. It was
determined that increased gas flow rate (8 percent), change in fly
ash resistivities, and increased particulates in the 1.0 and 10 m
size range reduced control efficiency. Corrective measures such as
installing auxiliary control devices, increasing precipitator size,
and reducing cofiring ratios need evaluation prior to inception.
Figure 15 shows uncontrolled emissions particulate size data for coal
and coal/RDF systems from suspension-fired utility boiler tests at
Union Electric in St. Louis.
Figure 16 presents the results of particulate analyses for
various RDF:coal ratios and boiler loads. Test work was carried out
by both Union Electric, the host utility, and Midwest Research
Institute. The average inlet loading to the precipitator was 4.90
grams/DNCM while the average outlet loading was 0.190 grams/DNCM (90
percent efficiency). This data indicates that compliance with the
more stringent standards was not achieved above 100 MW rated capacity
317
-------
TABLE 18
UNCONTROLLED PARTICULATE EMISSION FROM
COLUMBUS MUNICIPAL ELECTRIC PLANT
RUN NUMBER
FUEL
STEAM FLOW
(lb/hr)
PARTICULATES
(lb/hr)
PARTICULATES
(gr/scf)
1
3% S Coal
85,000
378
1.714
2
3% S Coal + 60 wt%/w/o Refuse
80,000
352
1.295
3
3% S Coal + 60 wt%/w/o Refuse
80,000
316
1.271
4
3% S Coal
75,000
330
2.37
5
3% S Coal + 53 wt%/w/o Refuse
78,000
346
2.03
6
3% S Coal 4- 52 wt%/w/o Refuse
87,000
347
2.71
SOURCE: Vaughn 1978.
-------
100
§ 80
Q
w
VO
LU
Nl
i—i
CO
<
~c
a:
UJ
h-
<
UJ
cc
CO
O
CC
UJ
CL
60
40
20
0
O
X
~
High(5.4%)Sulfur Coal
High(5.4%)Sulfur Coal plus
27 weight percent refuse
High(3.0%)Sulfur Coal plus
36 weight percent refuse
1.0 10
PARTICLE SIZE, Microns
SOURCE: Vaughn, Krause, Cover, Serton, and Boyd 1978.
FIGURE 14
PARTICULATE SIZE DISTRIBUTION FROM COAL + RDF COFIRING
(UNCONTROLLED PARTICULATES—STOKER FIRING) —
COLUMBUS, OHIO, MUNICIPAL ELECTRICAL PLANT
-------
99.8
99.99 99.9
501 T~
10
QL
U1
s;
<
Q
O
ce.
<
a.
1.0
0.1
99 98
TT
95 90
n—r
80 70 60 50 40 30
~~1 1 I I I I
20
~r
10
oo
<£>
£
A
A
<»
o*
A
o»
J I I I
0.2 0.05
5 2 1 0.5 I 0.1 I 0.01
"I I 1 ill! 150
10
1.0
Coal-
Only
O
0
A
Coal &
Refuse
• I 1973 Tests
A J 1974-75 Tests
_L
0.1
99.81 99.99
99.9
0.01 | 0.11 0.5
0.05 0.2 1
2 5 10 20 30 40 50 60 70 80 90 95 98 99
WEIGHT % LESS THAN STATED SIZE
SOURCE: Shannon, Fiscus, Gorman 1975.
FIGURE 15
PARTICULATE SIZE DISTRIBUTION FROM COAL + RDF
COFIRING (UNCONTROLLED PARTICULATES — SUSPEN-
SION FIRING) — UNION ELECTRIC PLANT, MISSOURI
320
-------
'(8)
0.50
0.200r-
2 0.150
l£)
o
o>
to
z
o
to
CO
LLl
£ 0.100
<
_j
3
O
0£
<
Q.
0.050
Missouri
Standard
•(0)
„ (0).
(9)
0.025-
(0)^^(27)
«dis
» » i
•(10)
•(9)
08k.
^8)--(9)
(9)«l0)
.(5)
—^To^
r (10)
^0)
-J 1 1 I I L
•(0)
•(18)
J9)
'(5)
0.40
•(7)
•(8),(1°)
•(8)
0.30
0.20
c/>
z
o
CO
t/i
<
-J
Z3
o
a:
<
a.
Federal
»(0)
Standard
0.10
J L
J L
70 80 90 100 120
BOILER LOAD,Mw
130 140
SOURCE:
Shannon, Gorman, Fiscus 1975.
FIGURE 16
CONTROLLED PARTICULATE EMISSIONS AS A FUNCTION
OF BOILER LOAD FOR VARYING COFIRING RATIOS-
SUSPENSION FIRING—UNION ELECTRIC PLANT,
MISSOURI
321
-------
of the boiler regardless of the fuel mix and that cofiring did accen-
tuate the problem. Corrective measures cited earlier would alleviate
the problem.
Extensive testing of particulate size distribution and emission
rates were also made on two stoker-fired boilers at the Ames, Iowa,
Resource Recovery plant.
It is also important to recognize that furnace combustion condi-
tions may play an important role in resulting particle size distribu-
tion. This concept needs further evaluation. Table 19 shows a
comparison of controlled particulate emissions from a stoker-fired
boiler at Ames, Iowa, equipped with a mechanical multicyclone collec-
tor versus a suspension-fired boiler at St. Louis equipped with
electrostatic precipitator. The information indicates that to meet
Federal particulate standards, more efficient particulate collectors
than mechanical devices are needed. Mechanical collectors appear to
be as efficient with coal as with RDF and coal. Precipitator perfor-
mance appears to decrease with cofiring for reasons cited earlier.
Figures 17, 18, and 19 show data obtained on emission rates and
multiple cyclone efficiency from the Ames, Iowa, plant. It appears
that collector efficiency initially increases, then decreases. This
is attributed to large particulate load with increasing RDF in the
initial stages followed by a state of increased air flow (transport
air with RDF that reduces collector efficiency).
Results of controlled particulate emission rates as a function
of RDF and stream loading indicate an increase in particulate emis-
sions with increased percent RDF. Increase in uncontrolled particu-
lates is also evidenced and is attributed to increased transport air
and overfire air for proper combustion. Figure 20 shows the rela-
tionship of ash content of RDF versus particulate emission. Data
indicates a linear increase in emissions with increasing ash content.
Trace Elements
Some of the trace elements measured in RDF and coal are listed
in Table 20. Zinc compounds enter the combustible fractions of MSW
from several sources. Zinc oxide is used in paper as a filler and
for photocopying, in inks as an extender, in plastics as a
stabilizer, in pigments, and in automobile tires. All these sources
could contribute to zinc in the combustible fraction with the
exception of automobile tires which are generally not collected with
MSW.
The amount of cobalt and nickel found in combustible MSW can be
primarily accounted for from unprinted paper stock and pigments.
Cadmium compounds find their way into MSW via pigments in paints and
322
-------
TABLE 19
COMPARISON OF PARTICULATE EMISSIONS
FROM STOKER AND SUSPENSION-FIRED BOILERS
Federal Standard
Coal Only
Air Force - outlet
Ames - inlet**
- outlet
Columbus - outlet
St. Louis - inlet
- outlet
Coal - RDF
4
Air Force - outlet
Ames"*" - inlet
- outlet
3
Columbus - outlet
2
St. Louis - inlet
- outlet
RDF Supplied Heat
40-45%
20-25%
20-25%
9-10%
Kg/GJ*0.043 Reference
0.39 24
3.3 11
0.9 11
1.4 30
1.74 36
0.56 (.046)*** 36
0.40 24
3.7 11
0.7 11
0.53 30
1.62 36
0.76 (.055)*** 36
Notes:
*The unit GJ in the boiler standard is a gigajoule, that is 10^ kJ
or about 950,000 BTU.
**Inlet refers to the uncontrolled emissions at the inlet to the
pollution control equipment; outlet refers to controlled emissions.
***Numbers in parentheses refer to measurements taken while boiler was
operated at or below rated capacity.
Facility
1. Ames
2. St. Louis
3. Columbus
Boiler Type
Stoker Fired;
also Ames has 2
stoker travelling
grate types and 1
tangentially fed
with a specially
modified hold-up
grid to obtain
higher RDF com-
bustion efficiencies.
Suspension
Abatement Device
Cyclones (Multiple);
Ames also has electro-
static precipatator on
its tangentially fed
boiler.
Stoker Fired
4. Wright-Patterson AFB Stoker Fired
SOURCE: Duckett, J.E. 1978c.
Electrostatic
Precipitator
Cyclones
Cyclones
323
-------
~ 2.0
1.0
O ~ 60 PCT LOAD
~ ~ 80 PCT LOAD
& ~ 100 PCT LOAD
OPEN SYMBOLS ~1976 DATA
SHADED SYMBOLS ~ 1 9 7 7 DATA
10 20 30 40 50
REFUSE DERIVED FUEL HEAT INPUT, PERCENT
60
SOURCE: Hall 1978a.
FIGURE 17
UNCONTROLLED PARTICULATE EMISSION RATE
STOKER FIRING—AMES, IOWA
324
-------
2.4
2.0
O -v 60 PCT LOAD
~ ~ 80 PCT LOAD
A ~ 100 PCT LOAD
OPEN SYMBOL ~ 1976 DATA
'HADED SYMBOL ~ 19 7 7 DATA
CONTROLLED EMISSION
BOILER UNIT 5
1 .6
REFUSE DERIVED FUEL HEAT INPUT, PERCENT
SOURCE: Hall 1978a.
FIGURE 18
CONTROLLED PARTICULATE EMISSION RATE
STOKER FIRING-AMES, IOWA
325
-------
60
PARTICULATE COLLECTOR EFFICIENCY
BOILER UNIT 5
40
20
O -r 60 PCT LOAD
~ ~ 80 PCT LOAD
A ~ 100 PCT LOAD
OPEN SYMBOLS ~ 1976 DATA
SHADED SYMBOLS ~ 197 7 DATA
1
1
10 20 30 40 50
REFUSE RECIEVED FUEL HEAT INPUT, PERCENT
60
SOURCE: Hall 1978a.
FIGURE 19
CYCLONE COLLECTION EFFICIENCY-AMES. IOWA
326
-------
2.0
1.6
1.2
0.8
0.4
cm
<
0.0
^ I
o
<
h—
to
O—60 PCT LOAD
~—80 PCT LOAD
A —100 PCT LOAD
OPEN SYMBOL 1 976 DATA,, IOWA COAL
SHADED SYMBOL 1 977 DATA,, IOWA-WYOMING COAL
NO FLAG— O PERCENT RDF
SINGLE FLAG—20 PERCENT RDF
DOUBLE FLAG—50 PERCENT RDF
N/AFTER CLEANING SLAG SCREEN AND
SUPERHEATER (1976 DATA)
or1
or1
on
~
o
erf1
6.76
1
7-
COMPLIANCE LEVEL
I I I
—£&-
1
8 10 12 14 16 18
ASH CONTENT OF FUEL, PERCENT
20
22
SOURCE: Hall et al. 1978b.
FIGURE 20
PARTICULATE EMISSION RATE AS A FUNCTION OF RDF ASH CONTENT
327
-------
TABLE 20
TRACE ELEMENTS IN COAL AND RDF
ELEMENT RDF (ppm by weight)
K 1470
Ca 10200
Ti 1030
V 100
Cr 13.5
Mn 131
Fe 2270
Ni 3.3
Cu 123
Zn 445
Ga 11.4
Ge 2.1
Se 0.48
Rb 3.2
Sr 31.5
Pb 605
COAL (ppm by weight) RDF/COAL
1270 1.2
13100 0.78
590 1.8
73 1.4
23.8 0.57
94 1.4
15200 0.15
10.8 0.31
13.4 9.2
52 8.6
2.5 4.6
7.5 0.28
0.2 2.40
4.2 0.75
71 4.4
67 9.0
SOURCE: Hall 1977a.
328
-------
plastics and as stabilizer compounds. Lead and chromium found in
paper and plastics are primarily from pigments whereas copper appears
as wire, screen and tubing.
Extensive work on characterizing the sources of metals in the
combustible fraction of MSW was conducted by the Bureau of Mines
(U.S. Department of the Interior 1978).
RDF Production Facility. Table 21 presents the results of trace
element analyses conducted on air classifier discharge samples both
in terms of concentration per gram of particulate and per unit volume
of air discharged. Examination of this table indicates Rb and Zn
have the highest concentration but were below their TLV. Elemental
concentrations downwind of the plant indicate the Pb, Cr, and Zn
concentrations were increased from air classifier operations. Proper
particulate emissions control of the air classifier discharge would
alleviate the problem.
Extensive trace elements test work was done at the St. Louis
facility to evaluate trace elements in particulate emissions from
exhaust stack. Uncontrolled and controlled particulate emissions
were analyzed for trace elements from the cocombustion of coal and
refuse. Table 22 shows the average concentration of trace elements
in coal and RDF and in emitted particulates and gases. Table 23
shows the results of emissions analyses on trace elements before and
after the electrostatic precipitator at the Union Electric Power
Plant in St. Louis. Based on the data obtained, the following
conclusions regarding trace elements in emissions from the Union
Electric Plant can be made:
• Trace element emissions increased at the electrostatic pre-
cipitator outlet as a result of cofiring. Elements such as
Be, Cd, Cu, Pb, Hg, Ti, and Zn exhibited increases.
• Most pollutant increases were associated with elements that
exist in higher concentration in RDF than in coal.
• Some of the pollutants were emitted in vapor form, thus
escaping removal by the precipitator. Sb, As, Se, Hg, Be,
CI, and F may be emitted as gases.
Trace elements analysis on uncontrolled particulates from the
Ames, Iowa, Resource Recovery Plant (Even et al. 1977) and the
Columbus, Ohio, Resource Recovery project showed similar trends to
that observed at St. Louis. Cofiring of refuse and coal at Columbus
(Table 24) also indicated:
329
-------
TABLE 21
TRACE ELEMENTS IN AIR CLASSIFIER DISCHARGE
TRACE ELEMENT
CONCENTRATION (jig/g)
uL£iri£ui 1 unTir i
Sb
As
Be
Cd
Cr
Cu
Pb
Hg
Se
Zn
Ba
Air Classifier 1-3
< 5.0
22.0
0.22
19.0
83.0
74.0
430.0
0.93
30.0
680.0
130.0
Air Classifier 2-3
4.2
9.1
0.18
7.0
78.0
60.0
370.0
0.35
28.0
520.0
94.0
Air Classifier 3-3
7.7
5.7
0.23
4.6
1 97.0
100.0
400.0
<0.40
25.0
740.0
| 130.0
TRACE ELEMENT CONCENTRATION Qxg/m3)
Air Classifier 1-3
1.3
5.8
0.058
5.0
21.7
19.0
113.0
0.24
7.9
178.0
34.0
Air Classifier 2-3
1.5
3.3
0.065
2.5
28.0
21.5
133.0
0.13
10.0
187.0
33.7
Air Classifier 3-3
2.1
1.5
0.062
1.2
26.0
27.0
107.0
0.11
6.7
198.0
34.8
TLV
50.0
50.0
2.0
50.0
100.0
200.0
150.0
50.0
200.0
5,000.0
500.0
RDF PLANT
Upwind
11/10/76
b/
<0.007
0.00017
0.002
<0.05
0.44
0.69
b/
b/
0.30
Downwind
11/10/76
b/
0.015
0.00056
0.007
0.17
0.39
2.25
b/
b/
1.96
Downtown
11/10/76
y
< 0.007
< 0.00010
0.0005
< 0.05
0.10
0.83
b/
b/
0.07
SOURCE: Fiscus 1977a.
-------
TABLE 22
COMPARISON OF TRACE ELEMENTS CONCENTRATIONS OF
COAL AND COAL + RDF EMISSIONS
u>
Average concentration of pollutants in
coal and RDF Average concent rat I mi of List of pollutants «4ilch
pollutants In emitted particulate data imflcated may partly
Relative
concentration
Coal-only Coal 4* Kl»F Relative
lement
Coal (ut/i)
RDF (uk/k)
(increase)
(IK!/it)
(iw/k)
lncrcasc
Measured
Sb
0.8, < 1
3.4X
V
42, 37
17
708
2 BO
Zn
53, 53
597
11X
IS0
^b/
1,500
Ht&f
NAC/
Br
72, 111
180
2X
Br
CI
CI
5,000, 4,870
4,930
*%,
F
123, 45
< 51
HA2
NA"
F
be owltted In vapor font
Susncctcd
Pb
Average Measured outlet
concentrations of
gaseous pollutants
Coal-only
(Ug/Nw1)
Sb 28.7
As < 7.5
Coal + RDF
(*WNm3)
< 1.54
< 7.2
IIS 21.7s'
Se 46.3
Br 5,760
CI 372,000
F 3,380
34.0£/
23.5
4,630
479,000
5,810
Relative
increase
1.5X
1.1X
I.7X
if Value Cor Sb and As is uncertain because SSMS shows higher value in RDF, which appears to be supported by increases In collected fly ash,
b/ Insufficient sanple for analysis.
j/ Hg vapor sampling was done only at the ESP inlet.
SOURCE: Fiscus 1977b.
-------
TABLE 23
TRACE ELEMENTS IN UNCONTROLLED AND CONTROLLED EMISSIONS
FROM COFIRING (UNION ELECTRIC PLANT, ST. LOUIS, MISSOURI)
lnV«t
Outlet
u>
u>
N>
Coal
Coal + RDF
Coal
Coal + RDF
m (cc/t. drv basis)
tests
tests
tests
tests
s^'
sO.33
<2
1.46
10.0
7.1
S4.7
162
36.0
Be
4,450
1,670
1,860
1,300
Be
4.4
10.8
10.3
12.7
Cd
4.8
8.7
29.6
25
Cr
217
233
624
293
Cu
121
206
209
228
Pb
131
853
583
982
US
0.61
2.3
*7.9
7.5
Se
21
9.0
42.1
y
Ag
10.4
2.7
29
6.4
T1
2,130
8,350
*1,620
5,470
V
357
104
708
280
Zn
287
1,110
1,600
1,500
Br"
140
289
1./
y
CI"
337—7
873^
y
y
F*
589,
<83
b/
NA
_a/ Results for Sb •»»<* As during coal-only tests arc suspect due Co arulysi* problems,
b/ Insufficient sample.
£/ Dy chloridinetcr*
d/ By ion selective electrode*
NA * Not «nulyzcd.
SOURCE: Fiscus 1977
-------
TABLE 24
TRACE ELEMENTS IN UNCONTROLLED EMISSIONS FROM COFIRING
(COLUMBUS, OHIO MUNICIPAL ELECTRIC PLANT)
High Sulfur Coal Coal + RDF Coal + RDF
Uncontrolled Particulates 2?% ^ ^ ^
Element (5.2% S) (3.32 S) + Coal (2% S) + Coal (3.8% S)
Nonmetals
S 2.2 1.6 3.7 3.9
CI <0.1 0.04 <0.1 0.09
C 27.3 ND 26.7 27.8
H 1.6 ND 1.5 1.7
H20 NCI ND NCI NCI
Major Metals
SI 5-10 7.5 5-10 5-10
Fe 5-10 6 5-10 3-5
A1 2-4 3 2-4 2-4
Ca 0.3 1 1.0 2-4
Mg 0.1 0.2 0.3 0.4
Na 0.1 1 1.0 1.0
K 1.0 1 1.0 1.0
Ti 0.1 0.3 0.2 0.2
Toxic Trace Metals
Pb 0.03 0.03 0.3 0.3
As <0.1 0.1 <0.1 <0.1
Cd <0.1 <0.1 <0.1 <0.1
Be 0.001 0.117 0.001 <0.0005
Other Trace Metals
Zn
0.05
0.3
0.3
1.0
Sn
<0.002
0.02
0.02
0.05
Mn
0.005
0.02
0.03
0.04
Ba
0.02
0.02
0.04
0.3
B
0.05
0.2
0.08
0.1
V
0.05
0.03
0.01
0.01
Mo
0.01
0.02
0.005
0.01
Cr
0.002
0.04
0.02
0.02
Zr
0.01
0.01
0.01
<0.01
Cu
0.005
0.1
0.02
0.02
N1
0.01
0.03
0.02
0.02
Co
0.005
0.01
0.005
<0.01
Sr
0.03
0.01
0.03
0.03
SOURCE: Vaughn, D.A., et al 1978.
333
-------
• increased concentrations of calcium, magnesium and sodium
• increased concentrations of sulfur, probably as a result of
interaction of SO2 from coal with particulate chlorides to
form sulfates
Gaseous Emissions (S0Y> N0V> CI)
RDF Co-Firing Facility. Table 25 shows the results of stack gas
analyses conducted on cyclone separator exhaust gases from the Col-
umbus, Ohio, Municipal Electric Plant. Results indicate that the
sulfur dioxide concentration was reduced as a result of the dilution
of high-sulfur coal with low-sulfur (0.25 weight percent) RDF. In
addition, alkaline elements such as Na, K, Ca, and Mg are capable of
forming metal oxides and then sulfates with sulfur dioxide and oxy-
gen, thus reducing sulfur dioxide emissions. Chlorides and N0X em-
issions were not present in amounts that would constitute emission
problems.
Figures 21 and 22 give N0X and S0X emissions from test work
done at St. Louis. Table 26 gives the chloride concentrations in
stack gases. These tests are representative of data obtained from
suspension firing of coal and RDF.
Similar data have been generated from test work done at the
stoker fired unit at the Ames, Iowa, test facility. Figures 23, 24,
and 25 show stack emissions from N0X, S0X and chloride as a func-
tion of RDF heat input and boiler load. Representative emission
standards for S0X and NOx are provided on Figures 23 and 24 for
comparative purposes. The following general conclusions can be drawn
from examining this data:
• NOx emissions showed a general decrease with increase in
percent RDF for stoker-fired boilers. The decrease was,
however, not significant for either stoker or suspension
fired equipment.
• S0X emissions decreased with increase in RDF for stoker
fired equipment.
• The sulfur content of the fired coal also affected S0X
emission levels.
• Chloride emissions for stoker- and suspension-fired boilers
increased with increasing percent of RDF at all loads.
Chlorides probably volatilized as HC1. A major source of
chloride emissions is from polyvinyl chloride used in plastic
bags.
334
-------
TABLE 25
STACK GAS ANALYSIS - CONTROLLED EMISSIONS
(COLUMBUS, OHIO MUNICIPAL ELECTRIC PLANT)
5.2 wt%
S coal
27wt%
refuse +
5.2 wt%
Scoal
3.2 wt%
Scoal
36 wt%
refuse +
3.2 wt%
S coal
42 wt%
refuse +
3J2wt%
Scoal
42wt%
refuse +
3.2 wt%
Scoal
50wt%
refuse +
2.6 wt%
ScoalW
50wt%
refute +
2Jwt%
Scoal
1 wt %
Scoal
Steam flow, Ib/hr
118,000
118,000
120,000
74,000
93,000
90,000
100,000
50,000
94,000
SO2, ppm
3,120
3,090
2,340
1,190
1,615
960
400(d)
760
720
SO3, ppm
68
61
12
20
27
2
ND
60
5
HQ, ppm
5
26
14
36
45
97
ND
103
45
NOx, ppm
48
27
210
127
214
94
180
ND
162
O2, percent
11.0
11.1
10.4
9.1
12.0
123
103
10.0
10.7
C02. percent
83
Sj6
9.6
10.5
7.7
6.0
83
7.0
10.5
CO, percent
0.004
0.021
<0.1
0.022
0.39
<0.1
0.20
<0.1
0.02
H2O, percent
10.9
10.1
9.4
8.6
83
7.2
9.2
ND
5.8
CH4, ppm
Nil
18
nd(»)
2
2
ND
19
ND
<1
C2H4.ppm
0.04
3
ND
0.2
03
ND
3
ND
<1
Vinyl chloride, ppm
Nil
Nfl
ND
Nfl
m
ND
Nil
ND
ND
Pirticulate, gr/scf
037
0.65
ijjoCb>
0.45
032
1.14
ND
ND
1.4200
U) NO ¦ not determined.
(b) CydonA (epmtois defective.
(e) Analytit of gnb ample.
(4 Mux tpedrumeter data - low In pwHaei of mitam.
SOURCE: Vaughn, D.A., et al 1978.
-------
0.35
CM
O
10
>"3 0 .
ID
O
CJ)
. 0.
00
1/7
C/0
0.30
25
20
x
o
0.15
0.10
0.05
. *(18)
• (18)
0(0)
FEDERAL
STANDARD
•(0)
0(9)
(i*(27)
" «(9)
(9)««(0)
•(0)
•(9)
o(o)
O(7-8)#(0)
0(9)
*(18)
-
-
.•(0)
(8-9)
(18)
• (9)
O (7-8) O#(0)
o(8)
•(0) -
-
0(5)
-
• (0)
0(7-8)
•(0)
- • EPA Van
O EPA Method
7
O (7)
Numbers in
Parentheses Correspond to
% RDF Energy
i ii i
• i
_l I
—1 1 .1
i ¦ ' •
1.0
0.9
0.8
0.7
0.6
CM
O
z
0.5
to
o
0.4
0.3
0.2
0.1
l/>
t/->
X
o
z:
75
100 125
BOILER LOAD, Mw
SOURCE: Shannon et al. 1977.
150
FIGURE 21
N0X STACK EMISSION-UNION ELECTRIC PLANT,
ST. LOUIS, MISSOURI
336
-------
1.75
1.50
¦"3
CO
O
Ol
* 1
•— I '
CO
z
O
CO
CO
1.25
00
LU
CSJ
O
CO
0.75
0.50-
0.25
—
•(18)
•
.(9)
—
• (9)
o(7)
•
(27)1
•(18)
•(9)
(8)4(10)
(5)A^(9)
•
•
(7-8)0
• (9) (7-8)o*
•( 18)(7-8)0
•(9)
•(10)
•
•(4-5) _
•
•(10)
•(8-9)
•do) —
Federal
Standard
-
Missouri
Standard .
| Numbers
O Method 6®./
A Method 8-'
• EPA Van
in Parentheses Indicate % RDF-
- Data acquired using Methods 6 and 8 are presented
only for those tests where EPA van data are not
available.
1 1 1 1 1 1 1 1 1 J 1 1 1 1 1
4.0
3.0
3
+J
CO
VD
O
CO
z
o
•—I
.0 co
CO
s:
LU
CM
o
CO
1.0
75
100 125
BOILER LOAD, Mw
150
SOURCE: Shannon et al. 1977,
FIGURE 22
S02 STACK EMISSION—UNION ELECTRIC PLANT—
ST. LOUIS, MISSOURI
337
-------
TABLE 26
CHLORIDE EMISSIONS
(UNION ELECTRIC PLANT, ST. LOUIS, MISSOURI)
TEST SERIES
AVERAGE CI IN FUEL
(ppm)
AVERAGE Cl" IN
OUTLET STACK
(mg/m3)
COAL
RDF
Coal-only - 1
3,900
-
335
Coal-only - 2
3,410
-
Coal-only - 3
4,140
-
373
Coal + RDF - 1
3,667
4,100
402
Coal + RDF - 2
4,090
3,370
535
Coal + RDF - 3
3,350
3,970
453
338
-------
0.14
0.12
tn
UJ
_J
z>
0.10c
o
<
CD
LU
s:
CO
s:
<
0.08 J
OH
>
CO
z
o
t—t
0.06
to
CO
s:
LU
X
o
0.04
z
0.02
NOx EMISSIONS
BOILER UNIT
O ~ 60 PCT LOAD
~ - 80 PCT LOAD
A ~ 100 PCT LOAD
OPEN SYMBOLS ~1976 DATA
SHADED SYMBOLS —1977 DATA
10 20 30 40 50
REFUSE DERIVED FUEL HEAT INPUT,, PERCENT
60
SOURCE- Hfill 1978a.
FIGURE 23
NOx STACK EMISSIONS AS A FUNCTION OF RDF
HEAT INPUT AND BOILER LOAD—AMES, IOWA
339
-------
2.8
2.4 J
2.0
1.6
1.2
S0X EMISSIONS
BOILER UNIT 5
0.4
O ~ 60 PCT LOAD
~ ~ 80 PCT LOAD
A ~ 100 PCT LOAD
OPEN SYMBOLS~l 9 76 DATA
SHADED SYMBOLS-1 977 DATA
I
1
1
1
1
10 20 30 40 50
REFUSE DERIVED FUEL HEAT INPUT,, PERCENT
60
SOURCE: Hall 1978a.
FIGURE 24
S02 STACK EMISSIONS AS A FUNCTION OF RDF HEAT
INPUT AND BOILER LOAD—AMES, IOWA
340
-------
REFUSE DERIVED FUEL HEAT INPUT, PERCENT
SOURCE: Hall 1978a.
FIGURE 25
CHLORIDE EMISSIONS AS A FUNCTION OF RDF HEAT INPUT
AND BOILER LOAD—AMES, IOWA
341
-------
Gaseous Emissions (organics)
RDF Cofiring Facility. Hydrocarbon emissions data obtained from
the cofiring of refuse at the Union Electric Power plant indicated
that hydrocarbon concentrations from coal firing alone are on the
order of 10-20 ppm and that cofiring did not seem to change the
hydrocarbon concentration significantly. Hydrocarbons emission data
obtained from stack gas analysis at Ames, Iowa, are presented in
Figure 26. No conclusive trends can be ascertained at this time.
Additional effort in this area is needed for fuller characterization.
Figure 27 presents aldehydes and ketone (reported as formalde-
hyde) emissions data from Ames. Limited data is available and no
definitive trends can be noted since emissions depend on constituents
of RDF such as wood chips, leaves, and other cellulosic materials.
Since no controls were placed on the nature and quantity of cellulo-
sic materials, the emissions were very variable in concentration.
Heavy organic compounds in the stack emissions from Ames are
shown in Table 27. Many of the heavy organic compounds are below
detectable levels and are in gaseous forms. Further work is neces-
sary to correlate these emissions as a function of RDF input.
Other Emissions
Figures 28 and 29 show data obtained from analysis of stack
gases for cyanide and phosphate. Data was obtained from stack gas
analyses from boilers at the Ames, Iowa, plant. The data is very
variable suggesting that the wide variability in RDF chemical
composition is responsible for no clear trends in emission levels.
WATER POLLUTION
RDF Production Facility
The major source of aqueous waste from an RDF production facil-
ity is periodic washdown of floors and equipment. Table 28 indi-
cates pollutant levels associated with floor washings. The basic
impact of floor washings is on the abatement devices, which receive a
fairly high concentration of wastewater in a short interval of time.
The overall effect is, however, minimal, approximately 2,000 to 4,000
gallons/week. The large increase in the total bacterial and fecal
coliform levels is a result of entrainment of settled RDF dust.
Though the bacterial levels are high, they must be related to bac-
terial levels in the receiving medium to have any significance.
342
-------
320
280
240
200
160
120
801
40
0
.CE:
O ~ 60 PCT LOAD
~ ~ 80 PCT LOAD
A ~ 100 PCT LOAD
OPEN SYMBOL ^1976 DATA
SHADED SYMBOL ~1977 DATA
HYDROCARBON EMISSIONS
BOILER UNIT 5
10 20 30 40 50
REFUSE DERIVED FUEL HEAT INPUT,, PERCENT
Hall 1978a.
FIGURE 26
HYDROCARBON EMISSIONS AS A FUNCTION OF RDF HEAT
INPUT AND BOILER LOAD—AMES, IOWA
343
-------
24
=3
O
cd 20
LU
<
cc ,,
CD 16
ALDEHYDE AND KETONES
REPORTED AS FORMALDEHYDE
BOILER UNIT 5
O ~ 60 PCT LOAD
~ ~ 80 PCT LOAD
A ~ 100 PCT LOAD
OPEN SYMBOL ~ 1976 DATA
SHADED SYMBOL ~ 1977 DATA
12J
odt
1
20 40
REFUSE DERIVED FUEL HEAT INPUT, PERCENT
60
SOURCE: Hall 1978a.
FIGURE 27
ALDEHYDES AND KETONES EMISSIONS AS A FUNCTION OF
RDF HEAT INPUT AND BOILER LOAD—AMES, IOWA
344
-------
TABLE 27
ORGANIC COMPOUNDS IN STACK EMISSIONS
(AMES, IOWA RESOURCE RECOVERY PROJECT)
Stack gases
Particulates
Compound
(Hg/1,000 m3)
(og/g)
Naphthalene
BDLIf
BDL
Acenaphthalene
BDL
BDL
Fluorene
36.5
BDL
Anthracene
BDL
H>L
Fluoranthene
119
BDL
^rene
36.5
B)L
Benzofluorenes (1,2 and 2,3)
54.7
»L
1,2-Benzanthracene
BDL
BDL
a- and e-Benzyprenes and perylene
72.9
0.42
2O-Mathylcho1anthrene
BDL
V)L
Dlbenzanthracenes (1,2-3,4 and A,H)
BDL
BDL
Dibenzanthracene (2,3-6,7)
BDL
BDL
Coronene and 3,4-9,10 dlbenzopyrene
BDL
B)L
Aliphatic hydrocarbons
31,700
340
Detection limits
35 pg/1,000 m3
0.35 ng/g
•/ BDL - Below detection limit.
SOURCE: Even, J.C., et al 1977-
345
-------
0.4
0.3
« 0.21
o
Boiler 5
Boiler 6
60% Steam Load
80% Steam Load
100% Steam Load
80% Steam Load
0.1
<
>-
o
10
20
30
40
50
60
RDF HEAT INPUT-%
SOURCE:
Hall et al. 1977.
FIGURE 28
CYANIDE EMISSIONS AS A FUNCTION OF RDF HEAT
INPUT AND BOILER LOAD-AMES, IOWA
346
-------
Boiler 5
60% Steam Load
80% Steam Load
100% Steam Load
20 40
RDF HEAT lNPUT-%
60
SOURCE: Hall et al. 1977.
FIGURE 29
PHOSPHATE EMISSIONS AS A FUNCTION OF RDF HEAT
INPUT AND BOILER LOAD-AMES, IOWA
347
-------
TABLE 28
POLLUTANTS IN WASHDOWN ACTIVITY
u>
00
¦w water flow rat*
T*tal water uaed
Vftlin at runoff collected
m«t analrati
Tot»l impended tolldt (ppaO
rv-tal dtiMtxl aolIda (ppa)
llocheaical oxygen Innrf (ppa)
Clinical oxygen deannd (ppa)
P»
fetal alkalinity (ppn)
Total organic carbon (ppa)
Oil and greaae (ppa)
tectorial analTala
lv>til bacteria (couata/al)
fecal collfora (HW/100 al
latwilU [prtNM (po«.) «
(¦!•)]
That *
». 1
Teat Ho. 2
Taat
*>. 3
teat as. *
J.21 i/a
2.21 i/l
2.OS 11*
2.08 1/a
6.606 X
7,991 1
3,247
1
4.622 1
37 1
49 1
14 1
12 i
Coapoalta
Co^oilta
Co^oalta
Cjapoalta
I» watax runoff ii»la
Tan uatar
runoff uala
Tae watar
runoff aaanla
Tap watar runoff eaaela
8.00
6.024.00
8.00
9,292.00
56.0
1,844.0
8.0
2,024.0
MS. 00
444.00
2S2.0O
364.00
492.0
788.0
200.0
432.0
me'
374.0
m
763.00
«• 1
160.0
< 1
242.0
32.90
2.137.30
33.40
1,332.00
329.0
1,497.0
2.48
1,388.0
9.7
6.3
9.S
6.3
9.4
7.1
9.3
7.3
62.00
SO.00
32.00
38.00
ie.o
36.0
21.60
22.0
4. SO
1,760.00
6.SO
1.ISO.00
m£'
KA
NA
Ml
M
NA
M
MA
20.0
92.0
28.0
60.0
80
940,000
36
1,900,000
< 3
12,000
< 3
36,000
Meg.
K)g.
teg.
roe. (Group
a/ m - nana detected.
£/ MA • not analyzed.
£/ m • aaat probakle antw-
Jt/8 - Liters per second
SOURCE: Fiscus, D.E. 1977.
-------
RDF Cofiring Facility
The primary pollutants discharged to waterways are pollut-
ants discharged from wastewater treatment system effluent designed
specifically to handle bottom or grate ash solids from the cofiring
process. Bottom ash is removed by sluicing out the ash with water
and conveying the resultant wastewater to an ash pond. The ash in
the pond is periodically dredged and landfilled.
Important aspects related to cofiring are ash generation rate,
chemical constituents, and the percent of ash in the fuel that is
converted to bottom ash. Table 29 shows accumulation rates and
properties of bottom ash. On an average, for about 10 percent heat
input from RDF, the bottom ash accumulates by a factor of 6 to 7 when
coal plus RDF was burned as compared to coal alone.
Visual inspection of the bottom ash when coal is cofired with
RDF indicates a variety of unburned materials (wood, plastic, etc.)
and incombustibles (metals). A compositional analysis of the bottom
ash is presented in Table 30.
Table 31 shows the concentration of trace metals in the bottom
ash with coal and coal plus RDF cofiring. The results show an
increase in Ba, Cr, Pb, Cu, Ti, Zn, Br, and Sb.
Table 32 shows bacteria levels in sluice solids (bottom ash) and
sluice water under cofiring conditions. Bacterial levels are higher
in solids than in sluice water, which may be due to the absorption of
bacteria onto the solids. Sluice solid bacteria levels were gener-
ally less than bacterial levels encountered in raw refuse (1 x 10®
counts/g).
Table 33 is a summary of pollutant data obtained from ash pond
effluents for both the ash from coal and the ash from coal and RDF.
Based on this data, it may be concluded that disposal of bottom ash
through sluicing and pond settlement results in the following:
• increased biochemical oxygen demand, dissolved oxygen and
suspended solids
• increased TOC (total organic carbon) with cofiring
• increased ammonia, iron, and manganese in the effluent with
cofiring
• increased total and dissolved calcium with cofiring
The effect of landfilling pond ash on leachate organic and metal
concentrations has not been quantified.
349
-------
TABLE 29
BOTTOM ASH PROPERTIES AND ACCUMULATION RATES
Parameter Coal rdf
Bottom ash accumulation rateS^ 605 kg/hr (+ 52%) 4,080 kg/hr (+ 73%)
(wet basis) for coal + RDF
Percent of heat input that is 99*7% 90%
not lost to bottom ash (i.e.,
combustion efficiency)
Percent of ash in fuel that 8,7% 64.7%
goes to bottom ash
Properties of sluice solids!?/ Coal-only Coal + rdf
Heating value (kj/kg) 2,887 3,668
Ash (wt %) 50.91 48,97
A1 (Al203) (wt %) 10.06 6.10
Fe (Fe203) (wt %) 13.39 4.71
S (wt %) 1.17 0.17
Geometric mean diameter (mm) 3.3 4,3
a/ Values are on wet basis and refer to sluice solids samples after
iioat of the free water had drained off.
SOURCE: Fiscus, D.E. 1977b.
350
-------
TABLE 30
COMPOSITIONAL ANALYSIS OF BOTTOM ASH
Mv load
133
134
133
135
RDF
7-8%
7-8%
7%
7-81
Comnosltlon fwt'l - as received)
Paper
0.3
1.2
0.7
1.4
Plastic
1.0
0.9
1.2
1.3
Wood
3.8
3.5
4.4
3.7
Glass
1.2
3.6
2.5
2.9
Fe metal magnetic
4.2
5.6
2.1
7.6
Other metal
1.9
1.7
1.5
1.6
Organics
0.3
0.7
1.6
0.6
Miscellaneous
12.3
15.8
20.7
20.2
Coal slag
60.6
48.2
47.0
43.5
Oust
14.4
18.8
18.3
17.2
Total
100.0
100.0
100.0
100.0
SOURCE: Fiscus, D.E. 1977b.
351
-------
TABLE 31
TRACE ELEMENTS IN BOTTOM ASH
Bottom Ash
Trace (Mg/g, dry basis)
Pollutant Coal Coal + RDF
Sb 0.20 <1
As 0.80 <2
Ba 572 2433
Be 4.2 2.9
Cd 1.8 3.0
Cr 595 675
Cu 188 1847
Pb <164 411
Hg <0.3 0.12
Se 2.63 1.54
Ag 4.10 1.7
T1 5007 5245
Vi 185 131
Zn 151 610
Br 20 68
CI 186 903
F 84 <21
SOURCE: Fiscus, D.E. 1977b.
352
-------
TABLE 32
SLUICE WATER BACTERIAL CONTAMINATION
FOR COAL + RDF FIRING CONDITIONS
Sample and Data
Coal + Refuse
Total Bacteria
Counts/ml
(Counts/g)
Fecal Coliform
MPN/100 ml
(MPN/g)
Salmonella
+ or -
and Group
Sluice Water
Test
6,400
75,000
38,000
5,600
4,300
4,300
24,000
4,300
+ Croup B
Sluice Solids
Test 1
2
3
4
(54,000)
(140,000,000)
(81,000
(43,000)
( 5)
(<1,100)
(<3)
(23)
SOURCE: Fiscus, D.E. 1977b.
353
-------
TABLE 33
ASH POND EFFLUENT ANALYSIS
Pollutant
ttvtr
Co.l + RDF
«lh Dond
Cot I Mh
M!
wtttr
Efflutnc
Jnllms
pond tflluine
BOD;
ppa
< 10
65
200
< 10
(10.8)
(103)
Dissolved oxygen
Mg/i
11
«
11
11
(6)
(1.85)
Suspended solids
ppa
400
75
200
40
(231)
(215)
Annonle
ppb
25
< 20
< 40
< 30
Boron
ppb
< 10
< 23
< 50
< SO
Calcium (total)
pp„
300
300
500
500
Calcium (dissolved)
ppa,
SO
to
60
60
COD
ppa
< 40
(0
20-960^
< 20
(93)
(423)
Dissolved sollda
ppa
350
300
500
400
(412)
(840)
Iron (total)
ppb
5,000
2,500
7,000
500
Iron (dissolved)
ppb
150
150
100
SO
Manganese (total)
PPb
300
400
1,000
130
Manganese (dissolved)
PPb
100
300
50
100
Oil and grease
ppb
s.ooq
10,000
50,000
3,000
(45,000)
(30,400)
Sulfate
ppm
75
125
110
140
T0C
ppm
20
35
50-375^
« 10
Aluulnum (total)
ppb
4,000
1,000
400-8,000^'
750
Aluclnum (dissolved)
ppb
100
100
175
100
Arsenic (total)
PPb
20
20
30
20
(< 10)
« 10)
Arsenic (dissolved)
ppb
20
20
20
20
Barium (total)
ppb
250
250
325
250
« 5,000)
« 9,000)
Earium (dissolved)
ppb
250
250
250
250
Beryllium (total)
PPb
< 10
< 10
« 10
< 10
« 30)
« 20)
Beryllium (dissolved)
ppb
< 10
< 10
< 10
< 10
Boron (total)
ppb
< 100
< 100
150
< 100
Cadclca (total)
ppb
< 10
< 10
10
< 10
« 0.5)
« 0.5)
Cad&lum (dissolved.)
ppb
< 10
< 10
< 10
< 10
Chloride
ppn
25
2S
30
23
(19.6)
(59)
Chrsoiuta +6 (total)
ppb
< 25
< 25
< 25
< 25
Chroolua +6 (dissolved)
ppb
< 25
< 25
< 25
< 25
Chropi.ua +3 (total)
ppb
20
20
60
20
Chromium +3 (dissolved)
ppb
20
20
20
20
Cr.roraiura (total)
ppb
20
20
60
20
(< 230)
« 150)
Chronica (dissolved)
ppb
20
20
20
20
Cobalt (total)
ppb
SO
50
50
30
Z'. jr it (dissolved)
ppb
50
50
50
SO
Copper (total)
ppb
20
15
10-150^/
IS
« 80)
« 60)
Copper fdisscTve-i)
ppb
20
IS
20
IS
Cyar.i-fe
ppb
< 10
< 10
< 10
< 10
« 50)
« 50)
Proposed
Mi«»ourl
•ffluasc
«uU«lln»
SO
30£/
Mon«
Hoot
Mom
Mom
Moat
Hon*
Hon*
1,000
None
Nou
15,000£/
Mont
Mont
Soot
Nont
Jfont
100
Mont
2,000
Hod*
500
Non
(ton*
100
Hom
Hon*
30
Hon*
300
Hon*
300
Hon*
tbn*
Nom
1,000
SO
354
-------
TABLE 33 (Concluded)
Proposed
Missouri
ftiver
Coal + RDF ash oond
Coal ash
effluent
Pollutant
Units
msis
Effluent
Influent
pond affluent
Fecal coliform
MPN/100 ml
so
50
75
< so
200
(22,000)
(23,325)
Florida
ppb
300
400
400
3S0
None
(25)
(40)
lead (total)
ppb
< SO
< 50
550
< so
None
lead (dlaaolved)
ppb
< SO
< 50
< 50
< 50
100
« 66)
« 2)
Harcury (total)
ppb
< 2
< 2
S
< s
None
« 8)
« 10)
Harcury (dissolved)
ppb
< 2
< 2
< 5
< 5
10
Molybedenum (total)
ppb
100
100
100
10(1
Hon*
Molybedenum (dlaaolved)
ppb
75
75
75
73
None
Bickel (total)
ppb
< SO
< 50
< 50
< 50
(Son*
Nickel (dlaaolved)
ppb
25
25
30
23
1,000
HlCrate
ppB
< 12
< 10
< 12
< 10
Nona
nitrite
ppb
50
50
so
so
Nona
Organic nitrogen
ppn
< 5
< 5
< 15
< 5
Sons
pa
pH ur.lCJ
7.5
7.2
8.6
8.4
6.0-9.0
(7.4)
(9.27)
Phenol
ppb
< 25
< 25
< 100
< 23
100
Phosphate »
ppb
1,000
500
1,500
500
Mom
Selenium (total)
ppb
< 35
< 35
< 33
< 35
None
« 4)
« 4)
Selenium (diasolved)
ppb
< SO
< 50
< 50
< 50
so
Settleable solids
ol/i/hr
< 2
< 2
< 4
< 0.23
0.2
Silver (total)
ppb
< 10
< 10
< 10
< 10
None
« 0.5)
« 0.5)
Silver (dlaaolved)
ppb
< 10
< 10
< 10
< 10
100
Vanadlun (total)
ppb
75
70
100
70
Hone
(< S00)
« 70)
Vanadium (dlaaolved)
ppb
SO
50
50
SO
Nom
Zinc (total)
ppb
< 100
< 100
300
< 100
Hon*
« 230)
« 260)
Zinc (dlaaolved)
ppb
50
30
50
30
1,000
a/ Approximate .tvaraga of Union Electric data from figures In original report Values la par*nth*sls
ar* averages of >SU data,
b/ gang* shown dua to wlda data acattering.
e/ Fadcral affluent guideline! for (teaa electric power plant* cover only total auapended aollda, and
Oil and Crease, and are the aame at thoae for Missouri.
SOURCE: Fiscus, D.E. 1977b
355
-------
LANDFILLED SOLIDS AND LEACHATE CONTAMINATION
Landfilled solids are generated from three main sources, all of
which are highly variable depending on raw refuse composition and RDF
preparation processes. They are:
• inert materials from the RDF preparation process
• flyash from particulate removal devices
• bottom or grate ash from ash ponds
Occasionally, RDF may be landfilled if the power generation
facility is shut down for maintenance reasons. Table 34 presents the
results of test data obtained from the analyses of RDF and magnetic
belt rejects (nonferrous fractions). The data were obtained from the
St. Louis refuse processing facility.
Tables 35 and 36 present the results of trace element analysis
conducted for electrostatic precipitator catch at the Union Electric
power plant and cyclone catch at the Columbus, Ohio, power plant.
Trace elements such as Sb, Ba, Cd, Cr, Cu, Pb, Zn, Br, CI, and Hg
increase in the flyash as a result of cofiring. The disposal of fly-
ash by landfilling would create a pollutant potential by way of
leachate contamination of groundwater.
Bottom ash was discussed earlier as being discharged via sluic-
ing to an ash pond. Disposal of bottom ash residues from settling
ponds would pose potential pollution control problems primarily be-
cause of the increase of trace metals during cofiring. The effects
of landfilling bottom ash would require evaluation.
Reject material from the RDF preparation plant and flyash parti-
culates collected by air pollution abatement mechanisms that are
landfilled, contain constituents that form leachate which can subse-
quently contaminate groundwater. Also, ash pond sludges that are
landfilled create similar leachate problems.
An evaluation of leachate from landfilled materials was made on
a laboratory-scale basis. Rejects from the RDF production facility
were obtained from the St. Louis refuse processing plant. Material
obtained was air classifier cyclone discharge and magnetic belt
rejects (nonferrous fractions). Ash material was obtained from the
Union Electric Power Plant. Both flyash and bottom ash were
collected from cofiring operations. Each sample was ground to a fine
powder and then contacted with distilled water for 2 days to produce
a leachate. Table 37 shows the leachate analysis. The deposition of
these constituents as a leachate in the landfill needs further
356
-------
TABLE 34
COMPOSITIONAL AND CHEMICAL ANALYSIS
OF LANDFILLED INERTS AND RDF
Composition (wt %) RDF^" Landfllled
(tr « trace) Inerts
Paper 62.8 2.5
Plastic 4.8 1.6
Wood 2.7 A.6
Glass 2.9 27.4
Magnetic Metal 0.2 19.9
Other Metals 0.39 5.7
Organlcs 3.8 20.3
Miscellaneous 22.2 18.0
Chemical Analysis (wt %)
Ash 20.85
Fe (Fe203) 0.89
A1 1.64
Cu (CuO) 0.04
Pb (PbO) 0.05
Ni (N10) 0.02
Zn (NzO) 0.07
Visual Analysis (wt %)
Fe 4.45
Tin Cans 16.08
A1 4.17
Cu 0.66
^Normally not landfllled except when boilers not operating
for extended periods.
SOURCE: Fiscus, D.E. 1977d.
357
-------
TABLE 35
TRACE ELEMENTS IN LANDFILLED FLYASH
(UNION ELECTRIC PLANT, ST. LOUIS, MISSOURI)
Trace
Pollutant
Sb
As
Ba
Be
Cd
Cr
Cu
Pb
Hg
Se
Ag
Ti
V
Zn
Br
CI
F
Fly AshS/ (ug/g, dry basis)
Coal Only
Coal + RDF
0.30
4.8
627
14
2.5
187
80
215
0.2
8.76
3.5
7933
426
314
25
46.2
81.0
0.44
8.4
287
15
3.1
154
221
227
0.3
14.7
4.3
3033
343
503
34
66.1
107.7
2.6
9.4
1467
14.1
9.1
224
180
851
1.5
5.4
2.5
7758
306
987
80
<1.60
37
3.9
15
1297
13.8
11.2
217
192
964
1.7
10.5
2.0
7387
329
1113
76
3.57
101
a/
I «= Sample taken from ESP hoppers nearest inlet
0 » Sample taken from ESP hoppers nearest outlet
SOURCE: Fiscus, D.E. 1977b.
358
-------
TABLE 36
TRACE ELEMENTS IN LANDFILLED FLYASH
(COLUMBUS, OHIO MUNICIPAL ELECTRIC POWER PLANT)
Element
high-sulfur coal
(2.4% S)
44 wt %
refuse +
high sulfur
coal
(2.4% S)
44 wt X
refuse +
high-sulfur
coal
(2.4% S)
Cyclone
Catch
Cyclone
Catch
Cyclone
Catch
44 wt X
refuse +
high-sulfur
coal
(2.4% S)
Cyclone
Catch
Nonmetals
S
CI
C
H
H20
Major metals
Si
Fe
A1
Ca
Hg
Na
K
T1
0.8
0.01
ND
ND
ND
10-30
5-10
5-10
0.8-2
0.6
0.3
3-6
0.5
1.1
0.22
ND
ND
ND
10-30
4-6
5-10
3-6
0.8
0.8-2.0
3-6
0.5
1.1
0.3
ND
ND
ND
10-30
4-6
5-10
3-6
0.6
0.8-2
3-6
0.6
0
1.8
0.2
ND
ND
ND
20-40
5-10
5-10
5-10
0.8-2.0
1-5
3-6
0.6
Toxic trace metals (1)
Fo
As
Cd
Be
0.3
<0.1
<0.1
<0.001
0.06
<0.1
<0.1
<0.001
0.08
<0.1
<0.1
<0.001
0.1
<0.1
<0.1
<0.001
Other trace metals
Zn
Sn
Mn
Ba
B
V
Mo
Cr
Zr
Cu
Ni
Co
Sr
<0.1
<0.1
0.02
0.05
0.05
0.02
<0.01
0.02
0.02
0.03
0.04
<0.01
0.03
0.1
<0.01
0.05
0.06
0.05
0.02
<0.01
0.02
0.02
0.03
<0.01
<0.01
0.03
0.1
0.02
0.05
0.06
0.05
0.02
<0.01
0.06
0.05
0.03
0.05
<0.01
0.03
0.2
0.04
0.05
0.08
0.05
0.02
<0.01
0.06
0.02
0.03
0.08
<0.01
0.04
H2O Solubles
2.1
3.2
3.5
5.3
SOURCE: Vaughn, D.A., et al 1978
359
-------
TABLE 37
LEACHATE ANALYSES
S2
S5
Drinking
Coal + refuse
Cyclone
Magnetic
water
Sluice
discharge
belt
Constituent
standards^/
Fly ash
solids
(RDF>
rejects
Extraction dilution
2.00
2.00
6.67
2.00
(ml distilled water/g
of sample)
Level (mz/l)
BOD
.
20.9
393.5
502.1
457.6
COD
-
116.3
1,488
7,016
4,007
Nitrites (as N)
-
0.021
< 0.015
0.018
< 0.015
Nitrates (as N)
10.0
0.090
< 0.022
< 0.022
8.258
Arsenic
0.05
0.93
< 0.10
0.48
0.65
Barium
1.0
16.8
< 1.0
< 1.0
7.04
Cadmium
0.010
< 0.05
< 0.05
<0.10
< 0.05
Chromium
0.05
< 0.50
< 0.50
< 0.50
< 0.50
Cyanide
0.2
< 0.05
< 0.05
< 0.05
< 0.05
Lead
0.05
< 0.20
< 0.40
< 1.0
< 0.20
Mercury
0.002
< 0.05
< 0.05
< 0.05
< 0.05
Selenium
0.01
1.53
0
0.90
1.02
Silver
0.05
0
0
0
0
a/ Environmental Protection Agency, "National Interim Primary Drinking
Water Standards," Fart 141, Federal Register. Vol. 40, No. 51,
Washington, D.C., March 14, 1975.
SOURCE: Flscus, D.E. 1977.
-------
evaluation. Table 38 shows the calculated amount of dilution water
needed to have these constituents meet drinking water standards. The
existence of such dilution levels in actual practice must be
determined. However, the potential for pollutants to enter the
groundwater is recognized.
TRANSIENT POLLUTANTS
Unplanned or accidental process upsets cause the release of
transient pollutants. Very little analysis if any has been per-
formed to characterize pollutant levels during abnormal operating
conditions. In the refuse shredding stages of RDF preparation, the
potential for transient pollutants is high as a result of explosion
hazards associated with combustible dusts and flammable vapors.
Explosion venting would lead to dust and other gaseous emissions
propagating beyond the limits of the immediate facility. If explo-
sion suppression systems were used that employed chemicals such as
halogenated hydrocarbons, ammonium phosphate, and sodium bicarbonate,
an explosion could produce a high concentration of these chemicals in
at least the immediate area for a short duration. The significance
of these emissions would require evaluation. Fine water mist sprays
or a water deluge of flammable gases would cause transient pollutants
in the aqueous form. Continuous venting would provide a measure of
protection but, on the other hand, would require careful analysis of
resultant emissions prior to institution. Diesel engine exhaust
emissions in enclosed shed areas and in areas of high packer truck
traffic would result in hydrocarbons and other emissions. Other
sources of transient pollutants are presented in Table 39.
361
-------
TABLE 38
LEACHATE DILUTION REQUIREMENTS TO MEET
DRINKING WATER STANDARDS
CONSTITUENT
COAL
+ REFUSE
S2
CYCLONE
DISCHARGE
(RDF)
S5
MAGNETIC
BELT
REJECTS
FLY ASH
SLUICE SOLIDS
Nitrates (as N)
18.0
4.4
14.7
1,652
Arsenic
37,200
4,000
64,000
2,600
Barium
33,600
2,000
6,670
14,080
Cadmium
10,000
10,000
66,700
10,000
Chromium
20,000
20,000
66,600
20,000
Cyanide
500
500
1,650
500
Lead
8,000
16,000
133,400
8,000
Mercury
50,000
50,000
165,000
50,000
Selenium
306,000
0
600,000
204,000
Silver
0
0
0
0 I
SOURC?: Fiscus 1977a.
362
-------
TABLE 39
SOURCES OF TRA
Upset Condition
Packer Truck Traffic
Spontaneous Combustion of
Stored Raw Refuse
Storage of Raw Refuse
Shredder (Explosions)
Explosion Suppression Mechanism
Excess Air to Air Classifier
RDF Transport Line Failure
Excess RDF Transport Air
(overload Pollution Abatement
Facility)
Excess RDF Feed Rates
Ash Pond Upset
POLLUTANTS
Emission
Particulates, Dust
Gases, Particulates, Odors
Odors, Heat, Gases
Dusts, Particulates, Gases
Flame Retardants, Vent Gases,
and Particulates
Dust, Particulates from Cyclone
Separator
Dust, RDF, Particulates
Fly-ash, Gaseous Emissions,
Volatile Metals
Increase in quantities of Fly-
ash* Bottom Ash, Gaseous Emis-
sions, Volatile Metals, Ash
Pond Organics, Suspended Solids,
Settleable Solids
Increased Pond Effluent and
Suspended Solids
363
-------
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369
-------
Part 7
In Situ Gasification
-------
TABLE OF CONTENTS
Page
LIST OF ILLUSTRATIONS 372
LIST OF TABLES 372
SECTION I - TECHNOLOGY DESCRIPTION 373
PROGRAM OBJECTIVES 373
TECHNOLOGY STATUS 375
PROCESS CHEMISTRY 377
IN SITU GASIFICATION SEQUENCE 378
SECTION II -POLLUTANTS AND DISTURBANCES 380
INTRODUCTION 380
STATE OF KNOWLEDGE 380
SOURCES OF EMISSIONS, EFFLUENTS, AND
DISTURBANCES 382
SPECIFIC POLLUTANTS 384
Air Emissions 384
Water Effluents 386
Organic Emissions and Effluents 386
Trace Element Emissions and Effluents 390
REFERENCES 397
371
-------
list of illustrations
Figure Number
Coal Fields of the United States 374
Underground Coal Gasification Production
and End Uses
Periodic Table of the Elements 391
LIST OF TABLES
Table Number Page
Components in Gasifier Gas (ppm) 385
Coal Tar Constituents by Boiling Point 387
Range in Amount of Trace Elements
Present in Coal Ashes (ppm) 388
Elements Exceeding Recommended Water
Quality Levels 389
Mean Analytical Values for 101 Coals 392
Trace Element Content of American Coals
(ppm in Coal) 393
Distribution of Environmentally Hazardous
Trace Elements (ppm in Coal) 394
372
-------
SECTION I - TECHNOLOGY DESCRIPTION
PROGRAM OBJECTIVES
The goal of the U.S. Department of Energy underground coal con-
version (UCC) program is to develop the technology to produce clean
fuels from coal deposits that are unsuitable for commercial ex-
ploitation by conventional mining techniques. Successful develop-
ment of in situ conversion technology would quadruple the proven re-
serves of U.S. coal by allowing production of gaseous and liquid
fuels from these deposits at 65 to 75 percent of the cost of conven-
tional coal conversion in an environmentally acceptable manner. Ap-
plicable reserves are shown in Figure 1.
Specific objectives of the program are as follows:
• develop commercially viable UCC processes to produce syn-
thetic natural gas (SNG), syngas for conversion to liquid
fuels or chemicals, and fuel gas for electric utility or
industrial use from low-rank (subbituminous or lignite) coal
by 1987
• develop cost-effective technologies to utilize steeply dip-
ping and bituminous coal by UCC
Accomplishing these objectives will lead to the growth of a com-
mercial UCC industry starting in late 1980. A recent market analysis
projects energy production levels of 0.2 quadrillion Btu (quad) in
1987, 0.5 quad in 1990, and 4 quad in 2000, assuming successful pro-
gram results. Four quads are roughly equivalent to 2 million barrels
of oil per day.
• provide detailed design and operational data which industry
can scale up with confidence
• provide accurate and complete cost estimates which can be
scaled up and allow comparison with alternative processes
• provide detailed environmental impact and control data to al-
low industry to implement projects that will meet applicable
standards
• verify the reliability of continuous operation of UCC proces-
ses
• show that UCC processes have the flexibility to meet a
variety of commercial needs (Sikri and Burwell, 1979)
373
-------
u>
vj
York
Medium- and high-volatile bituminous coal
V77A
Subbituminous coal
Lignite
TOTAL COAL TO 6000 FEET (BILLIONS OF TONS)
ESTIMATED UCG RESOURCE (BILLIONS OF TONS):*
TOTAL
~DIVIDE THESE NUMBERS BY 1.1 TO OBTAIN TONNES.
SOURCE: Department of Energy 1978e
FIGURE 1
COAL FIELDS OF THE UNITED STATES
-------
TECHNOLOGY STATUS
One future coal-based energy scenario estimates that UCG plants
could comprise about 15 percent of the total coal usage by the year
2000 and 35 percent by 2050 (Dickson, undated). The primary reason
for this optimistic appraisal of UCG's potential is that compared to
conventional mining of coal combined with surface gasification, UCG
offers a number of significant potential advantages: tripling re-
coverable coal reserves, minimizing health and safety problems as-
sociated with conventional extraction, reducing surface disruption
and solid waste disposal problems, reducing water consumption, and
reducing socioeconomic impacts (Department of Energy 1978b).
As shown in Figure 2, the demand for products of UCG logically
falls into three areas, as a function of gasification and upgrading
options:
• low-Btu gas (produced by injecting air to the UCG reactor)
for electric power generation and industrial fuels, at or
very near the coal deposits
• medium-Btu gas (produced by injecting oxygen) for chemical
feedstocks (e.g., gasoline, ammonia, methanol, ethylene
glycol, and acetic acid production) for manufacturing
facilities either on-site or short pipeline distances away.
The chemical feedstocks, however, can be transported via
railroad to the market areas.
• high-Btu gas (produced by injecting oxygen and then upgrading
the heating value of the raw product in surface facilities)
for injection into pipelines serving residential, commercial,
and industrial customers
Because of the favorable characteristics of the Western coals,
it appears that UCG technology will first be commercialized in the
West. As UCG technology develops for the most difficult Eastern
coals, the large Eastern markets for power and gas can be penetrated
(Department of Energy, 1978a).
The major process options being developed for underground gasi-
fication of coal are the gasification of horizontal beds using
"Linked Vertical Wells (LVW)" and a Soviet technique applied to
"Steeply Dipping Beds (SDB)Descriptions of these processes are
presented in Appendix E.
The current underground coal gasification (UCG) program of the
Department of Energy addresses four priorities focusing on commercial
processes that can (Sikri and Burwell, 1979):
375
-------
SOURCE: Department of Energy 1978b
FIGURE 2
UNDERGROUND COAL GASIFICATION PRODUCTION AND END USES
-------
1) produce a medium-Btu gas for synthesis to transportation
fuels by indirect liquefaction within the 1980s
2) produce a medium-Btu gas for upgrading to a synthetic
natural gas for distribution in the natural gas pipeline
network within the 1980s
3) produce a low-Btu gas for on-site electrical power genera-
tion and distribution within the 1980s through the existing
power grid
4) produce either low- or medium-Btu gases from a wide variety
of coals to address area markets in any region of the coun-
try, East or West
This strategy is not only consistent with DOE goals, it also
removes some of the geographic-related problems between the coal
resources and markets for UCG. The abundant Western coals that are
favorable to UCG can be used to address all four priorities. The
value of gasoline from UCG through indirect liquefaction is great
enough to transport it appreciable distances from the location where
it was made. There is sufficient Soviet experience in gasifying
steeply dipping seams of coals to indicate commercial potential in
the 1980s. Thus, the gasification of this resource also addresses
all four priorities. The Gulf Coast lignites could be commercially
gasified in the 1980s if problems of excessive seam water can be
handled. If not, a longer term project could still address the
fourth priority. Likewise, the gasification of Eastern bituminous
coals falls under the fourth priority as there is no clear prospect
of commercialization in the 1980s, but a longer-term successful
concept for bituminous coals would open UCG products to extensive
area markets in the East with minimal product transportation costs.
PROCESS CHEMISTRY
In most in situ processes, two distinct phases are usually
involved: carbonization and gasification. Air reacts exothermically
with coal and/or char producing CO2 and H2O as combustion
products. These hot gases react with char to form product gas
consisting mainly of CO, H2, and some CH^. The combustion heat
also promotes carbonization (or devolatilization) of coal resulting
in methane, char, H2O, and coal tar. Heavier components condense
in the coal seam, and the lighter components remain with the product
gas (King 1977).
The following reactions summarize some of the important steps
involved in underground coal gasification:
377
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combustion
coal + O2 —» H2O + CO2
hydrolysis coal + H2O —~ CH4 + CO + higher
hydrocarbons
carbonization coal —» C + CH4 + H2
Bouduard 2C0 » C + CO2
(undesirable side reaction)
water gas reaction C + H2O —» H2 + CO (gasification)
shift reaction CO + H2O H2 + CO2
methanation 3H2 + CO -~CH4 + H2O
The extent to which each of these reactions predominates and/or
can be controlled under in situ conditions is one of the principal
subjects of current technical investigations (Hughes et al. 1978;
King 1977).
IN SITU GASIFICATION SEQUENCE
In situ gasification consists of pregasification, preparation of
the seam, gasification of the seam, surface processing the product
gases (if necessary), and support systems.
The main feature of pregasification is preparation of the bed to
increase its permeability. Some coal seams are naturally quite per-
meable and do not require "pregasification"; however, the majority of
coal seams do require some pretreatment.
The main gasification methods are reverse combustion and
directional drilling. Permeability of the coal seam is enhanced
through reverse combustion by advancing a small flame front through
the seam against an injected flow of air. Directional drilling links
injection and production wells by a horizontal hole drilled from the
surface. Another method of linking is the use of shaped charges
placed in vertical wells and fired to form a long hole (Sikri and
Burwell, 1979).
Gasification involves introducing the gasifying agents (oxygen/
steam, and/or carbon dioxide), putting these agents in contact with
the coal, and recovering the reaction products.
Surface processing may include: mechanical separation to
separate heavy entrained hydrocarbons, amine absorption to remove
hydrogen sulfide, sulfur removal, and methanation to produce high-Btu
gas.
378
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Surface-support facility requirements may include oxygen and
steam plants and, possibly, water treatment units.
379
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SECTION II- POLLUTANTS AND DISTURBANCES
INTRODUCTION
One purpose of coal conversion is to convert an environmentally
unacceptable fuel into a clean, convenient gas or liquid that used as
a fuel will have an acceptable impact on environmental quality Con-
sideration must be given to the potentially large environmental ef-
fects of conversion facilities to preclude merely transferring the
environmental impacts of conventional coal utilization facilities to
coal conversion facilities.
Although knowledge of the wastes and emissions from coal con-
version processes is still incomplete, it i8 known that wastes will
be generated during each main process stage. Many of these wastes
are largely controllable or convertible to environmentally acceptable
forms; however, more serious problems may arise from possible fugi-
tive emissions produced by inadequate containment of process streams
or incomplete treatment of wastes.
The coal conversion processes discussed in this report are
largely untried under conditions approximating commercial applica-
tion. Consequently, although a number of potential pollutants have
been identified, it is impossible at this point to predict with high
confidence the combinations and forms they will come into contact
with in the environment. And in considering pollution control needs
it is also necessary to consider the potential interrelationships '
existing among liquid, gaseous, and solid wastes. The process
streams in which pollutants are found are presented in Appendix E.
Various tables listing pollutants of concern are presented in Ap-
pendix E. F
STATE OF KNOWLEDGE
State-of-the-art reviews or characterization of substances in
energy—related effluents have been conducted by several investiga-
tors. The reviews indicate that data availability varies among coal
conversion categories and individual processes.
A state-of-the-art review was conducted by Research Triangle
Institute to identify gaps in existing and probable future data on
chemical elements and volatile organic compounds in solid waste and
aqueous effluents from coal mines, coal-fired power plants, coal liq-
uefaction and gasification plants, and non-coal fossil fuels. The
reviewers found that with regard to coal conversion processes, a pau-
city of data existed on the organic composition of liquid and solid
effluents from in situ coal gasification. Meager data were available
380
-------
for the organic composition of liquids and solids from coal proces-
sing. In general it was concluded that,
"the research conducted to date on the analysis for
organics in liquid and solid effluents was highly
inadequate for the purpose of understanding the ef-
ficiency of the energy-related processes and the
potential environmental impact. Much of the data
were based on 'paper' studies that merely con-
jectured as to the probable pollutants that would
be associated with the energy-related activity.
When evaluating the available data on the elemental
and organic composition of effluents from energy-
related processes according to the chosen
criteria—particularly the thoroughness of the
study and its ability to provide specific individual
chemical information for all the species present in
the effluents—we found few significant energy-related
studies." (Pellizzari 1978)
Radian's survey of available data on the environment al aspects
of low/medium—Btu gasification processes concluded that although a
significant amount of data is available on environmental problems as
sociated with coal gasifier operations, the data are inadequate for
making comprehensive environmental and control technology assess-
ments. Major deficiences were found in the areas of characterizing
the emissions of minor and trace contaminants from gasificiation pro
cesses (particularly trace organics). The survey also indicated a
general lack of information on fugitive emissions and minor process
vent streams (Corbett 1978). It should be noted however, that pro-
duct and by-product streams containing coal-derived compounds and
added materials are capable of producing emissions through incomplet
recovery, evaporation of constituents, spills, or leaks.
Control and treatment processes applied to minimize pollutants
produced in the conversion areas include particulate control, stack
gas control, acid gas treatment wastewater treatment, char treatment
tar treatment, heat control, and noise control. Cleanup processes
can generate their own pollutants requiring treatment.
Emissions from pollution treatment facilities include converted
and fugitive pollutants derived from process emission streams and
constituents used within the treatment system. Emission disposal op
tions include the resale of by-products to other industries, use as
landfill or minefill, or return for further treatment.
381
-------
Pollutants which may be contained in emission streams include
sulfur (S2» S4> H2S, COS, CS2» mercaptans, thiophenes),
nitrogen (N0X, HN3, HCN, thiocyanates), particulate matter (de-
bris, fines, ash, chars), trace elements, wastewaters, organics,
spent capalysts, thermal effluents, noise, carbon dioxide, and
radioactivity (Braunstein et al. 1977).
It must be emphasized that stream characterization is not com-
plete, and available data may not be representatives of commercial
plants. Also, the exact nature and quantity of wastes will vary ac-
cording to coal type, operational design, and plant size.
Discharges with potential environmental impacts can be produced
at each main stage of coal conversion: pregasification, conversion
operations, and waste stream control and treatment. Appendix E
presents pollutant streams and emissions by process step.
Wastes from coal conversion units are currently being charac-
terized. Numerous steps in coal conversion may produce emissions
that are potential pollutants. The potential sources include the ash
and tars that remain underground as potential groundwater contami-
nants, and potential leaks of the effluent gas stream.
SOURCES OF EMISSIONS, EFFLUENTS, AND DISTURBANCES
The major environmental concern associated with in situ gasifi-
cation is the possibility that groundwater disturbances may occur.
Most of the environmental data collected on in situ operations are
based on findings observed at a smaller scale than field scale ex-
periment at HOE Creek site near Gillette, Wyoming. In addition to
groundwater contamination and aquifer disturbance, other areas of
potential concern include air pollution from plant effluents or sur-
face leaks and ground surface disturbances due to subsidence and ex-
plosive fracturing. Emphasis, however, has been placed on the poten-
tial of groundwater contamination by reaction products that remain
underground after gasification is complete. Reaction substances
include the coal ash and organic products of combustion. Soluble
compounds may become dissolved in groundwater as it percolates
through the reaction zone following gasification. It is expected,
however, that the cleansing action of surrounding coal can effec-
tively restrict the potential contaminants to the immediate vicin-
ity of the gasification zone. It has been demonstrated that the coal
matrix has a strong cleansing effect on groundwater pollutants ema-
nating from the gasifier. High concentrations of hydroxides and
metal ions leached from the ash undergo reaction with bound phenolic
end groups of the coal. Similarly, phenolic tars are also strongly
absorbed by the coal (Lamb 1972). The ash and some tars are left in
382
-------
the void creased by the gasification process. Surrounding the gasi-
fication void is a thin layer of char in which pyrolysis, but not
gasification, has taken place. Some of the tars and some product
gases may penetrate the coal or rock outside the char layer. The
extent of the penetration, in part, determines the potential for
groundwater contamination (Stephens 1978).
Following the gasification process, groundwater re-enters the
gasification zone and resumes its natural flow through the coal
aquifer. Reaction products that are soluble are leached and carried
away by the movement of groundwater. The hydrodynamic transport,
dispersion, and sorption of the dissolved reaction products are
variables which determine the future distribution and concentrations
of the remaining contaminants (Stephens 1978). Because of the lack
of extensive experience with this technology, stream characterization
is not complete and available data may not be representative of com-
mercial plants. Also, the exact nature and quantity of wastes will
vary according to coal type, operational design, and plant size.
In situ gasification should produce little or no effect on the
hydrological character of the adjacent rock strata. The burned-out
coal seam will have been filled with a material of low permeability.
The success of the gasification process, however, induces high-
temperature conditions causing the heating of aquifers which would be
otherwise unaffected. This could cause an increase in dissolved
mineral salts (Lamb 1977).
Underground gasification produces a gas product which can be
treated environmentally to remove particulates and sulfur content by
methods similar to those used in treating natural gas. There is the
possibility that subsidence-induced cracks may penetrate to the sur-
face and result in gas leakage (Lamb 1977) if the overburden is sandy
or is shallow.
Other possible disturbances may result from underground sub-
sidence and dewatering operations. Unlike the contaminants which may
be present in water as a result of gasification, the water produced
during pregasification dewatering operations is expected to be of
sufficient quality to be beneficially used for other purposes.
•
The physical aspect of ground subsidence is another area of
environmental concern. In experiments conducted during the Tula
(Podmoskovnaya) and Yuzhno-Abinskaya Soviet gasification studies,
considerable subsidence was detected. When subsidence craters were
formed, gas leakage increased from 15 to 40 percent nominally. This
leakage was reduced to approximately 25 percent by filling the holes
with mud (Stephens 1978). In contrast to the physical resource-
removal activities of above-ground gasification processes, in situ
383
-------
gasification operations may require a filling material which would
have to come from the surface. If suitable fill material is not
readily available, the environmental implications associated with the
potential mining and processing of needed fill could create a variety
of other problems (Lamb 1977)«
SPECIFIC POLLUTANTS
Air Emissions
Because coal gasification occurs in a ^1
be easier to control the emission of D0n system, it should
However, processing steps, auxiliary eauiDmpn/ ftmosPhere'
sions present possibilities for air emissions ' • u?lt:'ve emis~
identify the possible gaseous compounds. • an it is important to
Potential pollutants that may aria.* „
streams are sulfur oxides, nitrogen oxides F ™ore effluent
sulfur compounds, ammonia, hydrogen hvH™,»l P*r ate8' reduced
oxides, tars, oils, various other hydrocafh" cyanide- Pher»ols, carbon
(Hinerli ter 1974). See Table 1. ydrocarbons• ««* trace elements
Because organic sulfur is diffiCult. tn j
treatment and because about 90 percem- nf m "ring coal pre-
verted to hydrogen sulfide, this formof.TtJ-V"','"11'"
the major sulfur contaminant in gas streams nthar*"}"ated to.be
which may be present, include: hydrooo ic-j sulfur species
carbon disulfide, -ercaptan.? andth'L ,ulf,d-./-r«»onyl sulfide,
sulfur dioxide are readily removed frn enea* ydrogen sulfide and
sulfide and carbon disulffdrcan pa88 through I'T' ^ Carb°nyl
emitted to the atmosphere (Braunstein, et 1977)^ tFap8 a"d b®
Hydrocarbon emissions occur by evaooration nf u a
solved in liquid waste and by incomaief- h hydrocarbons dis-
may be emitted also due as a result nf X?n* ^arl)on »onoxide
a result 0f the incomplete combustion.
Other gaseous compounds of interest are carhonui. k j
chloride, hydrogen fluoride trac* are carbonyls, hydrogen
organic. The latter Jo lroZTlf T, ' ."d ««•
«i „ u u , grouP8 ot pollutants will be discussed
else^ere. Although these compounds should be removed i^ the
sing steps, they may be discharged to the air as a reaalr !!/? *
emxssions and from incomplete combustion of exhaust stream LkJ!
siblvDh!^8 °"han"ion °f synthesi. ga,, nickel c.rbonyl ...
s.bly be formed under certain upset conditions. There i, «Led\„
determine the conditions under whi^K a need to
tential pollutants other San thni • conditions may exist. Po-
tv.^ « 1 ! 1 a. ^ • those previously mentioned may exiar
The exact pollutants will be dotsymi j k„ •»«/ exist.
determined by the coal composition and
384
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TABLE 1
COMPONENTS IN GASIFIER GAS (PPM)*
COMPONENT
ILLINOIS
NO. 6
COAL
ILLINOIS
CHAR
WYOMING
SUBBITUMINOUS
COAL
WESTERN
KENTUCKY
COAL
NORTH
DAKOTA
LIGNITE
PITTSBURGH
SEAM
COAL
h2s
9,8000
186
2,480
2,530
1,750
860
Carbonyl sulfide (COS)
150
2
32
119
65
11
Thiophene
31
.4
10
5
13
42
Methyl thiophene
10
.4
7
Dimethyl thiophene
10
.5
11
6
Benzene
340
10
434
100
1,727
1,050
Toluene
94
3
59
22
167
185
C,. aromatics
24
2
27
4
73
27
so2
10
1
6
2
10
10
Carbon disulfide (CS2)
10
Methyl mercaptan
60
.1
•4
33
10
8
The reader should note that these data refer to surface gasifiers. In underground
coal gasification pressure and temperatures are different, thus emissions and their
concentrations emanating from commercial in-situ coal gasification may be different
from surface gasification. Since some of the pollutants are trapped in the coal seam
(coal being an excellent cleansing agent) the concentrations in the product gas would
be somewhat smaller.
SOURCE: Forney et al 1974
-------
the.operating conditions of the gasification process. The fate of
these species will be determined by the product processing steps,
control and treatment facilities, and the likelihood of fugitive
emissions.
Water Effluents
The possibility that adverse changes in groundwater quality
may result from in situ coal gasification is a major enviromental
concern. The reactions that take place underground during in situ
gasification yield a variety of organic and inorganic compounds.
Fugitive tars resulting from pregasification-process water from
the combustion process and potentially from the gas-processing facil-
ity contain a wide variety of organic compounds (Table 2) and
particulates that may collect and, in addition, polycyclic aromatic
hydrocarbons. Of the water-soluble organics, phenols and alcohols
and their methylated derivatives appear to be important. Pyridines,
quinolines, and indoles have also been identified in product waste-
water and may present a significant leaching problem. Miscellaneous
materials in wastewater residues may include hydrogen fluoride, fatty
acids, other trace organics, and trace elements. Trace amounts of
numerous elements appear in coal ash as shown in Table 3. Many of
these elements could be toxic such as mercury, cadmium, arsenic,
selenium, and fluoride if present in large quantity. Significant
differences in mineralogy and chemical forms of produced species may
affect the solubility of accessory elements in the ash and residue
material, and thuB affect their potential as pollutants.
To illustrate the existence of the potential problem, an an-
alysis of the chemical and mineralogical characteristics of an ash
residue from a conventional gasification process is presented in
Table 4. Analysis from the Illinois Herrin (No. 6) coal member
indicated that of the 60 chemical constituents measured in the raw
Lurgi ash, 15 were found to be soluble enough to exceed recommended
water quality levels. Over the pH range 3-10, 9 of the constituent
constituents (B, Ca, Cd, K, Mn, NH4, Pb, SO4, and Sb) exceeded
the recommended levels in all solutions. In UCG, the results could
be very different.
Organic Emissions and Effluents
Coal-derived organic compounds that can be emitted from conver-
sion process streams have not yet been completely characterized. It
has been estimated that, of 10,000 compounds in coal tar and hydro-
generation products, only 1,000 have been identified. This is partly
because the amounts and characteristics of the organics are variable,
influenced by both the coal characteristics and the process operating
386
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TABLE 2
COAL TAR CONSTITUENTS BY BOILING POINT
<1CJ''C
Pent.ine
llexane
Heptone
CycIoh^yane
Butyl^ntj
Amy1ene
Hexene
Heptene
Cyclohexene
1.5-Butadiene
Crotonylene
Cyclopentadlene
Cyclohexadiene
Benzene
Acetone
fethylethyl ketone
Acetonltrile
Carbon disulfide
Methylmercaptan
Ethylmercaptan
Dimethyl sulfide
Diethyl sulfide
Thiophene
100 - ISO'C
Octane
Methyl cydohexane
Oirrsthylcyclohexane
Nonaphthene
Toluene
o-Xylene
m-Xylene
?-Xylene
thylbenzene
Styrene
Pyrrole
Pyr1 d1 ne
2-Methylpyridlne
3-Methylpyrid1ne
4-Methylpyridina
2.6-D1methylpyr1d1ne
TMotoluene
Thloxene
ISO - iOO'C
Dccane
Dicyclopentadlene
Hydrindene
Isopropylbenzene
o-Ethyl toluene
n-Ethyltoluene
p-Ethyltoluene
n-Propyl benzene
Mesltylene
Pseudocumene
Hemellitene
Cyinene
Curene
Isodurene
Indene
2.7-01methylindene
3.6-D1methyl1ndene
Phenol
r-Cresol
Couinarone
D1 me thy 1 counwj r'ont'
Aniline
Toluidine
2.3-Dimethylpyrid1ne
2.4-Oiisiathyl pyridine
2.5-Dinetriylpyri (line
3,4-Diin9thvl oyridine
Oirnethylani 1 ine
2.4.5-Trimethylpyridine
2.1.6-Trimt;t.tiylpyrid1r,e
Benzoni trile
?.00 • ZSC'C
Naphthalene
Dihydronaphthalene
a-Methylnaph thai ene
e-Kethy]naphthalene
4.6-Dimethylindene
5.7-01 methylindene
™-Ci esol
p-Cresol
1.2.3-Xylenol
1.2.4-Xylenol
1.3.4-Xylenol
1.3.5-Xylenol
1,4,2-Xylenol
0-Ethylphenol
m-CthyIphonol
p-Ethylphenol
3-Methyl-5-ethylphenol
Isopseudocumenol
Durenol
2,2'-Di hydroxydiphenyl
Acetophenone
Benzolr. acid
Dimethyl coumarone
1.2,3,4-Tetraniethylpyrldine
QuinoHne
Isoqulnoline
2-Methylquinol1ne
Thlonaphthene
250 - 200°C
D1phenyl
3-Methyldiphenyl
2-Kethyldi phenyl
4-Methyldiphsnyl
4,4'-dimethyldiphenyl
3,4-D1methyldiphenyl
Acenaphthene
1.2-Dimethylnaphthalene
1.6-Diwthylna.phthalene
1.7-Dlmethylnaphthalene
Z.6-G1methyl naphthalene
2,7-D1methy1 naphthaiene
2.3-Dimethy1nap'uhal ene
2-Ethyl naphthalene
1-Ethylnaphthalene
1,2-Cyclopenta»onaphtha1ene
Fluorene
a-Naphthol
5-Naphthol
Oiphenylena oxide
a-Naphthofurane
S-Naphthofurane
1-MethyldiphCfiylone ovidfc
Indole
2-Mlthylindole
3-HethylIndole
4-Methylindole
5-Methylindole
7-Kethylindole
3-Hethylquinoline
4-Methvlquinol ire
5-Methylqui noline
6-Methylqui nol i ne
7-Heth.ylquintline
1-M«thylisoqi.inolin?
3-Methylisoquino' ine
1,3-Dir2thyl isoq'ii nol ine
2.8-Pinsthylquino'i ne
5.8-Dimethylqui 'iol i ne
1-Naphthunitrile
Above iOO'C
Nonadecann
Phenanthrene
Anthracene
2-Methylfluorene
3-Hethylfluorene
Dlhydroanthracene
4,5-Phenanthrylene methane
Chrysogen
Methyl anthracene
Fluoranthene
Pyrene
Tetrahydrofluoranthrene
2,7-0imethylanthracene
1.2-Benzfluorene
2.3-Benzfluorene
Chrysene
1,2-Benzanthracene
Naphthacene
Trlphenylene
Perylene
1,2-Benzpyrene
Crackene
4,5-Benzpyrene
Plcene
1,2-Benznaphthacena
Naphtho-2,3-1,2-anthracene
Acridine
Diphenylene sulfide
Ben zeryt! irene
1-Methylphcianthrene
3-Methylphenantnrene
9-Meth/lphenanthrene
Dibenzocoui'.orone
Carbazole
Benzacarbazsl?
Truxene
2-Methyldirh'iriylpnc oxide
2-Hydro
-------
TABLE 3
RANGE IN AMOUNT OF TRACE ELEMENTS
PRESENT IN COAL ASHES (ppm)
ANTHRACITES
LIGNITES & SUBBITUMINOUS
ELEMENT
Max
Min
Average(5)*
Max
Min
Average(13)
Ag
1
1
**
50
1
**
B
130
90
1,900
320
1,020
Ba
1,340
540
866
13,900
550
5,027
Be
11
6
9
28
1
6
Co
165
10
81(4)
310
11
45
Cr
395
210
304
140
11
54
Cu
540
96
405
3,020
58
655
Ga
71
30
42
30
10
23(12)
Ge
20
20
**
100
20
**
La
220
115
142
90
34
62
Mn
365
58
270
1,030
310
688
Ni
320
125
220
420
20
129(8)
Pb
120
41
81
165
20
60
Sd-
82
50
61
58
2
18(10)
Sn
4,250
19
962
660
10
156
Sr
340
80
177
8,000
230
4,660
V
310
210
248
250
20
125
Y
120
70
106
120
21
51
Yb
12
5
8
10
2
4
Zn
350
155
**
320
50
**
Zr
1,200
370
688
490
100
245
Figures in parentheses indicate the number of samples used
to compute average values.
Insufficient figures to compute an average value.
The reader should note that the conditions under which ash
is formed may affect the final trace element concentration
in the ash. Thus, ash derived from commercial scale in-situ
coal gasification operations (and varying with process) may
vary from these values.
SOURCE: Braunstein, et al. 1977.
388
-------
TABLE A
ELEMENTS EXCEEDING RECOMMENDED WATER QUALITY LEVELS
CONSTITUENT
LURGI
ASH SOLUBILITY
RECOMMENDED
LEVELS
(mg/1)
pH 3
(mg/1)
pH 8
(mg/1)
Al
132.00
0.5
0.10
B
5.5
4.0
0.75
Ca(a)
570.00
290.00
50.00
Cd(a)
0.06
0.02
0.01
Cr
0.12
0.02
0.05
Co
0.19
0.10
0.05
Cu
0.75
0.01
0.20
F
—
—
1.00
Fe
560.00
0.06
0.30
K<«>
26.00
42.00
5.00
Mn(a)
3.80
0.45
0.05
NH4(a)
11.00
17.00
0.02
Pb(a)
0.20
0.10
0.03
SO^3)
338.00
820.00
250.00
Sb(a)
0.60
0.20
0.05
Zn
17.00
0.12
0.20
(a)
Highest pollution potential
SOURCE: Griffen, et al 1978.
389
-------
conditions. Listings of identified and potential organic constitu-
ents and various characteristics are presented in Appendix F. (Braun-
stein et al. 1977).
The gasification process contains all of the products commonly
associated with pyrolysis, carbonization, and coking of coals in ad-
dition to oxygenerated products associated with partial combustion.
Several classes of compounds may be classified as tar (including
phenols, cresols, pyridines, anilines, catechols), intermediate- and
high-boiling aromatics (naphthalenes), saturates, olefins, and
thiophenes. Another group of organic compounds might be designated
light oil and/or naphtha, including BTX, naphathalene, thiophene and
condensable light hydrocarbons and disulfide carbon (Jones et al.
1977).
Possibly the most health-endangering coal-derived compounds are
polycyclic aromatic hydrocarbons (PAH). Workers exposed to high
levels of PAH-containing coal volatiles show an increased incidence
of skin and lung cancers. Coal-derived liquids contain a high per-
centage of aromatic and polyaromatic compounds, although, as in
petroleum, saturated paraffins dominate the low-boiling fractions.
Information concerning atmospheric emission of PAH from coal
conversion processes is scarce. However, coal-burning studies indi-
cate that the majority of PAH is adsorbed on particulate matter.
Humans are most likely to encounter PAH by accidental ingestion,
inhalation, or skin contact. Laboratory animal studies indicate that
skin contact may be considerably more hazardous than ingestion. Aro-
matic hydrocarbons condensed on the exterior surfaces of equipment
and structures may be a significant source of aromatic hydrocarbons
contamination, but as yet little is known on the subject (Braunstein
et al. 1977; Jones et al. 1977). Limited information is available
concerning the bioenvironmental effects of heterocyclic compounds;
however, the behavior of heterocyclics may be similar to that of PAH.
Trace Element Emissions and Effluents
As a result of its organic origin and its intimate relationship
with crustal formations, coal contains a large number of elements in
minor or trace quantities. Of the 92 known nontransuranic elements,
only 14 (shown in Figure 3) have not yet been found in coal. Trace-
element content in American coals is presented in Tables 5, 6, and 7.
Trace elements may be in elemental form or combined in organic
or inorganic compounds. In general, Ge, Be, Sb, and Br have high
organic associations in coal; Ni, Cu, Cr, and Hg tend to be present
in both organic and inorganic combinations; and Zn, Cd, As, and Fe
390
-------
1 °
H
1.00797
1 °
H
Hy4rt4m
m
3 4
Li
MM
4 4
Be
0.0122
5 4
B
10.011
6 4
c
1201115
7 °
N
14.00(7
0 °
0
15J994
9 °
r
101904
i
1
11 *
Na
22.9090
12 *
Mg
24.305
13 4
Al
26.9015
14 4
Si
20.006
15 4
P
30.9739
16 4
s
32.064
17 o
CI
35.453
;r
'A
i
1
IS *
K
31102
20 4
Ca
40.01
21 4
Sc
44.050
22 4
Ti
47.90
23 4
V
50.942
24 4
Ck
51.996
25 4
Mn
54.9300
26 4
Fe
55.147
27 4
Co
50.9332
20 4
Ni
51.71
29 4
Cn
63.54
30 4
Zn
65:37
31 •
Ga
69.72
32 4
Ge
72.59
33 4
As
741216
34 4
Se
70.96
35 •
Br
79.909
Wi
37 4
Rb
IS.47
30 *
Sr
07.82
39 *
Y
10.005
40 *
Zi
01.22
41 4
Nb
92.906
42 4
Mo
95.94
H
H
45 4
Rh
102.905
46 4
Pd
10(4
47 4
Ag
107.070
40 4
Cd
112.40
49 4
In
114.62
50 4
Sn
110.69
51 4
Sb
121.75
52 4
Te
127.60
53 4
I
1261044
JM
hi.
55 •
Cs
132.105
50 4
Ba
137.34
57 4
La
130.01
72 4
Hf
17149
73 4
Ta
100.040
74 *
w
103.15
it
it
H
70 4
Pt
195.09
79 4
An
196.967
(0 •
Hg
200.59
01 4
TI
204.37
02 4
Pb
207.19
93 4
Bi
200.9011
04 4
Po
[210]
KM
06 °
Rn
[222]
i
00 4
Ra
1220]
n
90 *
Th
232.031
n
92 4
U
230.03
*50-71
UndMRli*
50 4
50 4
60 4
M
02 4
63 4
04 4
65 4
66 4
07 4
00 4
B
70 4
71 4
Ce
Pi
Nd
Sm
En
Gd
Tb
Dy
Ho
Er
Yb
Ln
140.12
140.007
144.24
150.35
151.00
157.25
150.924
162.50
104.930
107.26
17314
174.97
SOURCE: Loran et al. 1978.
FIGURE 3
PERIODIC TABLE OF THE ELEMENTS
(THE ELEMENTS SHADED HAVE NOT BEEN FOUND IN COAL)
-------
TABLE 5
MEAN ANALYTICAL VALUES FOR 101 COALS
Consti tuent
Mean
Arsenic, ppm
14.02
Boron, ppm
102.21
Beryllium, ppm
1.61
Bromine, ppm
15.42
Cadnnu.T), ppn
2.52
Cobalt, ppm
9.57
Chromium, ppm
13.75
Copper, ppm
15.16
Fluorine, ppm
60.94
Gallium, ppm
3.12
Germanium, ppm
6.59
Mercury, ppm
0.20
Manganese, ppm
49.40
Molybdenum, ppm
7.54
Nickel, ppm
21.07
Phosphorus, ppm
71.10
Lead, ppm
34.78
Antimony, ppm
1.26
Selenium, ppm
2.08
Tin, ppm
4.79
Vanadium, ppm
32.77
Zinc, ppm
272.29
Zirconium, ppm
72.46
Aluminum, *
1.29
Calcium, %
0.77
Chlorine, %
0.14
Iron, %
1.92
Potassium, %
0.16
Magnesium, %
0.05
Sodium, I
0.05
Silicon, %
2.49
Titanium, %
0.07
Organic sulfur, %
1.41
Pyritlc sulfur, %
1.76
Sulfate sulfur, %
0.10
Total sulfur, %
3.27
Sulfur by X-ray
fluorescence, %
2.91
Air-dry loss, %
7.70
Moisture, S
9.05
Volatile matter, S
39.70
Fixed carbon, S
48.92
Ash, %
11.44
Stu/lfa
12,748.91
Carbon, X
70.28
Hydrogen, i
4.95
Nitrogen, 5
1.30
Oxygen, X
8.68
High-temperature ash, %
11.41
Low-temperature ash, %
15.28
Standard
deviation Min Max
17.70
0.50
93.00
54.65
5.00
224.00
0.82
0.20
4.00
5.92
4.00
52.00
7.60
0.10
65.00
7.26
1.00
43.00
7.26
4.00
54.00
8.12
5.00
61.00
20.99
25.00
143.00
1.06
1.10
7.50
6.71
1.00
43.00
0.20
0.02
1.60
40.15
6.00
181.00
5.96
1.00
30.00
12.35
3.00
80.00
72.81
5.00
400.00
43.69
4.00
218.00
1.32
0.20
8.90
1.10
0.45
7.70
.6.15
1.00
51.00
12.03
11.00
78.00
694.23
6.00
5,350.00
57.78
8.00
133.00
0.45
0.43
3.04
0.55
0.05
2.67
0.14
0.01
0.54
0.79
0.34
4.32
0.06
0.02
0.43
0.04
0.01
0.25
0.04
0.00
0.20
0.80
0.58
6.09
0.02
0.02
0.15
0.65
0.31
3.09
0.86
0.06
3.78
0.19
0.01
1.06
1.35
0.42
6.47
1.24
0.54
5.40
3.47
1.40
16.70
5.05
0.01
20.70
4.27
18.90
52.70
4.95
34.60
65.40
2.89
2.20
25.30
464.50
11,562.00
14,362.00
3.87
55.23
80.14
0.31
4.03
5.79
0.22
0.78
1.84
2.44
4.15
16.03
2.95
3.28
25.85
4.04
3.82
31.70
SOURCE: Ruch , et al, 197h
392
-------
TABLE 6
TRACE ELEMENT CONTENT OF AMERICAN COALS
(ppm in Coal)
REGION
ELEMENT
NORTHERN
GREAT PLAINS
WESTERN
INTERIOR
EASTERN
INTERIOR
APPALACHIAN
Beryllium
1.5
1.1
2.5
2.5
Boron
116
33
96
25
Titanium
591
250
450
340
Vanadium
16
18
35
21
Chromium
7
13
20
13
Cobalt
2.7
4.6
3.8
5.1
Nickel
7.2
14
15
14
Copper
15
11
11
15
Zinc
59
108
44
7.6
Gallium
5.5
2.0
4.1
4.9
Germanium
1.6
5.9
13
5.8
Molybdenum
1.7
3.1
4.3
3.5
Tin
0.9
1.3
1.5
0.4
Yttrium
13
7.4
7.7
14
Lanthanum
9.5
6.5
5.1
9.4
SOURCE: Zuboric 1975.
393
-------
TABLE 7
DISTRIBUTION OF ENVIRONMENTALLY HAZARDOUS
TRACE ELEMENTS (ppm In Coal)
ELEMENT
Antimony
Arsenic
Beryllium
Cadmium
Mercury
Lead
Selenium
Zinc
REGION
POWDER
RIVER BASIN
0.67
3
0.7
2.1
0.1
7.2
0.73
33
WESTERN
INTERIOR
3.5
16
2
20
0.13
5. 7
EASTERN
INTERIOR
1.3
14
1.8
2.3
0.19
34
2.5
250
APPALACHIAN
1.2
18
2.0
0.2
0.16
12
5.1
13
SOURCE: Zuboric 1975.
394
-------
are primarily associated with coal mineral matter. Several investi-
gations have also indicated that pollution in coal combustion and
conversion will for the most part be associated with the inorganic
matter in coal. It is possible that enhanced volatility of an or-
ganically associated trace alement could lead to its concentration
in the groundwater (Kuhn et al. 1978).
Fates of trace elements in coal conversion are not completely
known. Trace-element pathways may include adsorption on particulate
matter, inclusion in condensates, inclusion in by-products and final
products, and emission as fugitive pollutants, thus requiring de-
velopment of a variety of suitable control technologies (Braunstein
et al. 1977).
The fate of trace elements in coal gasification can be very dif-
ferent from that experienced in conventional coal-fired furnaces.
One reason is that the conversion operations take place in a reducing
atmosphere, whereas in combustion the conditions are always oxidiz-
ing. This affects the resultant oxidation state and the subsequent
tendency of the elements to combine or dissolve in the major ash com-
ponents. Furthermore, the reducing atmosphere may form hydrides,
carbonyls, or sulfides which may be more volatile than combustion
elements.
to
Many of the trace elements volatilize to a small or large extent
during processing, and many of the volatile components can be highly
toxic. This is especially true for mercury, selenium, arsenic, moly-
bdenum, lead, cadmium, beryllium, and fluorine. Beryllium, mercury,
and lead do not form gaseous hydrides, will condense on cooling, and
will very likely be removed by the aqueous condensates formed on gas
cooling and/or purification. Arsenic, antimony, and selenium have
lower volatility but can form gaseous (covalent) hydrides: arsine,
stibine, and hydrogen selenide (Magee 1976).
Consideration must also be given to trace metals that are not
volatilized and remain in the char and ash residue where leaching
could occur. Trace elements from coal conversion and use pose at
least as serious a potential bioenvironmental hazard as do organic
effluents. Because some trace elements are resistant to metabolic
detoxification and all are nondegradable, they can accumulate in
biota. Also, once released, they persist in the environmental in-
definitely. Some trace metals already exist in the environment at
maximum or near-maximum permissible levels.
Lead, mercury, arsenic, vanadium, selenium, nickel, and pos-
sibily cadmium and fluoride may be important environmentally. Lead,
mercury, and cadmium are particularly important because they are cap-
able of long-distance transport (Braunstein, et al. 1977).
395
-------
Although considerable data are available concerning the acute
health effects from trace elements, little is known about low-level
chronic effects to be expected from the amounts and forms of these
elements as they may be emitted from coal conversion operations.
Lead, chromium, manganese, arsenic, fluoride, nickel, cadmium, zinc,
and copper may pose human health hazards^
396
-------
REFERENCES
Braunstein, H.M. (ed.); Copenhaver, E.D., Pfuderer, H.A., 1977.
Environmental, Health and Control Aspects of Coal Conversion: An
Information Overview, Volumes I & II, ORNL EIS 94/93, Prepared for
ERDA by Oak Ridge National Laboratory, Oak Ridge, Tennessee.
Corbett, W.E., 1978. Low-Btu gasification—environmental
assessment, In Proceedings: Environmental Aspects of Fuel Con-
version Technology III Symposium. EPA-600 EPA-600/7-78-063, U.S.
Environmental Protection Agency, 1978a.
Dickson, E.M., Steels, R.V. Hughes, E.E. Walton, Zink, R.A.,
Miller, P.D., Ryan, J.W., Simmon, Holt, B., White, R.K., Harvey,
E.C., Cooper, R., Phillips, D.F. and Stoneman, W.C., undated.
Impacts of synthetic liquid fuel development, vol. I, Summary
76-129/1, Prepared for U.S. Energy Research and Development
Administration, by Stanford Research Institute, Menlo Park,
Cali fornia.
Enviro Control, Inc., 1978. Recommended health and safety guidelines
for coal gasification pilot plants, DHEW (NIOSH) Pub. No. 78-120,
U.S. Department of Health, Education, and Welfare, Rockville,
Maryland, January 1978.
Forney, Albert J., 1974. Analyses of tars, chars, gases, and water
found in effluents from the synthane process, Technical Process
Report 76, Pittsburgh, Pennsylvania, Pittsburgh Energy Research
Center.
Griffin, R.A., Schuller, R.M., Suloway, J.J., Russell, S.J.,
Childers, W.F., and Shimp, N.F., 1978. Solubility and toxicity of
potential pollutants in solid coal wastes, In Symposium Proceed-
ings: Environmental Aspects of Fuel Conversion Technology III,
EPA-600/7-78-063. U.S. Environmental Protection Agency, April 1978.
Hinderliter, C.R., 1974. Environmental aspects of the SRC pro-
cess. In symposium on the EPA environmental aspects of fuel
conversion technology. St. Louis, Missouri, May 1974.
Hughes, E.E., Dickson, E.M and Schmidt, R.A., 1974. Control of
Environmental Impacts from Advanced Energy Sources. Report No.
PB-239 450, EPA-600/2-74-002. EPA Conract No. 68-01-0483. Menlo
Park, California, Stanford Research Institute.
397
-------
Hughes, E.E., Dickson, E.M. and Schmidt, R.A., 1974. Control of
environmental impacts from advanced energy sources. Report No.
PB-239 450, EPA-600/2-74-002, EPA Contract No. 68-01-0483. Menlo
Park, California, Stanford Research Institute.
Jones, D.C., Clark, W.S., Holland, W.F., Lacy J.C. and Sethness,
E.D., 1977. Monitoring environmental impacts of the coal and oil
shale industries: research and development needs,
EPA-600/7-77-015, prepared for U.S. Environmental Protection Agency
by Radian Corporation, Austin, Texas.
King, S.B., 1977. Composition of selected fractions from coal tars
produced from an underground coal gasification test, Preprint,
Annual ACS Meeting, New Orleans, Louisiana.
Kuhn, J.D., Kidd, D., Thomas, J., Cahill, R., Dickerson, D., Shi ley,
R., Kruse, C., and Shimp, N.F., 1978. Volability of coal and its
by-products, In Symposium: environmental aspects of coal conver-
sion technology III, EPA 600/7-78-063, U.S. Environmental Protec-
tion Agency.
Lamb, G.H., 1977, Underground coal gasification. Noyes Data
Corporation, New Jersey.
Loran, B.I. and O'Hara, J.B., 1978. Specific environmental aspects
of Fischer-Tropsch coal conversion technology, In Symposium on en-
vironmental aspects of coal conversion technology III, EPA
600/7-78-063, U.S. Environmental Protection Agency, April 1978.
Mages, E.M., 1976, Evaluation of pollution control in fossil fuel
conversion processes: final report, EPA-600/2-76-EPA-600/2-76-101.
Prepared for U.S. Environmental Protection Agency, by Exxon Re-
search and Engineering Company, Linden, New Jersey.
Pellizzari, E.D., 1978. Identification of components of energy-
related wastes and effluents, EPA-600/7-78-004. Prepared for the
U.S. Environmental Protection Agency by Research Triangle
Institute, Research Triangle Park, North Carolina.
Philips, N.P., and Muela, C.A., 1977. In-situ coal gasification:
status of technology and environmental impact, EPA-600/7-77-045.
Prepared for U.S. Environmental Proteciton Agency, Office of Re-
search and Development by Radian Corporation, Austin, Texas.
398
-------
Ruch, R.R., Gluskoter, H.J., and Shimp, N.F., 1973. Distribution of
trace elements in coal, Symposium on environmental aspects of fuel
conversion technology, EPA-650/2-74-117.
Salk, M.S., and DeGicco S.G., eds., 1978. Environmental monitoring
handbook for coal conversion facilities, ORNL-5319. Prepared for
the Department of Energy by the Fossil Energy Environmental
Project, Energy Division, Oak Ridge National Laboratory, Oak Ridge,
Tennessee.
Sikri, Atam P. and Edward L. Burnwell, 1979. The Department of
Energy underground coal gasification program. Presented at the
Annual Meeting of the American Association for the Advancement of
Science, 3-8 January, Houston, Texas.
Sandia Laboratories. 1978. Proceedings of the 4th Underground Coal
Conversion Symposium, Steamboat Springs, Colorado, 17-20 July,
1978, SAND 78-0941. Albuquerque, New Mexico.
Stephens, D.R. and Minkel, K.J., eds., 1978. Lawrence Livermore
Laboratory In-situ coal gasification program, Annual Report Fiscal
Year 1977. October 1976 through September 1977, prepared for the
U.S. Department of Energy, March 1978.
U. S. Department of Energy, 1978a. Environmental Development Plan
(EDP): Underground coal conversion Program, FY77.
U. S. Department of Energy, 1979b. Fossil Energy Research and
Development Program of the U.S. Department of Energy FY1979,
DOE/ET-0013(78)).
Zubovic, P., 1975. Geochemistry of Trace Elements in Coal, Reston,
VA: U.S. Geological Survey, Reston, Virginia, 1975.
399
-------
Appendix A
Conventional Coal
-------
401
-------
FIGURE A-2
DISTRIBUTION OF UNITED STATES COAL RESOURCES
-------
TABLE A-l
COMPARISON OF COAL MINING METHODS
O
U)
TYPE
OF
MINING
PERCENT OF TOTAL
U.S. COAL
PRODUCTION(a>
RECOVERY
rateO>)
COAL LOSSES
DISADVANTAGES
ADVANTAGES
Underground
• in pillars left to
• subsidence
• only economically
Mining
46.0
50-60%
support mine
• mine safety
feasible method to ex-
• respiratory illness
tract coal from seams
• acid mine drainage
at depth
• mine fires
Strip
• spillage
• acid drainage
• no severe safety
Mining
45.6
80-90%
• losses in transit
• expensive land
problems
reclamation
• can be used econom-
ically only to a
maximum depth of
overburden of 200
feet
Auger
• governed by
• allows recovery of coal
Mining
0.5
50-75%
amount of coal
that would otherwise be
left between
left in place
holes
Combination
Strip and
Auger Mining
7.9
(c)
(c)
(c)
(c)
(a)
SOURCE: U.S. Department of the Interior, Bureau of Mines, 1976. Mineral Industry Surveys, Coal-Bituminous and
Lignite in 1974. Washington, D.C.
^SOURCES: U.S. Department of the Interior, Bureau of Mines, 1975. The Reserve Base of U.S. Coals by Sulfur
Content, Part I, The Eastern States, IC 8680, Washington, D.C.
U.S. Department of the Interior, Geologic Survey, 1975. Coal Resources of the United States,
January 1, 1974. Washington, D.C.
(c)
Combination of Strip Mining and Auger Mining findings.
-------
TABLE A-2
BITUMINOUS COAL AND LIGNITE
SHIPMENT METHODS, 1974(a)
METHOD
QUANTITY
(Thousands of Short Tons)
PERCENT OF
TOTAL
Railroad
397,161
65.8
Waterway
67,754
11.1
Truck
66,382
11.0
Mine-Mouth
Consumption
66,635
11.1
Other
5.474
1.0
603,406
100.0
(a)
SOURCE: U.S. Environmental Protection Agency. 1977.
Accidents and Unscheduled Events Associated with
Nonnuclear Energy Resources and Technology. EPA
600/7-77-016. Office of Research and Development,
Washington, D.C.
^includes coal used at the mine for power and hear,
coal used by mine employees, and coal shipped by
slurry pipeline.
404
-------
TABLE A-3
ELECTRIC POWER GENERATION BY ENERGY RESOURCE
RESOURCE
CONTRIBUTION BY RESOURCE,
kWhe
X 109 (%
OF TOTAL)
1973
1974
1980 Proj.
1990 Proj.
Coal
846.0
(45.7)
828.4 (44.5)
1310
(48.5)
1720
(36.6)
Oil
310.7
(16.8)
298.2 (16.0)
453
(16.8)
450
(3.6)
Gas
336.0
(18.2)
320.2 (17.2)
242
(9.0)
190
(4.0)
Hydroelectric
271.1
(14.7)
300.3 (16.1)
292
(10.8)
319
(6.8)
Nuclear
83.3
(4.5)
112.0 (6.0)
400
(14.8)
2000
(42.5)
Other
2.3
(0.1)
2.7 (0.1)
3.5
(0.1)
2.1
(0.5)
Total
1849.3
(100.0)
1861.9 (99.9)
2700
(100.0)
4700
(100.0)
SOURCE: U.S. Environmental Protection Agency 1977a.
-------
TABLE A-4
ENVIRONMENTAL RESOURCE USE AND POLLUTANT
RELEASE ASSOCIATED WITH COAL USE
The specific base units included in the coal fuel cycle range from coal mining and benefi-
ciation to its use for the generation of electric power by several possible methods. The trans-
portation of the coal and the transmission of the power generated are also included.
Each base unit is presented as a function of the energy content of the material produced.
All are standardized to 10^2 Btu's of energy product. This allows comparison of different
products, with different energy contents produced by various technologies, each with different
efficiencies and capacity factors, within the coal fuel cycle.
Emissions within this fuel cycle are highly dependent upon the type of coal used as well
as the control technology assigned to the base unit in question. Each base unit is assumed to
be equipped with currently available control technologies. The conventional boiler, for ex-
ample, has an electrostatic precipitator and a flue gas desulfurization scrubber. While this
results in the removal of most of the particulate matter and sulfur dioxide in the flue gas
stream, it creates a new environmental problem—the disposal of sludge. Control technologies
and the resultant net emissions are indicated where applicable for each base unit.
Since the type of coal used is a major determinant of environmental residuals, base units,
where applicable, are shown for two different coal types. One coal is an eastern coal, the
other is a western coal. The eastern coal is typical of the Monongalia group, which are high
sulfur and high energy content coals. The western coal, Powder River coal, has much less
sulfur, but also a substantially lower heating value.
SOURCE: The MITRE Corporation 1978.
-------
TABLE A-4 (Continued")
Surface Coal Mining - Eastern
ENERGY SYSTEM:
SIZE •capacity Is 600 tons/day
• aloe operates 250 days/year
• 150,000 tons/year or
• 4.11 z 10^-2 Btu'a/year
• Eastern strip mine, Northern
Appalachla district
DESCRIPTION
•eastern strip operation consisting
of drilling, loading and blasting the over-
burdm, excavation to expose coal seam and
remove coal, saoothlng piles of overburden,
replacing topsoll and revegetatlng area
COMPONENTS
e power shovels
• trucks
• front end loaders
• scrapers
• draglines
• bucketvheel excavators
• drilling equipment
• graders
• cable handler 6 reel
• pusps
• bulldozers
MAJOR ENVIRONMENTAL FRO BLOB
• solid waste
• reclamation
• acidic nine drainage cont—lnatlon of
surface and groundwater
• blasting damage and noise pollution
• vehicular Missions
• fugitive dust
• erosion
RESOURCES USED:
(Per 10*2 Btu Produced)
FUEL*
coal
energy content
Coal analysis
aolsture
volatile matter
fixed carbon
ash
sulfur
nitrogen
ENERGY
diesel fuel
electricity
WATER
dust suppression
(consumptive use)
COSTS
construction
power shovels
trucks
front end loaders
scrapers
road graders
bulldozers
cable handler & reel
drills
puvps
miscellaneous (elec trical,
storage and office, site
preparation, exploration)
engineering
total
operation & maintenance
labor
supplies
power
reclamation
miscellaneous
total
36,530 tons
13,690 Btu/lb
I
2.0
35.3
54.4
8.3
2.8
1.1
1.18 x 10' Btu
5.87 z 105 kwti
Acres
16 79-77". 9
Dollars (1975)***
267,400
18,400
5,600
8,200
1,300
9,200
1,300
17,900
100
25,100
7,200
361,700
17,600
27,000
9,500
1,500
63,500
119,100
RESIDUALS AND PRODUCTS:
(Per 10^-2 Btu Produced)
AIR POLLUTANTS (net)
particulates
S02
HO*
hydrocarbons
CO
aldehydes
WATER POLLUTANTS (gross)
total dissolved solids
total suspended solids
suspended Iron
dissolved iron
manganese
aluminum
zinc
nickel
sulfate
hardness
acidity
SOLID HASTE + (net)
tailings and waste from
mine runoff
ENERGY PRODUCT
Tons
0.1031
0 .214
2.936
0 .294
1.789
0 .048
Tons
35.583
4.812
0 .017
0 .439
0 .394
0 .622
0 -015
0 .006
16.144
0 .056
17.038
NA
Tons
412-668
Tons
36,530
PERSONNEL
construction (3 years)
operation
Workers/Year
*For mining, coal input ¦ coal output (by definition).
**This figure is based on a mine producing 4 million tons of coal per year.
***These costs are based on a strip mine producing 4.8 million tons of coal annually. This mine does not use draglines or bucketvheel excavators.
^Assumes reclamation of strip mine areas.
SOURCES: The MITRE Corporation, Annual Environmental Analysis Report, 1977.
Unlveriity of Oklahoma, Energy Alternatives: A Comparative Analysis, 1975.
TRW, Ness Environmental Data Book, Volume IV, 1978.
Hlttman Associates, Inc., Environmental Impacts, Efficiency, and Cost of Energy Supply and End Use. Volume I, 1974.
Bechtel Corporation, "Energy Supply Planning Model", 1978.
Bureau of Mines, Basic Estimated Capital Investment and Operating Costs for Coal Strip Mines. 1976.
In revision for updating.
-------
TABLE A-4 (Continued)
Surface Coal Mining - Western
EHEKG? STSTW:
SIZE • capacity Is 4,000 tons/day
m 000,000
« operates ^ d^f»/year
• annual yield Is 1.6S x lO^ Btu
• Western atrip nine, Campbell Co.,
Vy owing
DESCRIPTION
• Large strip ilnlnt operation capable
of producing 4,000 tons/day of Wyoming
Campbell Co. coal 250 days/year.
Operation conaiats in drilling, loading
and blasting the overburden, excavating
to expose coal scan and ronove coal,
smoothing piles of overburden, replacing
topsoil and revegetating area, trans-
porting coal to cleaning area.
COffONBITS
e power shovels
• trucks
• front end loaders
• P«"P«
• scrapers
• draglines
• bucket wheel excavation
• bulldozers
• drilling equipment
• graders
• electrical equipment
RESOURCES USED:
(Per 10^ Btu Produced)
RESIDUALS AND PRODUCTS:
(Per 10*2 Btu Produced)
MAJOR EKTCaOttgHAI. P80BLB6
• fugitive dust
• solid mitt disposal
PPEL
AIR POLLUTANTS
Tons
coal
bO
,200 tons
particulates
energy content
6
,300 Btu/lb
uncontrolled
(control techniques used to
2.280
Coal analvsl8
I
control fugitive dust )
0.850
noisture
28.1
SO 2
0.129
volatile natter
32.4
NO,
1.290
fixed carbon
33.6
hydrocarbons
0.129
ash
5.9
CO
0.803
sulfur
0.6
aldehydes
0.019
nitrogen
ENERGY
1.2
WATER POLLUTANTS (gross)
alkaline surface nine drainage.
Tons
diesel fuel
7.
91 x 10® Btu
runoff from solid waste piles
electricity
1.
.14 I 105 Kvh
total dissolved solids
total suspended solids
90.936
3.044
LAMP
Acres
suspended Iron
0.020
3.87
dissolved iron
0.005
WATER
Acre-Ft .*
¦anganese
0.019
dust suppression
alunlnun
zinc
nickel
0.006
0.005
0.001
(consumptive use)
3.05
COSTS
Dollars**
sulfate
41.139
construction
aroor.l a
0.133
dragline
73.000
hardness
40.91"
bulldozers
9,900
alkalinity
XA
drills
8,100
scrapers
17,600
SOLID WASTE ***
Tons
cable handler & reel
1,100
tailings+
~7TCT
power shovels
IB,800
front-end loaders
4,800
ENERGY PRODUCT
Tons
truck*
31.500
nined coal
bCCTXl
road grsder
1,100
puops
100
miscellaneous (electrical.
• reclamation
preparation 6 exploration1 26,700
• alkaline nine drainage
engineering
3,900
e erosion
total
194,700
operation & maintenance
labor
17,200
operating supplies
27,100
power
: ,200
reclamation
2,*00
miscellaneous
"'i.fcoe
total
12S.500
PERSONNEL
Workers Tear
construction (2 years)
HA
operation
1.40
*Thi» figure is based on a *1m prc>duciog 6 aillicm terns of coal per year.
••Reference year for coats not indicated la source material. These cost* ar« Sa»ec! or a strip sio# producing 9.2 nillic*n ton* of :oi] jnnuiiiv.
This Mine does not use bucketvbeel excavators.
*MA«fiae« control technology used.
*1t la not knows whether this figure Includes solid waste from nurface sine runoff.
Th« HI 7*1 Corporation, Animal Eovlrows"" *»»1y»ls Resort. 1977.
Onlverslty of Oklahoma, Energy Alternatives; A Cosparstfve Analyla. 197$.
T*V, Mesa Environ—ntal Pets hook. Vol vase IV. 1978.
SitCMA Associates, Inc., Environmental Impacts. Efficiency, sad Cost of Energy Supply snd End Use. Voltse I. 1974.
lachttl Corporation, "latriy Supply Planning IMsiu« lvls.
ftureau of Mines, fatlt Eatlnsted Capital Invesfsat and OwittM Costs for Coal Strip Win—. 1976.
In revision for updating.
-------
TABLE A-4 (Continued)
Underground Coal Mining
Eastern
ENERGY SYSTEM:
RESOURCES USED:
RESIDUALS AND PRODUCTS:
(Per lO*2 Btu Produced)
(Per 10^2 Btu Produced)
SIZE • operates 250 days/year
FUEL *
AIR POLLUTANTS
Tons
• 2,500 tons/day
coal
36,530 tons
Air emissions from equipment
• 625,000 tons/year
energy content
L3.690 Btu/lb
are not considered a problem
• 17.1 x 10*2 BCu/year
in underground extraction
Coal Analysis
X
since most equipment Is
DESCRIPTION
moisture
2.0
electric powered.
• A large underground mining operation
volatile matter
35.3
capable of producing 2,500 tons/day
fixed carbon
54.4
particulates
negligible
of Monongalia coal, 250 days/year.
ash
6.3
S02
negligible
Operation consists of preparing sur-
sulfur
2.8
NO,
negligible
face by constructing access roads and
nitrogen
1.1
hydrocarbons
negligible
facilities, bringing necessary utili-
CO
negligible
ties to site and clearing vegetation,
ENERGY
KWh
aldehydes
negligible
digging or boring a vertical shaft or
electricity
7.21 x 105
horizontal tunnel to reach coal de-
WATER POLLUTANTS (gross)
Tons
posit. A passageway is excavated
LAND
Acres
total dissolved solids
396.394
through the coal seam, rooms are forced
total land use
130
total suspended solids
19.031
by aiiiing the coal, leaving portions in
suspended iron
7.01
place as support pillars for the over-
WATER
Acre-Ft.**
dissolved iron
22.37
lying strata. Mined coal is loaded
dust suppression
manganese
0.609
onto transportation equipment.
(consumptive use)
7,30
aluminum
3.623
zinc
0.122
COMPOKQfTS
COSTS
Dollars***
nickel
0.060
• trucks
construction
sulfate
197.822
a conveyors
continuous miner
62,200
ammonia.
1.004
• roof bolting machines
loading machine
16,600
strontium
0.203
a ventilating fans
shuttle car
30,600
chloride
8.597
• drilling equipment
roof bolter
14,700
fluoride
0.114
s cutting machines
ratio feeder
9,300
hardness
101.665
• continuous mining machines
ventilating fans
5,000
s hoisting equipment
Jeeps
6,800
SOLID WASTE
• elevators
rock duster
10,500
Solid waste is produced in
• pwps
supply motor
3,200
sinking the mine shaft. Non-
coal
• loading machines
supply car
2,700
matter mined is slso a source
of
• shuttle car
conveyor
60,900
solid waste! Finally, sludge
is
• ratio feeder
power center
23,100
produced from the treatment of
• rock duater
trolleywlre & track
11,200
underground mining runoff.
• supply motor
vaterllnes & pumps
4,100
• power center
tractors
8,400
• rectifier
front end loader
2,100
ENERGY PRODUCT
Tons
forklift
1,500
mined coal
36,530
MAJOR ENVIROWCNTAL PROBLEMS
bulldozer
3,400
• solid waste disposal
trucks
500
• runoff from waste piles
mine drainage & treatment
• acid nine drainage
plant
1,300
• subsidence of surface area
miscellaneous (communications,
m fugitive dust
safety equipment, warehouse.
• brown lung disease affecting miners
and storage, site prepara
-
• noise
tion and exploration)
37,600
engineering
6,400
total
322,300
operation & maintenance
labor & supervision
100,800
supplies
67,300
power 6 water
14,000
miscellaneous
103,500
total
285,500
PERSONNEL
Workers/Year
construction (3 years)
NA
operation & maintenance
8.46
•for mining, coal input - coal output (by definition)
**thls figure is for a mine producing 2 million tons of coal/year
"•reference year for costs not indicated in source material
SOURCES: The MITRE Corporation. Annual Environmental Analysis Report. 1977.
University of Oklahoma. Energy Alternatives
: A Comparative Analysis. 1975.
TRW, Ness Environmental Data Book.Volume IV
, 1978.
Hlttman Associates. Inc.. Environmental Impacts. Efficiency* and Cost of
Energy Supply and End
Use. Volume I. 1974.
Bechtel Corporation, "Energy Supply Planning Model", 1978.
Bureau of Mines, Basic Estimated Capital Investment and Operating Costa for Coal StriD Mines.
1976.
In revision for updating.
-------
TABLE A-4 (Continued)
Coal Beneficiation
EXQtGT SYSTEM:
SIZE • Processes 2,857,000 ton* of run-of-mine (KOM)
coal each year Co produce 2 million Coos of
clean coal
s hourly capacity 950 cons of KM coal input,
therefore system operates about 3000 hours
per year (34Z cleaning plant utilization}
• plant lifetime at least 20 years
s 87.5X efficiency (in tens of Btus)
s yield by weight is 7OX
EESCttUTIOM
s Coal beneficiation is s process for cleaning
coal prior to its use for Metallurgical or
utility purposes. The purpose of beneflcla-
tlra la to rcriore impurities (i.e. ash and/or
sulfur) froa KM coal. The degree of benefi-
ciation uflt/td depends oo the type of coal
end Its ultlaate use. The system described
in this suaaary sheet (elaborate beneficiation)
Is s relatively intense procedure. It removes
¦ore sulfur and ash than aoat other types of
beneficiation, but it is also more costly.
issotnuxs USED:
(Per 10*2 Btu Produced)
FUEL
run-of-mine (ROM)
(assisting one ton of BOH coal
has an energy content of 24
mlllioa Btus and one ton of
cleaned coal has an energy
content of 30 million Btus)
r EHERGT*
electricity
oil
T0D8
47,620
e scalping screen
e crusher
s rotary breaker
e vibrator screens
e jigs
s heavy —d<« vessels or cyclones
s d its taring equipment
e thickeners
s filters
e concentrating tables or hydrocyclones
e flotation circuits
s theraal drying
majok nyneirm Ptouac
e fugitive dust affecting workers
e solid waste djaposal
e surf see water ceatartnation froa settling
pond overflow and/or refuse pile runoff
s possible grotmd water contamination froa
settling pond leaching
e noise
cashing plant
loading facility
settling pond
total
r WATER
wet cleaning
r COSTS
construction
operation and aalntenance
PEgSOWEL
construction (1 year)
operation and aalntenance
1.77 a 10^ 1
5.19 * 10 1
Acres **
0.08
0.67
0.83
1.60 + 0.8
Acre-Pt.
220-290
Dollars (1978)*
385,800
81,700
Workers/Tr
RESIDUALS AND PRODUCTS:
(Per 1012 Btu Produced)
r AIR POLLUTANTS
particulates
s?
hydrocarbons
CO
r MATER POLLUTANTS *
total dissolved solids
I iron
i manganese
aluminum
sine
nickel
sulfates
total suspended solids
iron
nutrients
SOLID WASTE
primary breaking
rough cleaning
raw-coal siring
dense aedis
tables
froth flotation
theraal drying
breaking and sizing
he*t
ittle or none
0.20
Tona+4-
0
2.81
0
11,260
6,560
9,370
0
2.81
BOISE
noise asy affect workers involved in
cleaning coal, but there should be
little or no adverse Impact oo land
near beneficiation planta.
KHEBCT PRODUCT
cleaned coal
Ton*
33,300
Ifcey are national averages (aaatmlng
These figures were calculated assuming an energy content of 12,100 btu/lb of coal (Hittsan 1974).
an energy efficiency of 91.3Z) and do not apply to elaborate beneficiation in particular.
These -coefficients msy be subject to error since toe dsts source presented only the fixed amount of lsnd used without specifying the plant's
annual output of coal. In calculating these coefficients, it was sssu—rl here that plant output was the same as that specified in the
"slae" section of this sheet.
The source used 1976 dollars Inflated to 1978 dollars.
These figures are weighted national averages based on regional coefficients projected by SEAS for 1979. The regional coefficients were
weighted in tezas of Btus used. Each of the coefficients shown In this sheet is equal to total national tons of residual divided by total
national Btu output.
These figures Include resldusls both froa refuse piles snd the beaeflelstlon prdcess Itself. They ssnatd that 80S of coal preparation
plants are closed cycle and that all refuse la treated. An efficiency of 90X (In Btus) waa assumed.
Baaed on national averages in Hlttasn.
Tons (Met)
0.90
0.005
0.59
0.23
0.17
Tons* (wet)
33.0
0.007
0.034
0.041
0.005
0.003
18.2
0.59
0.064
0.049
Pster Phillips and Paul DsRlenco, "Assessing the Economics of StSM Coal Preparation", Coal Mining 4 Prorettlng. Sept*
DOB and EPA. Eaalnsarlna/Econasile Analysis of Coal Preparation with BO* Cl—i» Processes. 1978.
Hlttasn Associates. Enrlm»ant*l Tiarta. t/flclancr. and Post of Energy Supply and End Pss. 1974.
Am MX1SI Corporation, Anal Egrirnnaantel Analysis Report. 1977.
University of Ofclahoae, Easrav Alternatives? A Co—srs*<— 1975•
>er 1977.
Augugt 1979
-------
TABLE A-A (Continued)
Conventional Boiler - Eastern Coal
Tons
ENERGY SYSTEM:
SIZE • 500 MWe
• heat rate 10,000 Btu/KWh
• Btu equivalent
• thermal efficiency 34Z
• capacity factor 55Z
• energy production 8.2 x 1012
Htu/year
DESCRIPTION
• Three model plants are considered. The
first model plants meet Ohio's state
Implementation plan air pollution regu-
lations. The second meet the current
USPS regulations and the third meets a
proposed revised NSPS regulation
• current NSPS
- particulates 0.1 lb/106 Btu
(coal input)
- sulfur oxides 1.2 lb/10^ Btu
(coal input)
• revised NSPS
- particulates 0.05 lb/10 Btu
- sulfur oxides reduction of 87Z
COMPONENTS
• coal handling systen
• coal crushing/conveying system
• coal pulverizing
• p.f. boiler
• feed water treatment
« air preheater
• econooiser
a flue gas desulfurlzation (FGD) (when
regulations are applicable)
• settling ponds
• electrostatic precipitator (ESP) (for
all three plants)
• cooling towers
MAJOR ENVIRONMENTAL PROBLEMS
• SO2 aniasiona from plants not required
to Install scrubbers
• SO* Missions
• potential leachate of trace elements
from ash/sludge
• water use (in certain areas)
RESOURCES USED:
(Per 10" Btu Produced)
RESIDUALS AND PRODUCTS:
(Per 10^ Btu Produced)
Plant
Under
NSPS
Plant
Under
Revised
NSPS
Plant Meeting
State Imple-
mentation Plan
FUEL *
Btu/lb
AIR POLLUTANTS
Gross
Net Net
Net
coal: North Central Appalachian
particulates
8805.8
147.0
73.5
320.5
heat content
LI, 500
SO 2
6802.9
1764.7 822.9
5008.8
N°x
1326.4
1023.5 862.3
1326.4
Coal Analysis
sultur
I
hydrocarbons
19.1
19.1
19.1
19.1
2.3
CO
63.2
63.2
63.2
63.2
ash
9.2
arsenic
1.2
1.4
1.4
1.4
berylliw
0.20
0.14
0.14
0.14
ENERGY
Z
cadmium
0.03
0.0014
0.0014
0.0014
(requirements for pollution
fluorine
7.0
0.54
0.54
0.54
control devices)
lead
1.2
0.10
0.10
0.10
electrostatic precipitator
0.44
mercury
0.16
0.16
0.16
0.16
flue gas desulfurlzation
5.8
selenium
0.44
0.14
0.14
0.14
manganese
20.5
1.2
1.2
1.2
LAND
Acres
gross plant
33.8
WATER POLLUTANTS
Tons
waste disposal
23.2
BOD
COD
1.41
137.18
total suspended solids
.33
WATER
Acre-Ft.
total dissolved
solids:
873.53
total (for water
124.6
aluminum
.30
pollution abatement)
chromium
.01
non-ferrouS metals
110.79
COSTS
Dollars**
line
.05
construction
540,507
sulfates
41.10
operation & maintenance
152,641
nickel
nutrients
3.62
PERSONNEL
Workers/Year
nitrates
1.82
(for water pollution
ananonia
.06
abatement)
phosphorus
.17
construction
NA
surfactants
.39
operation & maintenance
8.51
SOLIDS WASTE
Tons
Without Scrubbers
scrubber sludge 0
boiler ash 2201.4
ESP ash 8676.4
With Non-Regenerative
Lime Scrubbers
15247.0
2201.4
8676.4
HEAT
stack loss
cooling towers
ENERGY PRODUCT***
electricity
Btu's
0.53 x 10*2
1.41 x 1012
Kw-hrs.
2.93 z 108
*In 1975 over 90X of Ohio coal cane from Northern Central Applar.Man.
**The»e costs are probably in 1974 dollars, but the source did not specify.
***For each Btu of electricity generated, .53 Btu of energy is lost out of the stack and 1.41 Btu of energy is lost through the cooling towers.
SOURCES: U.S. Department of Energy, Materials-Process-Product Analysis of Coal Process Technology - Final Report for Project Phase II. 1977.
The MITRE Corporation, Annual Environmental Analysis Report. 1977.
U.S. Enviromental Protection Agency, Development Document for Proposed Effluent Limitations Guidelines and New Sources Performance Standards
for the Stem Electric Power Generating Point Source Category, 1974.
-------
TABLE A-4 (Continued)
Conventional Boiler - Western Coal
ENERGY SYSTEM:
SIZE • 500 MUe
• heat rate 10,000 Btu/KWh
• Btu equipment
• thermal efficiency 34Z
• capacity factor S5Z
• annual energy production 8.2 x 10*2 Btu/year
DESCRIPTION
• Three model plants are considered.' The
first aeets Wyoming's average SIP standard.
'Hie second is a projected average under
USPS standards and a third meets a proposed
revised NSPS regulation.
COMPONENTS
• coal handling system
• coal crushing/conveying system
• coal pulveriring
• p.f. boiler
• feed water treatment
• air preheater
• economizer
• flue gas desulfurization (FGD) (when regula-
tions are applicable)
• settling ponds
• electrostatic precipitator (ESP) (for all
three plants)
• cooling towers
MAJOR ENVIRONMENTAL PROBLEMS
• SOj emissions from plants not required to
install scrubbers
• HO* emissions
• potential leachate of trace elements from
ash/sludge
• water use (in certain areas)
RESOURCES USED:
(Per 10" Btu Produced)
FUEL
coal: Western Rocky Mountain Province
heat content 10,000 Btu/lb
Z
076
ash 7.7
Coal Analysis
sulfur *
(requirements for pollution
control devices)
electrostatic precipitator
flue gas desulfurlzation
LAND
gross plant
waste disposal
COSTS(for water pollution
abatement)
coustntction
operation & maintenance
PERSONNEL (for water
pollution abatement)
construction
operation & maintenance
RESIDUALS AND PRODUCTS: Plant
(Per 10^2 Btu Produced) Under
NSPS
AIR POLLUTANTS
particulates
S° 2
NOx
hydrocarbons
CO
arsenic
beryllium
cadmium
fluorine
lead
mercury
selenium
manganese
Gross
8862.3
1397.0
1326.4
19.1
63.2
0.14
0.06
0.04
7.3
0.58
0.005
0.14
2.5
Net
147.0
802.6
1023.5
19.1
63.2
0.007
0.001
0.001
0.56
0.05
0.005
0.04
0.14
Plant
Under
Revised
NSPS
Net
73.5
169.1
882.3
19.1
63.2
0.007
0.001
0.001
0.56
0.05
0.005
0.04
0.14
540.507
152,641
Workers/Year
WATER POLLUTANTS Tons
BOD 1.41
COD 137.18
total suspended solids 0.33
total dissolved solids: 873.53
aluminum 0 .30
chromium 0.01
non-ferrous metals 110.79
zinc 0.05
sulfates 41.10
nickel 3.62
nutrients
nitrates 1.82
anaemia 0.06
phosphorus 0.17
surfactants 0.39
SOLID WASTE
Plant Meeting
State Imple-
mentation Plan
Net
795.0
1397.0
1326.4
19.1
63.2
0.007
0.001
0.001
0.56
0.05
0.005
0.04
0.14
Without Scrubbers
scrubber sludge 0
boiler ash 2441.1
ESP ash 8725.2
With Son-Regenerative
Lime
HEAT
stack loss
cooling towers
EKERCT PRODUCT**
electricity
Btu's
0.53 x
10^ '
Kw-hrs.
2.93 x 10®
•These costs are probably In 1974 dollars, but the source didn't specify.
**For each Btu of electricity generated, 0.53 of energy is lost out of the stack and 1.4. Btu of energy
.s lost through the cooling cowers.
SOURCES: U.S. Department of Energy, Materlals-Process-Product Analysis of Coal Process Technology - Final Report for Project Phase II.
The MITRE Corporation, Annual Environmental Analysis Report. 39771
U.S. Environmental Protettion Agency, Development Dociasent for Proposed Effluent Limitations Guidelines and Sev Source Performance Standards
for the Steam Electric Power Generating Point Source Category. 1974.
In revision for updating.
-------
TABLE A-4 (Continued)
Unit Train
4>
»—»
Ui
ENERGY SYSTEM:
SIZE e one unit train carries 10,500 tons of
coal per trip
• unit train consists of 105 freight cars
aech carrying 100 tons of coal
• 4 dlesel locomotives of 3,000 HP each
• ten spare freight cars are reserved
for each unit train
e each unit train Is assumed to sake 90
round tripe per year. Each trip is
700 «lles (1126 km) one way
e 99X of the coal loaded on a unit train
Is successfully delivered to Its desti-
nation—12 Inefficiency accounts for
losses in handling and wind losses in
transportation
e 30 year lifetime of care
DESCRIPTION
e Unit trains for transporting coal are
freight trains whose sole purpose Is to
carry coal. Ho other commodity Is
shipped by unit trains for coal. The
unit train described In this si—ij
runs on dlesel fuel (99% of *11 rail
ton-wiles in the U.S. are by dlesel;
1Z are on electrically-powered trains)
C0HP0HEWS
e freight cars
e locomotives
e caboose
e tracks
e loading * unloading facilities
MAJOR EWnmjMIUilAL PROBLEMS
e air pollution
e railroad crossing hazard
e noise
RESOURCES USED:
(Per 10^2 Btu Produced)
WJKL
coal
energy content
EHERGT
dlesel
LAIIP
tracks and 50-ft. right-of-way
(pro-rated to exclude non-coal
rsil totmage)
loading & unloading
r MATERIALS**
alimlniw
brass & bronze (castings)
chromium
manganese
nickel
steel
r COSTS
construction**
electric*! equipment
¦lscellaneous equipment
other constructor expenses
total ***
operation and nalntenance*
ancillary energy* (dlesel)
other
total
41,470 tons
12,180 Btu/lb
Btus
1.44 * 10i0
MA
Tons
1.97
0.79
0.10
2.72
NA
1.40
0.02
195
Dollars (1978)
33,000
289,000
10,000
352,000
41,000
272,000
313,000
Workers/Tear
RESIDUALS AND PRODUCTS:
(Ppr 1012 Btu Produced)
AIR POLLUTANTS4**
particulates
SO2
N0X
hydrocarbons
CO
aldehydes, etc.
Tons*
17.9
3.9
3.4
2.6
3.6
0.6
r NOISE
Noise Inside dlesel locomotives ranges
at least as high as 112 decibels (d£A).
100 feet troa a moving train, noise may
be approximately 95 dBA, while at 1000
feet the noise level nay be about 75 dBA.
Locomotive whistle noise at 1000 feet
from a train has been recorded at 65 dBA,
dropping below 70 dBA at 1300 feet. The
amount of noise generated is affected by
train speed, the number of cars in a
train, track condition and topography.
Welding of tTacks help reduce noise, and
man-made barriers can obstruct or dissi-
pate sound emissions. Federal design
noise levels range from 55 dBA (maximum
desirable for residences) to 75 dBA.
ENERGY PRODUCT
transported coal
Tons
41,050
construction (1 year)
operation t maintenance
•These figures are for a unit train with four 2,400 HP dlesel locomotives, and 100 freight cars each carrying 100 tons of coal, with an
average haulage distance of 300 ailes.
**Tbe»e figure* do not include Materials (construction costs) for tracks, loading facilities and unloading facilities.
***Totel construction costs shown here do not include labor.
costs include tracks, but exclude loading facilities and unloading facilities.
++ Removal efficiency 0 percent.
SOURCES: Hittaaa Associates, Environmental Impacts. Efficiency, and Cost of Energy Supply and End Use. Volume I, 1974.
Beehtel Corporation, "Energy Supply Planning fedel", 1978 .
Pl"%,S^'iTO'" f" 1,74.
University of Oklahoma, Energy Alternatives; A Como*r»riv» 1975.
C. Harris, Ed., Handbook of Boise Control. 1957.
Creen Associates, «t. *1., Western Prince George's County (Maryland) "a Alternatives Studv: R**-fcf>round Report. 1973.
August 1979
-------
TABLE A-4 (Continued)
Conventional Train
ENERGY SYSTEM:
SIZE • one conventional train carries 1445
tons of coal per trip
• A conventional train Is usuied to
consist of 85 freight cars, each of
which carries 85 tons of freight.
17 of these freight cars carry coal.
The other 68 cars carry non-coal
products
e Each conventional train is assumed
to make 20 round trips per year,
each trip Is 300 miles (483 Km) one way.
s 30 year lifetime of cars
e 98% efficiency is due to losses in
loading* unloading, and wind losses
during transit
DESCRIPTION
• Conventional trains transport several
coModltles simultaneously. Only one
of these products is coal. The con-
ventional train described in this
suMury runs on dlesel fuel (991 of all
rail ton-miles in the B.S. are by
diesel; 12 are by electrically-powered
trains)
components
e freight cars containing coal
• freight cars containing other products
(all coefficients shown on this suaury
sheet are pro-rated to exclude freight
cars containing non-coal products)
• locomotives
e caboose
e tracks
• loading and unloading facilities
• yard facilities, including switchyard
buildings
MAJOR ENViaOltCHIA! PROBLPS
• air pollution
m noise pollution, particularly in
populated areas
a railroad crossing hazard
RESOURCES USED:
(Per 10l2 Btu Produced)
FUEL
coal
energy content
41,890 tons
12,160 Btu/lb
ENERGY
diesel
LAND
50-ft. right of way,
including tracks
(pro-rated to exclude
non-coal rail tonnage)
loading and unloading
r MATERIALS**
altaima
brass & bronxe
chroniun
copper
iron
manganese
nickel
steel
r COSTS
construetion**
electrical equipment
alscellaneous equipment
other constructor omeuet
total***
operation & maintenance"*"
ancillary energy (diesel)4
other
total
PERSONNEL
construction
operation 4 Maintenance
Btus*
1.14 x 1010
34.6
NA
Tons
5.95
3.51
0.42
10.30
NA
6.35
0 .09
890
Dollars (1976)
146,000
1,199,000
40,000
1,305,000
33,000
901,000
934,000
Workers/Year
RESIDUALS k PRODUCTS:
(Per 10*2 Btu Produced)
AIR POLLUTANTS ++
particulates
SO2
NO*
hydrocarbons
CO
aldehydes, etc.
Tons
34.5
2. 7
3.1
2.1
2.9
0.5
NOISE
Noise inside diesel locomotives ranges
at least as high as 112 decibels (dBA).
100 feet fro® a Moving train, noise may
be approximately 95 dBA, while at 1000
feet the noise level may be about 75 dBA.
Locotsotive whistle noise at 1000 feet
ftom a train has been recorded at 85 dBA,
dropping below 70 dBA at 1300 feet.
The amount of noise generated is affected
by train speed, the mrnber of cars in a
train, track condition and topography.
Welding of tracks helps reduce noise, and
man-made barriers can obstruct or dissipate
sound emissions. Federal design noise
levels range from 55 dBA (maximum desirable
for residences) to 75 dBA.
ENERGY PRODUCT
transported coal
Tons
41,050
*These figure* are for a conventional train carrying 1000 tons of coal per trip, with an average haulage distance of 300 mile
••These figures do not include materials (construction costs) for tracks, loading facilities and unloading facilities
' ***Total construction consts show here do not Include labor.
-tO&ff costs include tracks, but exclude loading facilities, and unloading facilities.
-r+fteaoval efficiency is 0 percent.
SOURCES: Bechtel Corporation, "Energy Supply Planning Model", Vol ism I, 1975, and revisions, 1978.
Bittman Associates, Environmental Impacts. Efficiency, sad Cost of Energy Supply and End Dse. Voli^ I, 1974.
Peat, Harvick, Mitchell fc Co., Railroad Freight Car tegulr—ats for Transporting Energy 1974-1985, 1974,
International Research & Technology Corporation. TEOffiT. 1978.
University of Oklahcms, Energy Alternatives: A Co«paratlve *ft*ysls, 1975.
Cyril Harris, ad.t Handbook of Noise Control. 1957, pp 32-11 to 32-14.
Cruen Associates, et al. Western Prince George's County (Maryland) Transportation Alternatives Study: Backaroimid Report. 1973.
August If/9
-------
TABLE A-4 (Concluded)
Slurry Pipeline
EKEBGT SYSTEM:
SIZE • 273 alle pipeline with a 62.S ft.
right-of-way (this is based on the
existing Black Mesa slurry pipeline 1b
Arizona, which Is 273 alles long).
e annual capacity Is 4.8 z 10* tons of
coal (115 x 1012 Btus)
• 982 efficiency—losses due to reduction
In coal's heating value because of Its
slurry water contest
• 36 inch dimeter pipe
e ratio of solids to water (in terms of
voliae) Is approximately 50-50 + 5Z
DESCRIPTION
• Slurry pipelines transport pulverized
coal suspended in water or oil. The
system described in this sheet uses water
to transport coal. Pipelines using oil
to aove coal are under study. Coal moved
by slurry pipeline must be processed to
obtain the proper particle size. Pumping
stations, dewatering facilities and (in
some caaes) storage facilities are also
required.
CQgOMMTS
• pipeline
e (Maplog stations
• dewataring facilities
• slurry preparation facility
MUOfc EBVTtUWttHUL PROBLEMS
• substantial water requirements
• disposal of waste water at end-of-llne
RESOURCES USED:
(Per 10^2 Btu Produced)
FUEL
coal
energy content
electricity
41,890 tons
12,180 Btu/lb
Kwh
7.07 x 105***
LAUD
pipeline, right-of-way
ptaplng stations
dewatering facilities
slurry preparation facility
WATER
consumptive
MATERIALS
aliaintai
brass ( bronze
chromium
concrete
copper
iron
manganese
nickel
steel
COSTS
construction
pipeline (273 wiles)
coal slurry preparation
dewatering
total
operation t maintenance
(1972 dollars)
Acres
18.6***
1.74***
0.08*
0.08*
31.0+
Tons**
5735"
0.11
0.14
572.5
1.19
NA
1.99
0.02
262.7
Dollars (1978)
251,000*
216,000*
87,000*
555,000*
31,200***
RESIDUALS fr PRODUCTS:
(Per 10^2 Btu Produced)
AIR POLLPTAHTS
The amount of any pollutant oitted,
if any, is unknown.
r WATER POLLUTANTS
After coal slurry has been dewatered,
waste water containing suspended coal par*
tleles remains to be disposed of. Under
a closed systa, this waste water would
be ptmped back to the beginning of the
pipeline and reused, thus causing no
water pollution. Ifader an open system,
disposal of the waste water could cause
problems. These could be altlgated
by evaporating the water in ponds.
ENERGY PRODUCT
transported coal
Tons
41,050
construction
operation 6 maintenance
Workers/Tear
3.8**
0.00025
* based on Bechtel figures for a system with a capacity of 25 million tons/year.
**these figures are for coal slurry preparation, dewatering, and 273 miles of pipeline and are per 1012 Btu annual capacity.
***asstaes 273 miles of an 18-inch pipeline.
+sme AEAR IV, pg 39, pipeline diameter and length unspecified.
SOURCES: Hlttman Associates. Environmental Impacts. Efficiency, and Coat of Energy Supply and End Use. Volusw 1, 1974.
Bechtel Corporation, "EneTgy Supply Planning Model", 1978.
University of Oklahoma, Energy Alternatives. May 1975.
U.S. House of Representatives Coamlttee on Science 4 Technology, Oversight Hearings - Coal Slurry Pipeline Research t Development, 1976.
U.S. Energy Research and Development Administration, Envlrofsntal Development Plan - Coal Extraction. Beneficlatlon 6 Transportation, 1977.
The MITRE Corporation, Enviroimwntil Analysis Titp«rt; I"77,
August 1979
-------
TABLE A-5
ELEMENTAL COMPOUNDS IDENTIFIED IN EFFLUENTS
FROM ENERGY-RELATED PROCESSES
Source of Liquid and Solid Effluents'
-P-
o\
Au
Ag
A1
Al2°3
Ammonia
Ammonium cyanate
As
Arsenic acid, Na sale
Ar2°2
Arsine
Ba
BaCl2
Be
Bi
Bx
L, S
L,S
L
S
L
L,S
L
L
L
L
L,S
L,S
L
L
L
L
L
L
L,S
L,S
L,S
L,S
L,S
L,S
L,S
L,S
L,S
L,S
L,S
S
S
S
(continued)
-------
TABLE A-5 (Continued)
Source of Liquid and Solid Effluents'1
-------
TABLE A-5 (Continued)
Source of Liquid and Solid Effluents
oo
Elemental or Inorganics
Cr
Co
Cobalt Molybdate
Cu
Cyanides
Dysorlum
Erbuin
Europuin
Fe
FeCl3
F
Ge
Gadolinium
Ga
Hafnium
Holmiun
.o*
<&>
&
L,S
S
L,S
S
L,S
L
L,S
L
L
L
L
S
L
L
L,S
L,S
L,S
L,S
L,S
L,S
L,S
L,S
L,S
L,S
L,S
L, S
L,S
> f
C?V
(continued)
S
S
S
S
S
Cv 0/
u . -C*
c
L,S
-------
TABLE A-5 (Continued)
Source of Liquid and Solid Effluents3
-------
Table A-5 (Continued)
Source of Liquid and Solid Effluents3
-------
TABLE A-5 (Concluded)
Source of Liquid and Solid Effluents
SOUKCE; U.S. Environmental Protection Agency. 1978.
Identification of Components of Energy-Related Wastes
and Effluents. EPA-600/17-78-004. Environmental Research
Laboratory, Athens, Georgia.
-------
TABLE A-6
ORGANIC COMPOUNDS IDENTIFIED IN EFFLUENTS
FROM ENERGY-RELATED PROCESSES
Source of Liquid and So]id Effluents"
Compound of Chemical Class
>
c? _v
/
v
> .s*
cPV
c?V
o
,0
cv »
v"
Acenaphthalene
Acenaphthene
Acenaphthenols
Acetophenone
Acetaldehyde
Acetic acid
Aldehydes
Alkyl and aromatic hydrocarbons
Alkyl and aromatic amines
Alkyl and aromatic alcohols
Aniline
Anthraquinone/Disulfonic acid
Anthracene
Benzaldehyde
Benzoic acid
Benzene
Benzofuranol
L,S
L
L,S
L
L
L
L,S
L
L
L
L,S
L,S
-------
TABLE A-6 (Continued1)
Source of Liquid and Solid Effluents'
N>
W
Compound of Chemical Class
Benzo(a)anthracene
S
Benzo(a)anthracene, 7,12-dimethyl
Benzonaphthiothiophenes
s
Benzonitrile
L
Benzo(a)pyrene
S
S
Benzo(e)pyrene
S
Benzo(g)chrysene
S
Benzo(g,h,i)perylene
S
Benzo(c)chrysene
S
Biphenyl
S
1-Butanol
L
2-Butoxyethanol
L
Carbon disulfide
L
Carbonyl sulfide
L
Carbazoles
L
¦-Cresol
L
L
L
L
o-Cresol
L
L
L
L
(continued)
-------
TABLE A-6 (Continued)
Source of Liquid and Solid Effluents'
Compound of Chemical Class
o°&
J
J
oN £
j>-Cresol
Crysene
Cresylic acid
1-Decanol
Diacetone alcohol
Dibenzofuran
Dibenzothiophenes
Dibenz(a,h)anthracene
Dibenz(a,j)acridine
Dibenzo(cd, lm)perylene
Dimethyl furan isomer
2,6-Dimethylnaphthalene
3,3-Diphenylpropanol
Dimethylphenol
Dodeane
Eicosane
L
S
L
L
L
L
L
L
L
L
L
L
(continued)
-------
TABLE A-6 (Continued)
Source of Liquid and Solid Effluents^
Compound of Chemical Class
&
Ethylene glycol
Ethyl naphthalene
0-Ethyltoluene
Fluorene
Formaldehyde
Fluoranthrene
Furans
Formic acid
Heneicosane
Heptadecane
Hexadecane
1-Hexanol
Indane
Indanols
A-Indanol
Indene
S
S
S
S
(continued)
S
L
S
L
L
L
L
L
L
L
-------
TABLE A-6 (Continued)
Source of Liquid and Solid Effluents3
Compound of Chemical Class
/<
/ v/
/ V
£ / £
V / c°.
// °vi
/ £
/
//
^ / \
V° />,
' / i
/ ^
/
„t>
o / Jfr
r / cO
/ v
/ ^
¥ / oN 4
/ p
/ *
£ /
/
Indole
s
Maleic anhydride
L
Maleic acid
L
m-Methoxyindole
s
a-Methylbenzyl alcohol
L
Methyl biphenyl isomer
L
Methyl ethyl naphthalene isomer
L
1-Methyl indene
L
3-Methyl indene
L
1-Methylnaphthalene
L
2-Methylnaphthalene
L
Methyl indole
L
Methyl mercaptan
L, S
L,S
Methyl anilines
L
o-Methylstyi one
L
B-Methylsty» ene
L
(continued)
-------
TABLE A-6 (Continued)
Source of Liquid and Solid Effluentsc
Naphthalene
Naphthols
1-Naphthol
2-Naphthol
Naphthol, methyl
Nonadecane
1-Octanol
Octadecane
Oleic acid
Phenanthrene
Fhenanthrols
Phenol
o-Ethylphenol
j>-Ethylphenol
o-Isopropylphenol
2-Methyl-4-ethylphenol
L,S
S
L
S
L
L
S
L,S
L
L
L
L
(continued)
L,S
L
L
L
L
-------
TABLE A-6 (Continued)
Source of Liquid and Solid Effluents
¦>
K>
oo
3-Me thy1-6- e thy lpheno 1
4-Met hy 1- 2- e t: hy lpheno 1
2,3,5-Trimethylphenol
1—Phenylnaphthalene
Pyridine
Pyridine, ethyl
Pyridine, methyl
Pyrroles
Pyrene
Pyrocatechol
Pyrocatechol, methyl
Palmitic acid
Pentadecane
Quinolines
Styrene
Thiophene
L
L
L
S
L,S
L
L
L,S
L
L,S
(continued)
L
L
L
L
L
-------
TABLE A-6 (Continued)
Source of Liquid and Solid Effluents3
Compound of Chemical Class
/?
/ & t
/
A f / / / 4
JV / ryj / \. „v /
* c? / Jy o / r>y O X *<,
$ / °$ / O0 ^ / /<
> / £ / £ / c° /
/ & / s* / V
*£ / * /
r / & / °V
/ ^ ^
Cn /
J?' /
<- /
t /
Thiophene, dimethyl
L,S
Thiophene, methyl
L,S
L
Toluene
L,S
L
L
L
Thiosulfide
L
a-Terpineol
L
Tetradecane
L
n-Tridecane
L
Undecane
L
Xylene (£>H»£)
L
L
L
2,3-Xylenol
L
2,4-Xylenol
L
2,5-Xylenol
L
2,6-Xylenol
L
3,4-Xylenol
L
3,5-Xylenol
L
y-valerolactones
L
(continued)
-------
TABLE A-6 (Concluded)
Source of Liquid and Solid Effluents3
Compound of Chemical Class
/*>
.//
^ /
/ N
/ Jtr
/•O
V
/
o* /
*Y /
£
o°
V
/
/ r
/
: SOURCE: U.S. Environmental Protection Agency. 1978.
0 Identification of Components of Energy-Related Wastes
and Effluents. EPA—600/17—78—004. Environmental Research
Laboratory, Athens, Georgia.
-------
TABLE A-7
COMPARISON OF COAL RESOURCE TECHNOLOGY OPTIONS:
HUMAN HEALTH AND SAFETY FROM ACCIDENTS3
FUEL CYCLE
TECHNOLOGY OPTION
RESOURCE AREA
ACCIDENT RATE PER
1012 BTU EQUIVALENTS
FATALITIES INJURIES MAN-DAYS LOST
Surface coal
mining and
reclamation
Underground coal
mining and
reclamation
Northwest-area strip
Uncontrolled
Controlled'1 >c
Central-area strip
Uncontrolled
Controlled^
Northern Appalachian-
area strip
Uncontrolled
Controlled
Northern Appalachian
Contour
Uncontrolled
Controlled^
Central Appalachian Auger
Uncontrolled
Controlledd
Central Appalachian
Contour
Uncontrolled
Controlledd
Southwest-area strip
Uncontrolled
Controlled0
Eastern coal-area strip
Uncontrolled
Control led**
Western coal-area strip
Controlled
Central
Room and Pillar
Uncontrolled
Controlled
Northern Appalachia
Room and Pillar
Uncontrolled
Controlled
0.0025
0.0025
0.003
0.003
0.005
0.005
0.005
0.005
0.0001
0.0001
0.0018
0.0018
0
0
NC
0.005
0.0065
0.01
0.01
U
U
0.057
0.057
0.16
0.16
0.12
0.12
0.12
0.12
0.094
0.094
0.164
0.164
0.059
0.059
NC
0.25
0.31
1.01
1.01
U
U
1.41
1.41
3.99
3.99
2.49
2.49
2.49
2.49
1.9
1.9
3.30
3.30
0.678
0.678
NC
74
96
37.8
37.8
U
U
431
-------
TABLE A-7 (Continued)
FUEL CYCLE
TECHNOLOGY OPTION
RESOURCE AREA
ACCIDENT RATE PER
1012 BTU EQUIVALENTS
FATALITIES INJURIES MAN-n;
Coal preparation/
beneficiation
Coal gasification
(low, inter-
mediate energy
content)
Longwal1
Uncontrolled
U
U
U
Controlled
U
U
u
Central Appalachia
Room and Pillar
Uncontrolled
0.022
0.955
3.42
Controlled
0.022
0.955
3.42
Breaking and Sizing
Northwest
Uncontrolled
0
0.003
0.148
Controlled
0
0.003
0.148
Central
Uncontrolled
U
U
u
Controlled
U
u
u
Northern Appalachia
Uncontrolled
U
u
U
Controlled
U
u
u
Central Appalachia
Uncontrolled
U
u
U
Controlled
U
u
U
Southwest
Uncontrolled
0
0
0
Controlled
0
0
0
Cleaning including washing**
Uncontrolled
0.0026
0.0053
22.9
Controlled
0.0026
0.0053
22.9
Cleaning including washing0
Uncontrolled
NC
NC
NC
Central coal
BuMines
Atmospheric
U
u
u
Pressurized
U
U
u
Koppers-Totzek
U
U
u
Northern Appalachian coal
BuMines
Atmospheric
U
U
u
Pressurized
U
U
u
Koppers-Totzek
U
U
u
432
-------
TABLE A-7 (Continued)
FUEL CYCLE
TECHNOLOGY OPTION
RESOURCE AREA
ACCIDENT RATE PER
1012 BTU EQUIVALENTS
FATALITIES INJURIES MAN-DAYS LOS1]
Coal gasification
(high energy
content)
Northwest coal
BuMines
Atmospheric
Pressurized
Koppers-Totzek
Lurgi
Eastern Coal
Agglomerating
Fluidized Bed^
High-Btu gasification
Central Coal
HYGAS-steam-oxygen
BIGAS
Synthane
Lurgi
Northern Appalachian coal
HYGAS-s team-oxygenb
BIGAS
Synthane
Northwest coal
HYGAS-s team-oxygen
BIGAS
Synthane
Lurgi
CO2 acceptor
Solid coal
Solvent refined coal
Northern Appalachian area
Central
Eastern coal
Chemical cleaning*5
Liquefaction
Northwest area
CSF process
SRC process
Central area
CSF process
SRC process
SRC process0
U
U
U
U
NC
U
U
U
U
U
U
u
u
u
u
u
u
u
u
NC
u
u
u
u
NC
u
u
u
u
NC
U
U
U
U
U
u
u
u
u
U
U
u
u
u
NC
u
U
U
u
NC
U
U
u
u
NC
U
U
u
u
u
u
u
U
u
u
u
u
u
u
NC
u
U
U
u
NC
433
-------
TABLE A-7 (Continued)
FUEL CYCLE
TECHNOLOGY OPTION
RESOURCE AREA
ACCIDENT RATE PER
1012 BTU EQUIVALENTS
FATALITIES INJURIES MAN-DAYS LOST
Transportation,
in-mine
Transportation,
surface
distribution
Northern Appalachian area
CSF process
U
U
u
SRC process
U
U
u
Northwest coal
Trucking
Uncontrolled
0
0.027
0.674
Controlled
0
0.027
0.674
Central coal
Trucking
Uncontrolled
U
U
U
Controlled
U
U
U
Conveyor
Uncontrolled
U
U
U
Controlled
U
U
U
Mine rail
Uncontrolled
U
u
U
Controlled
U
u
U
Southwest coal
Trucking
Uncontrolled
0
0.015
0.171
Controlled
0
0.014
0.171
Unit train
Northwest coal
0.075
0.599
55.6
Central coal
0.066
0.876
81.3
Northern Appalachian coal
0.065
0.856
79.6
Central Appalachian coal
0.062
0.767
71.4
Southwest coal
0.067
0.0534
49.6
Mixed or conventional train
Northwest coal
0.075
0.599
55.6
Central coal
0.066
0.876
81.3
Northern Appalachian coal
0.065
0.856
79.6
Central Appalachian coal
0.062
0.767
71.4
Slurry pipeline river barge
Central coal
0.0019
0.0032
0.243
Northern Appalachian coal
0.0019
0.0032
0.243
Central Appalachian coal
0.0019
0.0032
0.243
Trucking
Northwest coal
0.032
0.692
45.4
Central coal
0.032
0.692
45.4
434
-------
TABLE A-7 (Concluded)
ACCIDENT RATE PER
TECHNOLOGY OPTION 1012 BTU EQUIVALENTS
FUEL CYCLE RESOURCE AREA FATALITIES INJURIES MAN-DAYS LOST
Northern Appalachian coal
0.032
0.692
45.4
Central Appalachian coal
0.032
0.692
45.4
Conveyor
Central coal
0
0
0
Northern Appalachian coal
0
0
0
Central Appalachian coal
C
0
0
SOURCE: U.S. Environmental Protection Agency. 1977. Accidents and Unscheduled
Events Associated with Nonnuclear Energy Resources and Technology. EPA 600/7-77-016.
Office of Research and Develoment, Washington, D.C.
^In controlled situation, land reclamation and water treatment considered part of
mine operation; in uncontrolled situation, they are not considered.
cFive years assumed for land reclamation.
^Three years assumed for land reclamation.
NC ¦ not considered, U - unknown
435
-------
TABLE A-8
ANNUAL DEATHS, INJURIES, AND WORK DAYS LOST FOR UNCONTROLLED COAL-FIRED ELECTRICITY
SYSTEMS ASSOCIATED WITH A 1,000-MEGAWATT POWERPLANT WITH A LOAD FACTOR OF 0.7 5
OCCUPATIONAL
HEALTH
EXTRACTION
DEEP SURFACE
PROCESSING
TRANSPORT
CONVERSION
TRANSMISSION
TOTAL
DEEP SURFACE
Deaths
1.67
0.308
0.0238
2.30
0.012
NA
4.00
2.61
Injuries
85
13.9
2.56
23.4
1.38
NA
112.3
41.2
Workdays
4,678
499
99.5
2,340
152.9
NA
15,280
3,091
NA - not available
SOURCE: U.S. Environmental Protection Agency. 1977. Accidents and Unscheduled Events Associated with Nonnuclear
Energy Resources and Technology. EPA 600/7-77-016. Office of Research and Development, Washington, D.C.
NOTES:
Impacts of coal based on coal transport exclusively by rail (ave. distance 300 ml.); annual coal supply for a
1000 MWc plant is 0.1 percent of total national ton-mileage and it is assumed that average injury leads to
loss of 100 workdays.
For conversion it is assumed that one-half the combined deaths and permanent injuries are fatal injuries.
Permanent total disabilities are considered to represent 6,000 workdays lost, and other disabilities are
estimated at 100 days lost.
Workdays lost due to pneumoconiosis not included in data on deep mines.
-------
TABLE A-9
FATAL, DISABLING AND NONDISABLING INJURIES OF 1978, FOR COAL AND METAL/NONMETAL MINES
Average
•P-
W
^4
Fatal
Nonfatal
N'FDL
Nonfatal Injuries
NDL
All
Number
Fatal
Incidence
With Days Lost
Incidence
With No Days Lost
Incidence
All
Incidence
Of
Injuries
Rate
(NFDL)
Rate
(NDL)
Rate
Injuries
Rate
Workers
Coal Mines
Underground Mines:
Underground
66
.07
9,864
10.62
2,337
2.52
12,267
13.21
125,936
Surface
9
.07
652
5.85
313
2.81
973
8.73
15,425
Total, Underground Mines
75
.07
10,516
10.11
2,650
2.55
13,240
12.73
141,361
Surface Mines
Strip Mines
16
.03
2,019
3.36
1,351
2.25
3,386
5.64
72,228
Auger Mines
1
.26
21
5.53
5
1.32
27
7.11
1,109
Culm Bank
-
-
11
6.74
9
5.52
20
12.26
328
Dredge
-
-
2
19.98
-
-
2
19.98
21
Total Surface Mines
17
.03
2,053
3.39
1,365
2.25
3,435
5.67
73,686
Preparation Plants
13
.08
851
5.42
489
3.11
1,353
8.61
21,607
Independent Shops/Yards
-
-
134
4.40
100
3.28
234
7.69
3,883
Total Other Operations
13
.07
985
5.25
589
3.14
1,587
8.46
25,490
Total
105
.06
13,554
;.3o
4,604
2.51
18,262
9.96
240,537
Employee
Hours
Reported
185,703,725
22,280,422
207,984,147
120,110,438
759,732
326,354
20,022
121,216,546
31,411,786
6,089,076
37,500,862
366,701,555
SOURCE: Bureau of Mines 1977.
-------
Appendix B
Chemical Coal Cleaning
-------
100
90
£80
LU
s
o
° 70
+
£ 60
LU
>
O
o
K 50
40
30
J L
PITTSBURGH SEAM COAL (+100M)
GREENE COUNTY
X-14M, Mechanically Crushed,
40.74%<100 M
3/8", Mechanically Crushed,
10.59%<100 M
o ROM Sample Coal,
5.49%<100 M
A Chemically Comminuted
Gaseous NH3 Exposure Time,
2 hrs at 120 psig,
7.2% 100 M
J I I L
J L
i
2.0
2.5 3.0
SULFUR (PERCENT)
3.5
4.0
SOURCE: Contos 1978.
FIGURE B-1
SYRACUSE PROCESS VS. MECHANICAL CRUSHING:
SULFUR WASH ABILITY CURVES FOR PITTSBURGH COAL (TWO HOURS)
-------
JS
O
100
90
80
§70
s
o
o
760
>-
cc
LU
£50
o
LU
CC
40
X-A
PITTSBURGH SEAM COAI_(+100M)
GREENE COUNTY
X-14M, Mechanically Crushed,
40. 74%<100M
•-3/8", Mechanically Crushed,
10.5 9%<100M
o ROM Sample Coal,
5.49 %<100M
Chemically Fragmented,
Gaseous Exposure Time 4
120 psig. 10.31%<100M
hrs
2.0
2.5
3.0
3.5
4.0
SULFUR (PERCENT)
SOURCE: Contos 1978.
FIGURE B-2
SYRACUSE PROCESS VS. MECHANICAL CRUSHING:
SULFUR WASHABILITY CURVES FOR PITTSBURGH COAL
(FOUR HOURS)
-------
INTERPOLATION SCALE
5 10
¦ ¦ <¦¦¦¦!
SCREEN OPENING
.(a)
400
U.S. STANDARD SIEVE DESIGNATION
J I I I L
_l_
50 40
_L
20
-L
10
6 4
300
400 200 100 60 35 20 10
TYLER SIEVE DESIGNATION
SOURCE: Contos 1978.
J I I I
8 6 4
O 1*5 in-. ROM Sample
• 3/8 in., Mechanically Crushed
A 14 Mesh, Mechanically Crushed
A 1% in., Chemically Fragmented,
Gaseous Ammonia, 120 psig,
75°F, Exposure Time: 120 min.
1 2 3 4 5 10
SCREEN OPENING INCHES
(a)Any scale, if in milimeters
coinsides with lower scale.
FIGURE B-3
SYRACUSE PROCESS VS. MECHANICAL CRUSHING:
SIZE CONSIST COMPARISON USING ILLINOIS NO. 6 COAL
-------
100
90
80
£ 70
%
8 60
LLl
a:
50
40
30
20
o 1% in., ROM Sample
• 3/8 in., Mechanically Crushed
A 14 Mesh, Mechanically Crushed
a 1% in., Chemically Fragmented,
Gaseous Ammonia, 120 psig.
75°F, Exposure Time. 120 min.
0
6 8
CUMULATIVE % ASH
10
12
14
SOURCE: Contos 1978.
FIGURE B-4
SYRACUSE PROCESS VS. MECHANICAL CRUSHING:
PERCENT ASH VS. PERCENT RECOVERY OF ILLINOIS NO. 6 COAL
-------
TOO
90
80
£ 70
60
50
40
30
20
1.0
-2 in, ROM Sample
3/8 in., Mechanically Crushed
14 Mesh, Mechanically Crushed
1% in., Chemically Fragmented,
Gaseous Ammonia, 120 psig.
75°F, Exposure Time: 120 min.
i
1.2
1.4
1.6
1.8
2.0
2.2
CUMULATIVE % SULFUR
SOURCE: Contos 1978.
FIGURE B-5
SYRACUSE PROCESS VS. MECHANICAL CRUSHING:
PERCENT SULFUR VS. PERCENT RECOVERY OF ILLINOIS NO. 6 COAL
-------
0 20 40 60 80 100
% REMOVAL
20 40 60 80 100
% REMOVAL
0 20 40 60 80 100
% REMOVAL
20 40 60 80 100
% REMOVAL
% REMOVAL % REMOVAL
SOURCE: Contos 1978.
FIGURE B-6
MEYERS PROCESS VS. PHYSICAL COAL CLEANING:
TRACE ELEMENT REMOVAL DATA
444
-------
SOURCE: Kalvinskas 1978.
FIGURE B-7
LABORATORY GLASSWARE APPARATUS FOR
CHLORINATION OF COAL IN JPL PROCESS
-------
¦QUARTZ TUBE
-p-
¦e*
WATER
GAS
COLLECTOR
STEAM
GENERATOR
SOURCE: Kalvinakas 1978.
FIGURE B-8
LABORATORY EQUIPMENT FOR DECHLORINATION OF
COAL IN JPL PROCESS
-------
TABLE B-l
PRODUCT RECOVERY OF FOUR SAMPLES OF TREATED
ILLINOIS NO. 6 COAL AT 1.4% SULFUR
SAMPLE TOP SIZE
PERCENT MINUS
100 MESH
FINES
PERCENT RECOVERY
FINES FREE
BASIS
OVERALL
RECOVERY
3.8 cm (1 1/2 in) ROM
Coal
2.5
50
49
1 cm (3/8 in)
Mechanically Crushed
8
70
64
14 Mesh, Mechanically
Crushed
22
78
61
3.8 cm (1 1/2 in)
Chemically
Comminuted
5.5
96
91
SOURCE: Contos 1978.
447
-------
TABLE B-2
PRODUCT RECOVERY OF FOUR SAMPLES OF TREATED UPPER
FREEPORT COAL AT 0.9% AND 1.3% SULFUR
SAMPLE TOP SIZE
PERCENT MINUS
100 MESH
PERCENT
FINES
RECOVERY
FREE
OVERALL
RECOVERY
FINES
0. 9%S
1. 3%S
0. 9%S
1. 3%S
3.8 cm (1 1/2 In)
ROM
2.8
37
72
36
70
1 cm (minus 3/8 in)
Mechanically
Crushed
9
72
92
65.5
84
14m, Mechanically
Crushed
19
87
94
70.5
76
3.8 cm (1 1/2 in)
Chemically
Comminuted
5
77
88
73
83.5
SOURCE: Contos 1978.
448
-------
TABLE B-3
MEYERS PROCESS
SUMMARY OF PYRITIC SULFUR REMOVAL RESULTS
(100-200 MICRON TOP-SIZE COAL)
1 TOTAL SULFUR W/W IN COAL*
MEYERS'
MEYERS' PROCESS
X SULFUR
MINE
SEAM
STATE
PROCESS PYRITE
TOTAL SULFUR
IN COAL '
Initial
Axter Meyers Process
Current Results
CONVERSION X W/W
DECREASE Z W/W
AFTER FLOAT-SINK
APPALACHIAN COALS
Kopperstone No. 2
Campbell Creek
W. Virginia
0.9
0.6
92
33
0.8
Harris Nos. 1 & 2
Eagle & No. 2 Gas
W. Virginia
1.0
0.8
94
23
0.9
Warwick
Sevickley
Pennsylvania
1.4
0.6
92
54
1.0
Marion
Upper Freeport
Pennsylvania
1.4
0.7
96
50
1.2
Mathies
Pittsburgh
Pennsylvania
1.5
0.9
95+
36
1.7
Isabella
Pittsburgh
Pennsylvania
1.6
0.7
96
54
1.5
Lucas
Middle Kittanning
Pennsylvania
1.8
0.6
94+
64
0.7
Jane
Lover Freeport
Pennsylvania
1.8
0.7
91
63
0.8
Martinka
Lower Kittanning
W. Virginia
2.0
0.6
92
70
0.8
North River
Corona
Alabama
2.1
0.9
91
55
2.2
Humphrey No. 7
Pittsburgh
W. Virginia
2.6
1.5
91
42
1.9
No. 1
Mason
E. Kentucky
3.1
1.6
90
48
2.3
Bird No. 3
Lower Kittanning
Pennsylvania
3.1
0.8
96+
75
1.5
Williams
Pittsburgh
W. Virginia
3.5
1.4
96+
50
2.3
Shoemaker
Pittsburgh
W. Virginia
3.5
1.7
80
51
3.6
Meigs
Clarion 4A
Ohio
3.7
1.9
93
48
2.8
Fox
Lower Kittanning
Pennsylvania
3.8
1.6
89
57
2.0
Dean
Dean
Tennessee
4.1
2.1
94+
49
3.0
Powhattan No. 4
Pittsburgh No. 8
Ohio
4.1
1.9
85
53
3.3
Robinson Run
Pittsburgh
W. Virginia
4.4
2.2
97+
50
3.0
Delmont
Upper Freeport
Pennsylvania
4.9
0.8
96+
80
2.1
Muskingham
Meigs Creek
Ohio
6.1
3.2
94+
47
4.4
Egypt Valley No. 21
Pittsburgh No. 8
Ohio
6.6
2.7
89
59
4.6
EASTERN INTERIOR COALS
Orient No. 6
Merrin No. 6
Illinois
1.7
0.9
96+
44
1.4
Eagle No. 2
Illinois No. 5
Illinois
4.3
2.0
94
54
2.9
Star
No. 9
W. Kentucky
4.3
2.5
91+
43
3.0
Homestead
No. 11
W. Kentucky
4.5
1.7
93
47
3.2
Camp Nos. 1 & 2
No. 9 (W.KY)
W. Kentucky
4.5
2.0
89
55
2.9
Ken
No. 9
W. Kentucky
4.8
2.8
91
42
3.5
WESTERN COALS
Navajo
Nos. 6,7,8
N. Mexico
0.8
0.6
90
25
Colstrip
Rosebud
Montana
1.0
0.6
83
30
WESTERN INTERIOR COALS
Weldon No. 11
Des Moines No. 1
Iowa
6.4
2.2
92
65
3.9
*Dry, moisture-free basis
£1.90 float material, 16 mesh x 0, is defined here as the limit of conventional coal cleaning
+Run at 150 x 0
SOURCE: Contos 1978.
-------
TABLE B-4
MEYERS PROCESS RAW MATERIALS, UTILITIES AND WASTE STREAMS BALANCE
Hourly units
Units per process t-min Unit Ratio
Product coal, dry basis
metric
tons
(Tons)
81.9 (90.3)
1.0
Coal received, dry basis
metric
tons
(Ibns)
90.7 (100.0)
1.107
Ash loss
metric
tons
(Tens)
5.2 (5.7)
0.063
Oxygen, 99.5%'
metric
tons
(Tans)
3.5 (3.9)
0.043
Binder
metric
tons
(Tens)
1.3 (1.4)
0.015
Fuel coal, dry basis
metric
tons
(Tens)
3.6 (4.0)
0.044
Fewer
kw
8,400
93.0
Water*
liters
2
,180,000
26,620
Iron sulfate wastes
metric
tons
(Tans)
7.3 (8.1)^
0.090
Sulfur by-product
metric
tons
(Tons)
1.2 (1.3) +
0.014
Gypsum
ma trie
tons
(Tons)
1.45 (1.6)
0.018
Lime, dry basis
metric
tons
(Tons)
0.45 (0.5)
0.006
* Includes 36,000 1/nin cooling water and 420 1/min process water
A Includes 0.9 metric tons/hr water
t Includes 0.1 metric tons/hr coal
SOURCE: Contos 1978,
450
-------
TABLE 3-5
PYRITE REMOVAL FROM REPRESENTATIVE
COALS USING THE PETC PROCESS
Temp.,
Pyritic Sulfur
, wt. %
Seam
State
°C
Untreated
Treated
Illinois No. 5
Illinois
150
0.9
0.1
Minshall
Indiana
150
4.2
0.2
Lovilia No. 4
Iowa
150
4.0
0.3
Pittsburgh
Ohio
160
2.4
0.2
Lower Freeport
Pennsylvania
160
2.4
0.1
Brookville
Pennsylvania
180
3.1
0.1
SOURCE: R. P. Warzinski. 1978. Survey of Coals Treated by Oxydesul-
furization. Presented at U.S. Environmental Protection Agency Sym-
posium on Coal Cleaning to Achieve Environmental and Energy Goals,
Hollywood, Florida, 11-15 September 1978.
TARLF. B-6
ORGANIC SULFUR REMOVAL FROM REPRESENTATIVE COALS USING THE PETC PROCESS
Temp., Organic Sulfur, wt. "
Seam
State
°C
Untreated
Treated
Bevier
Kansas
150
2.0
1.6
Mammoth*
Montana
150
0.5
0.4
Wyoming No. 0»
Wyoming
150
1.1
0.8
Pittsburgh
Ohio
180
1.5
0.8
Lower Freeport
Pennsylvania
180
1.0
0.8
Illinois No. 6
Illinois
200
2.3
1.3
Minshall
Indiana
200
1.5
1.2
*Subbituminous
SOURCE: same as above.
451
-------
TABLE B-7
PETC PROCESS OXYDESULFURIZATION OF REPRESENTATIVE COALS
Seam
Minshall
Illinois No. 5
Lovilia No. 4
Mammoth*
Pittsburgh
Wyoming No. 9*
Pittsburgh
Upper Freeport
State
Indiana
Illinois
Iowa
Montana
Pennsylvania
Wyoming
Ohio
Pennsylvania
Temp.,
°C
150
150
150
150
150
150
160
160
Total Sulfur, wt. %
Untreated Treated
5.7
3.3
5.9
1.1
1.3
1.8
3.0
2.1
2.0
2.0
1.4
0.6
0.8
0.9
1.4
0.9
Sulfur, lb/10 Btu
Untreated Treated
4.99 1.81
2.64 1.75
5.38 1.42
0.91 0.52
0.92 0.60
1.41 0.78
2.34 1.15
1.89 0.80
*Subbituminous
SOURCE: R. P. Warzinski. 1978. Survey of Coals Treated by Oxydesulfurization. Presented at U.S.
Environmental Protection Agency Symposium on Coal Cleaning to Achieve Environmental and Energy
Goals, Hollywood, Florida, 11-15 September 1978.
-------
TABLE B-8
ANALYSES OF COAL SAMPLES USED IN THE EVALUATION OF THE G.E. PROCESS
Sulfur Content, %
Coal //
Geographic Origin
Pyritic
Organic
Sulfate
PSOC-26
Illinois #6 Seam
4.23
2.08
0.35
PSOC-252
Illinois #5 Seam
2.82
1.84
0.06
PSOC-255
Lower Kittaning Seam from Pa.
4.49
0.78
0.03
PSOC-257
Upper Freeport Seam from Pa.
1.06
0.56
PSOC-294
Pittsburgh Seam from Pa.
2.27
0.34
0.01
PSOC-320
Pittsburgh Seam from Pa.
0.45
0.64
0.07
PSOC-353
Clarion Seam from Pa.
4.65
1.21
0.07
PSOC-272
Kentucky Seam #9
0.03
3.80
0.06
PSOC-273
Kentucky Seam #11
0.2-0.3
4.49
0.14
SOURCE: Contos 1978.
-------
TABLE B-9
ANALYSES FOR RAW AND G.E. PROCESS TREATED COALS
% S % N % C % H % 02 % Ash I H20 % V.M.
PSOC 294
Pittsburgh-mostly 2.02 1.21 62.65 4.24 10.08 19.94 0.07 34.74
pyritic
Single
Treatment, 1.29 1.24 59.21 3.88 12.36 22.02
30 sec.
Double
Treatment 0.4 1.09 53.87 2.22 14.06 29.24 3.0 24.7
PSOC 273
•O Kentucky #11 4.18 1.33 60.19 4.80 18.62 12.88
organic
Dbl. Treatment
30 sec. ea. <0.1 1.15 63.34 4.39 22.14 8.98
#5 Coal
Clarion Co. 2.37 1.53 78.82 5.69 9.12 2.47
Penna, mostly
pyritic
Single Treatment
30 sec. 0.88 1.49 75.51 5.17 11.44 5.53
Z FC
45.32
46.10
SOURCE: Contos 1978.
-------
TABLE B-10
PYRITIC SULFUR EXTRACTION BY THE BHCP
Source
of Coal
Percent Pyritic
Sulfur*
Extraction
Mine
Seam
State
Raw
Coal
BHCP
Coal
Efficiency,
Percent
CN719
6
Ohio
4.0
0.1
99
Belmont
8
Ohio
1.6
0.1
92
NE41
9
Ohio
4.0
0.1
99
Ken
14
Ky.
2.1
0.2
92
Beach Bottom
8
Pa.
1.7
0.1
95
Eagle 1
5
111.
1.5
0.2
87
*Moisture and ash free basis. Coal samples were supplied from
the various mines. Analyses were conducted by Battelle on raw
and hydrothermally treated coals.
SOURCE: E. P. Stambaugh. 1978. States of Hydrothermal Processing
for Chemical Desulfurization of Coal. Presented at U.S. Environ-
mental Protection Agency Symposium on Coal Cleaning to Achieve Energy
and Environmental Goals, Hollywood, Florida, 11-15 September 1978.
455
-------
TABLE B-ll
EXTRACTION OF ORGANIC SULFUR BY THE BHCP
Source of Coal
Percent Pyritic
Sulfur*
Extraction
Mine
Seam
State
Raw BHCP
Coal Coal
Efficiency,
Percent
Sunny Hill
Martinka #1
Westland
Beach Bottom
Reign //I
Lower
Kittaning
8
8
4A
Ohio
W. Va.
Pa.
W. Va.
Ohio
1.1
0.7
0.8
1.0
2.3
0.6
0.5
0.5
0.7
1.1
41
24
38
30
52
^Moisture and ash free basis. Coal samples were supplied from
the various mines. Analyses were conducted by Battelle on raw
and hydrothermally treated coals.
SOURCE: E. P. Stambaugh. 1978. States of Hydrothermal Processing
for Chemical Desulfurization of Coal. Presented at U.S. Environ-
mental Protection Agency Symposium on Coal Cleaning to Achieve
Energy and Environmental Goals, Hollywood, Florida, 11-15 September
1978.
456
-------
TABLE B-12
CONTINUOUS BENCH-SCALE RESULTS
FOR THE BATTELLE PROCESS
Coal Source
Mine
Seam
Sulfur Analysis,
wt%
Raw
Coal
BHCP
Coal
SO2 Equivalent,
kg/10^ kg cal
(lb/106 Btu)
Raw
Coal
BHCP
Coal
1. Laboratory Scale
Martinka No. 1 Lower Kittanning 1.07 0.39 3.87(2.15)
(W. Va.)
Renton
Upper Freeport
(Pa.)
1.32 0.52 4.36 (2.42)
1.57(0.87)
1.66(0.92)
2. Continuous Bench-Scale Studies
Martinka No. 1 Lower Kittanning 2.77 0.76 7.20(4.00)
(W. Va.)
Renton
Upper Freeport
1.20 0.60 4.32(2.40)
1.89(1.05)
1.42(0.79)
SOURCE: E. P. Stambaugh. 1978. States of Hydrothermal Processing for Chemical
Desulfurization of Coal. Presented at U.S. Environmental Protection Agency
Symposium on Coal Cleaning to Achieve Energy and Environmental Goals,
Hollywood, Florida, 11-15 September 1978.
457
-------
TABLE B-13
LABORATORY COAL DESULFURIZATION DATA
CHLORINATION REACTION PARAMETERS, COAL PSOC-219
CHLORINATION: 500 ml stirred flask; 100 gram sample of -100 to 4200 mesh coal, acm pressure,
74'C, Cl2(g) at 0.75 g/min; methyl chloroform/coal at 2. water/coal at 0.5.
HYDROLYSIS: 1000 ml stirred flash, 60-100'C, water/coal at 2-4 per wash; 5-60 minutes
per wash, filtration water wash/coal at 1-2; 1 to 2 washes,
DECHLORINATION: 1-inch diameter quartz rotary tube at 1-2 RPM in split tube furnace, coal at
2 to 4 grams/batch, steam atm. at 0.4 to 110 grams/hour. temp, of 350 to
5506C, 15 to 75 minutes
Ave
No . of
Runs
Chlorinat ion
Time
(Min.)
Residual Sulfur Analysis
(Wt. X)
Sulfur Remov
(%)
a 1
Dechlorination
Residual CI (wt ?.)
Organic
Pyritic
Sulfate
Total
Organic
Pyritic
Total
Be fore
After
COAL PSOC-219, HVA BIT. KY
NO. 4, HOPKINS, KY
RAW COAL
1.08
1. 40
0.08
2.56
10
0. 78
0. 79
0.04
1.61
28
44
37
4.6
i
20
0.69
0.73
0.11
1.50
36
48
41
4.9
0.12
6
30
0.82
0.41
0.07
1. 39
27
71
46
5.4
0. 37
9
60
0.59
0.31
0.05
0.95
45
78
63
10 L
0 42
2
120
0 .45
0.48
0.14
1.07
58
65
58
14 6
0. 36
WATER
/COAL -
0.3
:
30
0.57
0. 75
0 04
1.37
47
46
4fc
4 . 74
0 95
:
60
0.56
0.40
0.06
1.00
48
71
61
6.86
0.21
2
120
0.70
0. 28
0.06
1.04
45
79
59
18.9
0.26
WATER
/COAL -
0.7
;
30
0. 78
0.45
0.01
1.24
28
68
51
5.1
0.17
60
0.63
0.47
0.02
1.15
41
66
55
9 2
0.53
2
120
0.71
0.41
0.03
1.14
34
71
55
11 .4
1 .16
TEMP. - 50'C
30
0. 78
0.35
0.02
1.15
28
75
55
-
0.45
2
60
0.69
0. 13
0.01
0.83
36
91
67
-
0.52
2
120
0.54
0.25
0.05
0.84
50
82
67
18.6
0.50
TEMP. -60*
C
1
30
0.71
0. 16
0.01
0.87
34
89
66
-
_
60
0.72
0, 18
0.07
0.96
40
87
62
8.6
0.47
1
120
0.74
0.08
0.03
0. 74
46
94
71
22 . 3
0.50
TEMP. - 85
•c
1
60
0.65
0.35
0.12
1.12
40
75
56
0.86
Cl2(g)
o. 37;
g/min
120
0.30
0.63
0.38
1.31
72
49
11.3
0.31
C12(g)
• 1.50 g/min
2
30
0.48
0.56
0.25
1.30
56
60
49
6.3
0.57
1
60
0.33
0. 19
0.40
0,96
69
66
62
13.1
1.00
1
120
0.70
0.04
0.18
0.92
35
97
64
19.8
-
SOLVENT - CARBON TETRACHLORIDE
1
30
0. 72
0. 31
0.01
1,03
33
78 1
60
-
0.21
0
60
0.74
0 43
0.08
1.20
37
69
53
8.8
0.15
2
120
0.64
0.50
0.05
1.19
40
64
53
9.0
0.96
SOLVENT
- TETRAC
HLOROETHYLENE AT
74°C
1
15
0.99
0. 34
0.02
1.35
8
76
47
-
1.29
20
0. 77
0. 30
0.13
120
29
79
53
24.4
1.14
30
0.66
0.57
0.07
1.30
39
59
49
11.2
0.41
3
60
0.55
0.53
0.05
1.13
49
62
56
15.3
1.01
1
120
0.66
0.46
0.05
1.18
37
67
54
17.1
0.64
SOLVENT
- TETRACHLOROETHVLENE AT
100°C
15
0.66
0. 77
<0.01
1.44
39
45
44
-
0 44
1
30
1 .00
0. 14
0.01
1.14
7
90
56
-
0.31
1
60
0.73
0. 42
0.05
1.21
32
70
53
23.1
0.39
SOURCE: Kalvlnskas 1978.
458
-------
TABLE B-.U
LABORATORY COAL DESULFURIZATXON DATA
EASTERN, MIDWESTERN, WESTERN COALS '
CHLORINATION:
500 ml stirred
pressure, 74'C;
water/coal at 0
flask; 100 gram senile of >100 to +200 mesh coal;
Cl2(g) at 0.75 g/min; methyl chloroform/coal at 2
atm.
HYDROLYSIS:
1000 ml stirred flask; 60-80*C; water/coal at A/wash; 60 min./wash;
filtration water wash/coal at 1; 1-2 washes.
DECHLORINATION.
1-inch diameter quartz rotary tube at I-
atrr. at 0.4 - 110 grams/hour; 400-500#C
2 RPM; 2-4 grams coal; steam
30-60 minutes.
Ave
3hlorination
Residual Sulfur Analysis
Oft. 7.)
Sulfur Removal
(X)
Dechlorination
Reiidual CI (Ut %)
.so of
Runs
1 ime
(Min.
)
Organic
Pyritic
Sulfate
Total
Organic
Pyritic
Total
Before
After
EASTERN COALS
PHS-513, BITUMINOUS, UPPER CLARION, BUTLER, PA.
(Bureau of Mines pretreated for Pyrlclc Sulfur Renoval)
iUW COAL
1.76
-0.20
¦"¦Q. 2Q
1.76
0.27
-
1
30
1.27
<0.20
-0. 20
1.26
28
-
28
-
0.44
1
60
1.16
<0.20
o
c*
o
1.16
34
-
34
-
0.90
*
120
1.28
<0.20
o
fS
o
1.28
27
-
27
-
1.18
PHS-398, RAW HEAD, 3A UPPER FREEPORT SEAM, SOMERSET.
PA.
RAW COAL
0.46
2.26
0.29
3.01
-
-
-
0.10
-
-
30
0 64
0.62
0.02
1.28
-40
73
57
-
0.14
-
60
0.63
0.19
0 .04
0.B7
-42
92
71
8.3
0.82
PSOC-108
HVB BITUMINOUS, PITTSBURGH, PA.
RAW COAL
1.07
2.06
0.00
3.13
-
-
-
-
-
1
30
0.71
1.23
0.21
2.16
34
40
31
7.65
-
2
60
0.50
0.43
0.09
1.01
53
79
68
9.4
0.92
i
120
0.66
0.39
0.04
1.27
20
82
59
14.1
0.39
PS0C-342, HVA BITUMINOUS. CLARION, JEFFERSON
PA.
RAW COAL
1.39
5.01
0.15
6.55
-
-
-
-
-
1
60
1.35
1.84
0.03
3.24
3
63
50
-
0.93
1
120
1.55
1.45
0.03
3.03
-11
71
54
12.83
0.15
MID-WESTERN COALS
PSOC-190, HVA BITUMINOUS, ILL NO. 6. KNOX. ILL.
RAW COAL
1.9
1.05
0.10
3.05
-
-
-
-
-
2
60
1.53
0.11
0.12
1.62
19
90
47
7.60
0.07
1
120
1.34
0.06
0.17
1.57
29
94
48
15.10
0.13
459
-------
TABLE B-14 (continued)
LABORATORY COAL DESULFURIZATION DATA
EASTERN, MIDWESTERN, WESTERN COALS
Ave
Chlorinacion
Residual Sulfur Analysis
(Ut. X)
Sulf
ur Removal
CO
Dechlorination
Residual CI (Wt. \)
No. or
Kuns
Time
(Min.)
Organic
Pyrit it
Sulfate
Total
Organic
Pyritic
Total
Before
After
PSOC-213
HVB BITUMINOUS, KY. NO
9
-------
TABLE B-15
OXIDIZED COAL SAMPLES
KVB PROCESS
COAL SAMPLE
TOTAL
PYRITIC
AND
SULFATE
ORGANIC
FINAL
TOTAL SULFUR
AFTER OXIDATION
PERCENT
REMOVAL
of Total
Initial S
of Initial
Pyritic S
Lower Kitanning
4.3
3.6
0.7
3.3
23
28
Kansas
6.7
5.1
1.6
4.1
24
31
Crawford Co.
—
29
Kansas
5.3
3.8
1.5
4.3
19
26
Crawford Co.
2.7
49
68
Oklahoma
3.2
1.3
1.9
2.5
22
54
Craig Co.
2.0
38
92
A
Particle Size -14 +28 Mesh. NO^/S Mole Ratio - 1 to 2.5 - Contacting the Coal
SOURCE: Guth 1978.
-------
TABLE B-16
OXIDIZED AND WATER WASHED COAL SAMPLES*
KVB PROCESS
COAL SAMPLE
INITIAL SULFUR CONTENT %
FINAL TOTAL
PERCENT
REMOVAL
Total
Pyritic &
Sulfate
Organic
SULFUR AFTER
WATER WASH
of Total
Initial S
of Initial
Pyritic S
Lower Kentucky
4.3
3.6
0.7
1.6
63
75
Illinois 5
3.0
1.1
1.9
2.0
33
91
1.9
37
100
Kansas
5.3
3.8
1.5
3.0
43
61
Crawford Co.
5.3
3.8
1.5
2.5
53
74
Moundsville (WV)
5.3
2.6
2.7
3.2
40
81
'ft
Particle Size -14 +28 Mesh. Mole Ratio - 1 to 2.5 - Contacting the Coal
SOURCE: Guth 1978.
-------
TABLE B-17
OXIDIZED WATER WASHED AND CAUSTIC WASHED COAL SAMPLES*
KVB PROCESS
COAL SAMPLE
INITIAL SULFUR CONTENT %
FINAL SULFUR
PERCENT
REMOVAL
Total
Pyritic &
Sulfate
Organic
of Total
Sulfur
of Organic
Sulfur
Lower Kittaning
4.3
3.6
0.7
0.5
88
29
Illinois 5
3.0
3.0
1.1
1.1
1.9
1.9
1.0
1.2
67
60
47
37
tip 'it
Moimdsville (WV)
2.8
2.8
***
1.6
43
43
*
Particle Size -14 +28 Mesh. KK^/S Mole Ratio - 1 to 2.5 - Contacting the Coal
**
Sample was pretreated to remove pyrites. Initially this sample analyzed 5.3%
total sulfur, 2.6 pyritic (and sulfates), 3.2 organic
***
After oxidation and caustic treatment
SOURCE: Guth 1978.
-------
Appendix C
Fluidized Bed Combustion
-------
TABLE C-l
RIVESVILLE TEST FACILITY
30 MWe ATMOSPHERIC FLUIDIZED-BED
BOILER DESIGN PARAMETERS
Primary Bed
Operating Temperature
Superficial Gas Velocity
Static Bed Depth
Overall Heat Transfer Coefficient to 48" Above
1500°F
12 ft/sec
24 inches
Air Distribution Grid
35 BTU/hr-ft2-°F
40% of Lime Feed Leaves with Dust Products
60% of Lime Feed Leaves with Bed Tap Products
10% Sulfur Input Captured as SO2
90% Sulfur Input Captured as CaSO^
65% of Fuel Ash Leaves with Dust
1% Carbon Contained in Bed Tap Products
90% Combustion Efficiency (10% of Total Fuel
Heat Input Escapes with Dust)
85% of Available Heat Released to Bed (to 4
ft above Grid)
15% of Available Heat Released to Free Zone
Design for 3% Excess O2 in Off-Gas
Ca/S Mole Ratio — 2
Carbon Burn-Up Cell
Operating Temperature 2000°F
Superficial Gas Velocity 9 to 10 ft/sec
Static Bed Depth 24 inches
Overall Heat Transfer Coefficient to 48" Above
Air Distribution Grid — 40 BTU/hr-ft^-°F
Excess Air 25%
90% Combustion Efficiency
Overall Unit
Equivalent Electrical Output-30 MWe
Steam Conditions
Rate, lb/hr 300,000
Pressure, psia 1450
Temperature, °F
930
465
-------
TABLE C-2
GEORGETOWN UNIVERSITY FLUIDIZED
BED STEAM GENERATOR
Steam Flow
100,000 lbs/hr
Outlet Temp./Press
Saturated/625 psig
Bed Dimensions
19'-A" x 11'-0 (2 Segments)
Design Coal
Bituminous
Heating Value
12,750 BTU/lb
Ash %
7.97%
Moisture %
5.0%
Sulfur %
3.29%
Design Parameters
Bed Depth
4-1/2 ft.
Bed Operating Temperature
1594F
Fluidizing Velocity
8 ft/sec
Freeboard Height
8 ft
Bed Tubes
Sloped
Segment Separation
Partition Wall
Ca/S Ratio
3/1
Coal Feed System
Stoker (2) - Side Wall Mount
Coal Size
1" x 1/4"
Coal Flow Rate
9,565 lbs/hr
Limestone Flow Rate
3,133 lbs/hr
Re-Injection Flow Rate
7,500 lbs/hr
Efficiency
83.51%
466
-------
TABLE C-3
CURTISS-WRIGHT SGT/PFB OPERATING CHARACTERISTICS
Design Point
Maximum
Conibustor Pressure - psia
94.4
94.4
Temperature - °F
1650
1750
Fluidizing Velocity - fps
2.7
5.0
Bed Height - ft.
16
16
Bed Airflow - pps
2.29
4.2
Coal Flow - pph
586
1130
Excess Comb. Air - %
30
35
Dolomite Flow - pph
(1.5 Ca/S to 2.0 Ca/S)
213-284
394-526
Cooling Airflow - pps
4.6
8.5
Inlet Air Temperature - °F
506
506
467
-------
TABLE C-4
PROCESS CONDITIONS OF SAMPLES STUDIED FOR
THEIR ENVIRONMENTAL IMPACT ON DISPOSAL
Condtt lona""""*-—*.^.,^
Argonna
C2/C3
A r gonna
VAJl-4
Argonwo^
REC-3
<*»>
Argonna
CCS-10
Argonn*
LST-1
Arronna
LST-:
Argonna
LST-)
A r gonna
LST-4
Coal
Arkvrtght
ArkvrlgM
Arkvrtghc
Trlangla
Arkvrtght
Arkwrlghc
Arkwrlghc
Arkvrtghc
Sorbtnt
Tyaochcca
dolo*tta
Tynocheaa
dolo«lta
Tvmoehcaa
dolonlea
Twechtaa
dolomlca
Llnaatona
2201
Dolonle*
1)37
Dolmtca
1331
lli*» aeon*
1 336
Hun Langch
—
—
—
—
—
~
_
-
Coal Faad Rata
(kg/hr)
—
7.9
13.3
—
12.1
11.7
11.7
11.6
Sorbane Faad Mti
(kg/hr)
—
2.A
2.9
—
1.7
3.A
3.1
1.3
Ca/S Molor Ratio
X.i—1-3
1.9
1.3
-
1.5
1.8
1.4
1.4
Excess Air
-
17
17
Ha due In g
17
17
17
17
S07Ealsslon (ppa>
(10*373
122
430
67,000
*00
160
270
990
*0^ (ffml
135
183
120
-
130
135
183
93
CO Iff*)
—
30
64
—
74
30
30
33
CO, (I)
-
10
16
-
16
1)
It
U
0,
3.0
3.0
3.2
-
3.3
1.1
2.9
3.0
S lUtanclon (I)
82-96
93
79
-.6$ r. 6)
laganaraclon
93
89
58
lb S0,/M»tu
—
0.23
o.gj
-
t.3
0.28
0.47
1.7
lb M0,/K*eu
-
0.23
0.1ft
-
0,18
0.17
1.23
0.12
'*'tklr4 csabwtlm nvarlmi In can-cycla c«*u«tlon/r«MHf«tlon • •run af Hptrlann
T««th raamaratlM In tm-cycla eoahvml
-------
TABLE C-4 (Concluded)
^ Samolaa
Cdnd 1 c
Exxon
1.4
Exxon
27
Exxon
19.4
Exxon
30.2
Exxon
2*
Exxon
34
FCT
Coal
ATkvright
Champion
Chanptcm
Champion
Champion
Champion
Sevlekley
Scrbtnt
Crew llMttone
1359
Pflier
dolovlte 1337
Grove llacstonc
1)59
Grove limestone
1359
Crow llnastone
135*
Pfltar
dolomite 1337
Grove
limestone
Run Langth
(hr)
11
240
7,5
8*5
15.5
13.25
—
Pracaura
(kPa)
906-907
930
930
920
930
932
101.1
Avg Bed Teap
CO
—
829-930
880-'8*
929
885-927
900
816*C
Lover Bed Tcap
CC)
877*908
840-960
—
945
949
868
—
Cat Velocity
(¦/a)
1.77-1.*3
1.7-2.2
2.01-;
2.5
1.9-2.1
1.5
2.7-4.6
Expanded Bed Height
(*)
—
3-7
—
—
—
—
-
Seeded Bed Height
<¦>
0.66-1.19
—
1.5S
—
1.12-2.28
2.29
0.1-0.9
Coal Feed Rate
(kg/hr)
75-112
112-149
113-li)
137
130
90
272-361
Sorbent read Rat#
(kg/hr)
10.3-15.2
—
—
—
—
"
0-182
Ca/S Molar Ratio
1.67
0-2.5
2.5
3.7
3.7
0.75
-
Excess Air
18-72
8-23
15
17.2
9.5-11.5
20.9
-
SO^Enlaslon (pn)
—
20-1290
5/V>
137
140-300
100- 300
-
NO^(ppm)
50-200
70-210
10i
-
180-185
52
-
CO (ppa)
—
. *vno
-
45
50
61
-
co2 (X)
—
1.1-17
11.7-11.3
15.1
13
15.5
-
02 Ct>
—
1.5-3.9
2.5-3.-*
3.1
, 1.8-2,15
3.5
1
S Retention (Z)
62
41-100
M
IW
81-«1
-
-
lh SOj/MfttU
1.8
O.OV2.5
1.0
-
0,29-0,59
-
-
lb M02/MBcu
-
0.12-0.30
o.n
-
0.25-0.28
-
-
469
-------
Appendix D
Coal-Oil Mixtures
-------
I. DESCRIPTION OF COM PROCESSES
INTERLAKE PROCESS DESCRIPTION
The Interlake COM process is intended to demonstrate the use of
COM as a supplementary fuel for their blast furnace "B" located at
Chicago, Illinois (Keyser and Marlin 1977).
The blast furnace is the most widely used device for reducing
iron ore to metallic iron, Figure D-l is a diagrammatic cross section
of a typical blast furnace. Until 1960, fuel for all blast furnaces
was charged into the top of the furnace, usually in the form of
metallurgical coke. In passing down through the blast furnace with
the other raw materials (iron ore, limestone, etc.), most of the coke
survives in solid form until reaching the hearth area, where it is
burned in the presence of high-velocity heated air entering the
hearth through the tuyeres. About 15 years ago, it was discovered
that part of the fuel requirements of a blast furnace could be
provided by injecting gaseous or liquid fuels at the tuyeres along
with the blast air. The advantages of injecting fuel at the tuyeres
are the added flexibility of an alternate supplementary fuel, re-
duction in requirements for (expensive) coke, and the greater control
of the blast furnace operations.
In the Interlake COM process (see Fig. D-2), three items—
coal, oil, and a water-emulsifier mixture are brought together to
form a stable COM. The No. 6 fuel oil, heated to a temperature of
160°F, is supplied from an existing oil storage and pumping station.
Coal is supplied from a storage hopper. The water-emulsifier mixture
is supplied from premix tanks. The COM is produced in a single com-
minuting and mixing batch operation performed in a high-speed dis-
perser. This technique eliminates the fire hazards and environ-
mental problems associated with dry grinding of the coal. The
finished COM will be pumped to a storage tank.
COM from the storage tank will be pumped to the furnace and dis-
tributed to the individual tuyeres. The injected COM then releases
its chemical energy, partly as sensible heat to the products (iron)
and by-products (slag and top gas) and the rest is transformed from
one form to another of chemical energy by means of the following four
main iron-reducing reactions:
Fex0y + CO —~Fex0y_i + CO2
FexOy + H2 —FexOy-! + H20
C02 + C —f 2 CO
471
-------
Double-bell and hopper
Ore, Coke, Limestone
Ore loses moisture and
becomes more porous.
Reduction starts,
iron and impurities
begin to separate.
Reduction completed
Ore first becomes
spongy and then
fluid iron and slag
start trickling down
to the hearth.
Slag Out
Top gastodustcatcher
Preheated air (980°C)
COM Tuyere Injection
Iron Out
FIGURE D-1
DIAGRAMMATIC CROSS SECTION OF A
BLAST FURNACE
472
-------
TO BOILER
FIGURE D-2
INTERLAKE COM PROCESS (COMMERCIAL SCALE)
-------
h2o * C —~ CO + h2
Of course, other elements present, principally silicon and man-
ganese, are also reduced to the metallic state. Some energy is also
used to convert fluxes, gangue, and ash to silicates, which appear in
the slag. Finally, the blast furnace acts as a low-Btu gas producer,
as indicated by the following typical top gas composition: 16 percent
CO2. 23 percent CO, 4 percent H2 and 57 percent N2. The top
gas after cleaning is utilized to produce auxiliary energy for air
blast heating and process steam.
The coal to be used is a high volatile bituminous coal with a
nominal top size of 2 inches, a heating value of approximately 12,500
Btu/lb, an ash content of 9 percent and a sulfur content of up to 2.6
percent. The No. 6 oil to be used has a heating value of 15,000
Btu/gallon and a maximum sulfur content of 2.8 percent. The em-
ulsifier is Tetrolite, a proprietary product of Petrolite.
The proposed COM will be 50 percent coal, 45 percent oil and 5
percent additive-water solution (containing approximately 5 percent
additive in solution, by weight). The estimated daily usage of COM
is 22,320 gallons, consisting of 102,500 pounds of coal, 11,500 gal-
lons of oil, and 58 gallons of emulsifier.
The COM preparation plant is under construction. Feasibility
testing for 2 months is scheduled for the last quarter of FY 1979.
Demonstration testing is scheduled for the last quarter of FY 1980.
474
-------
II. NEPSCO PROCESS DESCRIPTION
The NEPSCo program is a full-scale test program to fire COM at
30 percent coal by weight in a high-pressure boiler originally de-
signed for coal and now firing oil. The boiler is located at Salem
Harbor, Massachusetts. The only significant modification to the
present boiler system is the installation of a commercially available
burner considered highly suitable for the expected characteristics of
COM. The boiler is a front-wall-fired radiant design installed in
1951 by Babcock and Wilcox Corporation, having a steam flow of
625,000 lb/hr with a superheat and reheat temperature of 1000°F at a
design pressure of 1,675 psig. *
The NEPSCo process (see Fig. D-3) will produce a 2.2 percent
sulfur COM consisting of 30 percent high— to medium-sulfur coal
(Pittsburgh Seam No. 8) and 70 percent low-sulfur (1%) oil. In prin-
ciple, it is intended to produce a stable (the suitability of a COM
to minimize separation of coal particles during storage and pumping
is generally referred to as the mixture stability). COM without the
use of additives. If storage stability of up to 1 week is not
possible with low-speed mechanical agitation only, then chemical
additives will be used.
The coal will be delivered in 6,000-ton barges and unloaded into
a coal storage pile. This pile will be sealed with an oil emulsion
spray to control dust and erosion. Coal will be conveyed from a
breaker house into an existing 1,000 ton capacity coal storage bunk-
er. From there it will be fed to the existing ball pulverizer, where
it will be ground to 80 percent through a 200-mesh sieve. The air to
the pulverizer, as supplied by the existing primary air fans, will be
used as the drying and conveying medium. The sieved coal will be
piped to a cyclone separator mounted on top of the pulverized-coal
storage bin. Pulverized coal will be conveyed by a gravimetric feed-
er into the COM blending tank, where it will be continuously wetted
and mixed with No. 6 fuel oil by a dual-impeller turbine agitator.
COM will be pumped from the blending tank to the storage tank. The
COM storage tank is an existing 700,000 gallon tank which is being
insulated and modified by the installation of a simple impeller tur-
bine agitator.
From the storage tank, the COM will be pumped to the existing
boiler retrofitted with new burners which because of their low-
pressure operation and large nozzle design, should eliminate poten-
tial plugging and erosion due to COM.
Ir.M. Dunn, The New England Power Service Company Demonstration
Project, First International Symposium on Coal-Oil Mixture Combus-
tion Proceedings, St. Petersburg Beach, FL, May 7-9, 1978, CONF-
7805141 (McLean: The MITRE Corporation, 1978, M78-97) pp. 80-89.
475
-------
STACK
FIGURE 0-3
NEPSCO COM PROCESS (COMMERCIAL SCALE)
-------
The existing electrostatic precipitator should be sufficiently
efficient for compliance with the regulatory limit of 0.12 lb per
million Btu. The flyash captured by the ESP is removed and separated
by a water recycle and hydroclone system resulting in practically a
zero discharge to public waters.
The mixture normally will be 30% by weight coal, resulting in an
estimated heating value of 16,700 Btu per pound. The COM rate of
consumption at full load will be 6,000 gallons per hour, equivalent
to approximately 7.8 tons of coal and 4,500 gallons of oil per hour.
Demonstration testing is scheduled to start in August 1979 and
proceed continuously for 12 months.
477
-------
III. PETC PROCESS DESCRIPTION
The Pittsburgh Energy Technology Center (PETC) at Bruceton,
Pennsylvania, is operating an experimental combustion test facility
(CTF) built around a commercial packaged boiler. The CTF consists of
a COM preparation plant, a 700-hp packaged water tube boiler, a heat-
removal system, and a flue gas cleaning system. Because of the ex-
perimental nature of this facility, coal-oil mixtures will be made
with different coals, particle size distributions (75, 85, and 95
percent through 200 mesh), coal concentrations (30, 40, and 50 per-
cent by weight), and with/ without additives for stabilization. Coal
grinding under contact with No. 6 oil (wet-grinding) also will be
tested and compared with the dry grinding process. *
In the PETC process (see Fig. D-4) coal is delivered to the
facility by truck and unloaded into a coal storage bin. The coal
moves through the bin to a coal pulverizer and drying system, which
includes fines separation and an inert combustion gas blower. The
pulverizer has a capability of 3,000 pounds per hour and reduces the
size of the coal to 90 percent through 200 mesh. No. 6 oil is re-
ceived at the facility in tank trucks. Slurry is prepared by mixing
the desired portions of oil and coal in a proportioning-mixing tank
and then transferred to a COM storage tank.
The COM is injected at temperatures from 140 to 220°F into the
700-hp combustion test boiler, which generates a maximum rate of
24,000 pounds of steam per hour at 175 psig. Since sulfur dioxide
levels would be too high to permit discharge to the atmosphere, the
flue gas is treated with sodium bicarbonate near the inlet to the
baghouse. The reaction product, sodium sulfate, is collected on the
filter bags along with the ash for landfill disposal. Particulate
removal efficiency is higher than 99 percent and SO2 removal
efficiency is higher than 70 percent.
Three fuel feedstocks will be used during test firing: No. 6
fuel oil, Pittsburgh seam bituminous coal, and Western subbituminous
coal. The No. 6 fuel oil has a heating value of 18,400 Btu/lb and a
sulfur content of 0.9 percent. The Pittsburgh seam bituminous coal
has a heating value of 13,200 Btu/lb, a sulfur content of 1.8 percent
and an ash content of 10 percent. The Wyoming subbituminous coal has
a heating value of 8,000 Btu/lb, a sulfur content of 0.6 percent, and
an ash content of 6 percent.
*U.S. Energy Research and Development Administration, Environmental
Assessment of a Coal-Oil Slurry Combustion Test Facility, Pittsburgh
Energy Research Center, Bruceton, Allegheny County, PA, Division of
Coal Conversion and Utilization, CIA/CCU77-4, 1977.
478
-------
STACK
FIGURE D-4
PETC COM PROCESS (PILOT PLANT SCALE)
-------
The major process characteristics are:
• The maximum boiler heat load is 23.5 x 10^ Btu/hr.
• The average COM will be 40-50 percent coal and the balance
oil (by weight).
• For a 40/60 COM utilizing Pittsburgh seam coal, the fuel pro-
perties are:
Heating value 16,300 Btu/lb
Sulfur content 1.3%
Ash content 3.9%
and the fuel rates are:
Coal 577 lb/hr
Oil 865 lb/hr
COM 1442 lb/hr
• For a 40/60 COM utilizing Wyoming coal, the fuel properties
are:
Heating value 14,200 Btu/lb
Sulfur content 0.8%
Ash content 2.6%
and the fuel rates:
Coal 660 lb/hr
Oil 990 lb/hr
COM 1650 lb/hr
PETC also has a 100-hp test facility to provide technical sup-
port to the COM program. * Both facilities are scheduled to con-
tinuously support and collect information for DOE's COM program.
Ij.J. Demeter, C.R. McCann, G.T. Bellas, J.M. Ekmann, and D.
Bienstock, Combustion of Coal-Oil Slurry in a 100 hp Firetube
Boiler, Combustion (April 1978): pp. 31-37.
480
-------
Appendix E
In Situ Gasification
-------
APPENDIX E
IN SITU GASIFICATION TECHNOLOGY OPTIONS
Linked Vertical Wells Process (LVW)
The LVW process is applied by drilling vertical walls into the
coal seam to provide for injection of air and collection of product
gases. Reverse combustion is used to link the wells through the coal
seam, followed by forward gasification of the coal between the linked
wells.
In Figure E-l, the center and right wells are linked by reverse
combustion. High pressure air is injected in the right well and
flows to the center production well through naturally occurring
cracks and paths in the coal. The combustion zone advances from
center well to the right well (injection well) against the gas flow
creating a hot char channel between the wells. Once two wells are
linked, the gasification front reverses direction moving with the gas
flow. This second stage, called forward gasification, is shown
between left and center wells in the diagram. Forward gasification
proceeds along the linked passage which widens and caves in to expose
more coal (U.S. Department of Energy 1978a).
*
Steeply Dipping Beds Process (SDB)
This process is being developed to gasify coal seams that dip
at angles greater than about 35°. This coal is not recoverable by
existing mining methods. Drilling requirements and subsidence prob-
lems are less for this process than for the other in situ gasifica-
tion processes.
As illustrated in Figure E-2, slanted holes, cased only through
the overburden, are drilled into and through the coal bed following
the dip. A channel connects the lower ends of these slanted produc-
tion wells. All injection wells are drilled either vertically,
slanted underneath the coal bed, or in the coal bed itself to inter-
sect the horizontal channel connecting the uncased production holes.
Product gases are withdrawn through the slanted holes in the coal bed
midway between the injection holes. Reducing reactions occur on the
surface of the slanted, uncased exhaust holes. As the coal above the
along the horizontal channel burns away, the fire zone advances
updip.
Steeply dipping beds generally are uneconomical to mine, yet
over 100 billion tons of SDB coal are estimated to exist in the
United States. A large percentage of the Pacific coast coal is
481
-------
AIR COMPRESSOR BLDG.
GAS CLEANUP
BLDG.
TO POWER PLANT
FORWARD
GASIFICATION
REVERSE
COMBUSTION
LINKING
SOURCE: Department of Energy 1978b
FIGURE E-1
LINKED VERTICAL WELLS PROCESS
482
-------
STRATA CRACKING
AND SUBSIDING
NO. 1 AIR
INLET
GAS OFFLET N0- 2 AIR INLET
(IN DIFFERENT n2?ecEncND
VERTICAL PLAN ™ASE 0F
THAN AIR INLETS) GASIFICATION
NO. 1 AIR INLET USED
FOR FIRST PHASE OF
GASIFICATION
ASH AND CLINKER IN
BURNT OUT AREA
ORIGINAL END OF
GASIFICATION BORE HOLE
REACTION ZONE
STRATA SUBSIDING
INTO BURN-OUT AREA
SOURCE: Department of Energy 1978b
FIGURE E-2
STEEPLY DIPPING BED CONCEPT
483
-------
steeply dipping so commercialization of an SDB process would
contribute, to the future energy supply of the populous West Coast.
There are also substantial SDB deposits in the Rocky Mountain area
and lesser amounts in the Appalachian and interior coal regions
(Department of Energy 1978a).
The underground gasification of SDB coal is under development by
the Gulf Research and Development Company and TRW Systems at a site
near Rawlins, Wyoming. The Soviet Union has been highly successful
in employing slant drilling along the dip of a coal bed, thus this
process is almost in hand for U.S. application to SDB coal (Sikri and
Burwell 1979).
484
-------
PREGASIFICATION
Process Information
Pregasification is preparation of the coal seam for subsequent
gasification, and generally consists of increasing seam permeability.
Although some coal seams are naturally permeable to some extent, as a
practical matter all seams require preparation prior to gasification.
Methods of increasing bed permeability include electrolinking, pneu-
matic linking, fracturing by hydraulic pressure (normally not con-
trollable), explosives, deviated drilling, and reverse combustion
(Phillips and Muela 1977).
Waste Streams and Potential Constituents
Air
Water
• water from dewatering
- natural groundwater contaminants
485
-------
GASIFICATION (in situ)
Process Information
The methods of gasification can be classified as shaft type,
shaftless type, or a combination of both. Shaft-type gasification
requires the drilling of underground channels or passageways. Shaft-
less gasification (research to date has focused on this matter)
requires only surface drilling operations. Current research is
almost entirely devoted to the development of shaftless technology.
Gasification involves introduction of gasifying agents, i.e.,
oxygen, steam, and carbon dioxide, and subsequent reaction with the
coal seam to produce carbon monoxide, carbon dioxide and hydro-
carbons. The product gases are removed via production wells
(Phillips and Muela 1977).
Waste Stream and Potential Constituents
Air
• Product gas leaks
- carbon monoxide
- carbon dioxide
- hydrogen
- water vapor
- nitrogen
- methane
- volatile organics
- heavier entrained hydrocarbons
- hydrogen sulfide
- trace elements
Water
• Groundwater/surface water contamination by combustion
residues
- phenols
pyridines
- anilines
- quinolines
- aromatic nudrocarbons
- trace elements
• water from dewatering
- groundwater contaminants
- contaminants from combustion residues
486
-------
Remarks
As a result of hydraulic gradients, migration of groundwater
will occur through coal seams and burned-out areas which lie below
the water table. This may cause soluble components in or sorbed on
the ash or char to be leached out and transported away from the
gasification site. An increase in dissolved organic material could
result from partial dissolution of coal tars formed during
gasification. Phenols, pyridines, anilines, quinolines, and aromatic
hydrocarbons pose varying hazards.
Incorporation of inorganic salts and trace elements into the
groundwater could occur via leaching of ash components. The dis-
persion of soluble contaminants will be a function of groundwater
flow and the sorptive properties of the materials through which the
leachate passes (Phillips and Muela 1977).
487
-------
TABLE E-l
ORGANIC COMPOUNDS IDENTIFIED IN EFFLUENTS
FROM THE GASIFICATION PROCESSES
Compound of Chemical Class
Liquid
Solid
Acenapthene
•
Acenaphthenols
•
Aniline
•
•
Anthraquinone/Disulfonic acid
•
Benzaldehyde
•
Benzene
•
•
Benzofuranol
•
Benzonaphiothiophenes
•
Benzonitrile
•
m-Cresol
•
o-Cresol
•
£-Cresol
•
Dibenzofuran
•
Dibenzthiophenes
•
Ethylene glycol
•
Fluorene
•
Indane
•
Indanols
•
A-Indanol
•
Indane
•
Indole
•
m-Methoxyindole
•
Methyl indole
•
Methyl mercaptan
•
•
Naphthalene
•
•
488
-------
TABLE E-l (Continued)
ORGANIC COMPOUNDS IDENTIFIED IN EFFLUENTS
FROM THE GASIFICATION PROCESSES
Compound of Chemical Class
Liquid
Solid
Naphthols
•
1-Naphthol
•
2-Naphthol
•
Naphtho1, methy1
•
Phenanthrene
•
Phenanthrols
•
Phenol
•
•
£-Ethylphenol
•
p-Ethylphenol
•
o-Isopropylphenol
•
2-Methyl-4-ethylphenol
•
3-Methyl-6-ethylphenol
•
4-Methyl-2-ethylphenol
•
2,3,5-Trimethylphenol
•
1-Phenylnaphthalene
•
Pyridine
•
•
Pyridine-ethyl
•
Pyridine, methyl
•
Pyrocatechol
•
•
Pyrocatechol, methyl
•
Thiophene
•
•
Thiophene, dimethyl
•
•
Thiophene, methyl
•
•
Toluene
•
•
2,3-Xylenol
•
489
-------
TABLE E-l (Concluded)
ORGANIC COMPOUNDS IDENTIFIED IN EFFLUENTS
FROM THE GASIFICATION PROCESSES
Compound of Chemical Class Liquid Solid
2.4-Xylenol •
2.5-Xylenol •
2.6-Xylenol •
3.4-Xylenol •
3.5-Xylenol •
SOURCE: Pellizzari 1978.
490
-------
TABLE E-2
ELEMENTAL COMPOUNDS IDENTIFIED IN EFFLUENTS
FROM THE GASIFICATION PROCESSES
Elemental or Inorganics
Liquid
Solid
A1
A12°3
Ammonia
As
Arsenic acid, Na salt
Ar2°2
Arsine
Ba
Be
B
BO
Br2
Ca
CaO
CaS
Cd
CS
COS
Cl2
Cr
Co
Cu
Cyanides
Fe
FeCl,
491
-------
TABLE E-2 (Concluded)
ELEMENTAL COMPOUNDS IDENTIFIED IN EFFLUENTS
FROM THE GASIFICATION PROCESSES
Elemental or Inorganics
Liquid
Solid
F
Ge
HC1
HCN
HF
h2s
Hg
K
Mg
MgO
Mn
Na
Ni
NiCO
P
Pb
Sb
Se
Sn
Sr
Te
V
V2°5
Zn
ZnO
SOURCE: Salk and DeCicco (eds) 1978.
492
-------
TABLE E-3
SOME ENVIRONMENTALLY HAZARDOUS ORGANIC SPECIES
Compound
Hazard
Poiycyldc aromatic*
Naphthalenes
Naphtalcnc
l-Methyl naphthalene
Acenaphtheacs
Acenaphtene
Anthracenes
Anthracene
9-MethyUnthraccne
Phenanthrenes
Phenaiuhrcne
Pyrenes
Pyrene*
Fluoranthenes
3-Mcthyinuoranthcnc
Fluoranthene
Indenopyrenes
Indcnof 1,2,3-<in>cthylbcn/faJaalhr»ccr>e
8. 12-Dtmcihylbefu(a)anibrace(>c
I • Mctliylbcn/(]fluoraMlicne
Bcnzof A }l]uoranthene
Benzopyrcnes
Bcnzo(d]|>yrenc
ficnzi^rlpyrene
3-Mcthylbcnzo[«)pyrene
Perylencs
Pcrylene
Dibenzantracenes
Diben/fa.AJanthracene
Diben/fa. < janthracene
DibcnzfajJanthracenc
Dibensopyrenes
L)i ben/ofa./Jpyrene
Dibenzo[a./]penuphene
Dibenzoperylenes
Pcropyrene
Carcinogen
Suspected carcinogen
Carcinogen
Carcinogen
Suspected carcinogen
Carcinogen
Carcinogen
Suspected carcinogen
Suspected carcinogen
Carcinogen
Suspected carcinogen
Suspected carcinogen
Carcinogen
Suspected carcinogen
Suspected carcinogen
Suspected carcinogen
Carcinogen
Suspected carcinogen
Suspected carcinogen
Pyrroles
Pyrrole
Nitrogen heterocyclics
Toxic
Morpholines
Morpholine
/V-Ethylmorpholine
Bismorpholino methane
Irritant
Irritant
Carcinogen
.SOURCE: Salk and DeCicco (eds.) 1978.
-------
TABLE E-
Pyridioes
Pyridine
(t-Picolinc
3.4-Dihydroxypyridine
Indoles
Indole
Carbazolcs
Carbazole
Benzocarbazoles
Benza(a)carbazolc
Dibenzocarbazoles
7 //-l)ibcnzo(r.g]carbazole
7//-Dibcnzo(a.<]carbazole
7//-Dibenzu(cridine
7-Meihylbenzfrjacridinc
Dibcnzacridines
I )ibcn/f a.y]acridine
Irritant
Irriuni
Carcinogen
Suspected carcinogen
Toxic
Suspected carcinogen
Carcinogen
Suspected carcinogen
Suspected carcinogen
Toxic
Toxic
Suspected carcinogen
Suspected carcinogen
Carcinogen
Carcinogen
Phcnazines
Phcnazines Suspected carcinogen
Nonhctcrocydk nitrogen compounds
Nitrites
Acctronitrilc Toxic
Acrylonitrilc Toxic
(CONT'D)
Aliphatic amines
Piperidine
Toxic
Methylamine
Irritant
Ethylamine
Irritant
^-Propylamine
Irritant
n-Butylaminc
Irritant
Triethylamine
Irritant
Ethylendediamine
Irritant
Cyclohcxylaininc
Irritant
Dicyclohexylamine
Irritant
Dimcthylaminc
Mutagenic
AUylamine
Irritant '
Anides
Acrylamidc
Toxic
Acetamide
Carcinogen
N, AZ-Dicthylacctamide
Suspected carcinogen
Acctylaminofluoranthcnc
Suspected carcinogen
Thioacetamide
Mutagenic
Acetanilide
Mutagenic
Aromatic amines
o-Toluidine
Suspected carcinogen
/n-Toluidine
Suspected carcinogen
/i-Naphthylamine
Carcinogen
Diphcnylamine
Suspected carcinogen
Benzidine
Suspected carcinogen
4-Amino-biphenyl
Suspected carcinogen
Aniline
Toxic
4,4-Mcihylenedianiline
Suspected carcinogen
Aminoazobenzene
Suspected carcinogen
Bcn/ylamine
Irritant
/>-Plienylcitediamine
Irritant
Imines
Ftnylcnimine
Toxic
Hydroxyla mines
iV-llydroxyaniline
Mutagenic
A'-2-Naphthylhydroxylamine
Suspected carcinogen
Hydroxyla mine
Mutagenic
-------
TABLE E-
Compound Hazard
Hydrazines
Hydrazine
Suspected carcinogen
1,3-Diethy Ihydrazine
Suspected carcinogen
Methylhydrazine
Suspected carcinogen
Hydroazobcnzene
Suspected carcinogen
Semicarbazides
Semicarbazide
Carcinogen
Azo compounds
Azobenzenc
Suspected carcinogen
Azoethenc
Suspected carcinogen
Thioureas
lliiourea
Suspeaed carcinogen
Mercaptans, aliphatic
MethylmercapUq
Disagreeable odor
Ethylmcrcaptan
Disagreeable odor
Isopropjrlmcrcapun
Disagreeable odor
«-Propylincrc=ptan
Disagreeable odor
2-Pentylmercaptan
Disagreeable odor
Isoamylmcrcaptan
Disagreeable odor
n-Amylmercapian
Disagreeable odor
n-llexylmcrcapian
Disagreeable odor
^-Mercaptoethanol
Mutagenic
Mercaptans, aromatic
Thio phenol
Disagreeable odor
Bcnzylmcrcaptan
Disagreeable odor
p-Thiocrckol
Disagreeable odor
Thionaphlhol
Disagreeable odor
Sulionic acids
Bcnzcnesulfonic acid
Irritant
Meihancsutfonic acid
Irritant
Sulfuric acid esters
Dimclhyhulfalc
Suspected carcinogen
/i-l'rgpylmcttunesulfooaie
Mutagenic
Sulfoxides
Dimcthykulfoxide (DMSO)
Suspected carcinogen
(CONT'D)
Compound
Hazard
Sulfides
Carbon disulfide
Thiophenes
ThiAphene
Toxic
Toxic
Benzene derivatives
Polyaryls
Bi phenyl
Double-bond conjugated bciiezenes
Styienc
Alkylbcnezenes*
Benzene
Toxic
Toxic
Phenol
0-Chlorophenol
2.4-Xylenol
2.5-Xylenol
2.6-Xylenol
3,4-Xylenol
),S-Xylenol
p-Cresol
m-C rcsol
p-Cresol
1-Naphltiol
2-Naphthol
Pyrogallol
llydroquinone
Aliphatic acids
Formic acid
Acetic acid
Propionic acid
Butyric acid
Valerie acid
Caproic acid
Suspected carcinogen
Phenols
Suspected
Suspected
Suspected
Suspected
Suspected
Suspected
Suspected
Toxic
Toxic
Toxic-
Toxic
Toxic
Irritant
Irritant
carcinogen
carcinogen
carcinogen
carcinogen
carcinogen
carcinogen
carcinogen
Carboxylic acids
Caustic
Caustic
Disagreeable odor
Disagreeable odor
Disagreeable odor
Disagreeable odor
-------
TABLE E-3 (CONCLUDED)
Acrylic acids
Acrylic acid
Metbacryiic acid
Carbamates
Methylcarbamaic
Ethylcarbamate
n-Bulylairbam^te
n-Propylcarbamate
Lactones
0-Propiolactone
-y-Butyrolactone
Amino benzoic acids
Anihranilic acid
Aliphatic aldehydes
Formaldehyde
Acctuldehyde
Propionaidchydc
Butyraldehyde
Glyccraldchydc
Aliphatic ketones
Acetone
Methylcihylkatone
Cyclohexanonc
a.fi Unsaturated carbonyls
Acrolein
Crotonaldehyde
Irritant
Irritant
Mutagenic
Mutagenic
Mutagenic
Mutagenic
Mutagenic
Mutagenic
Suspected carcinogen
Irritant
Suspected carcinogen
Irritant
Irritant
Mutagenic
Irritant
Irritant
Carcinogen
Irritant
Irritant
Aromatic carbonyls
Acetopkenonc
Furfural
Irritant
Irritant
Quinones
Benzoquinone
Ant hraqui none
2-Methylbcnzoquinone
Suspected carcinogen
Suspected carcinogen
Suspected carcinogen
Other species
Oxygen heterocyclics
p-Dioxane
Suspected carcinogen
Coumarin
Suspected carcinogen
Alcohols
Methanol
Toxic
Ethanol
Suspected carcinogen
Allyl alcohol
Irritant
Ethylene glycol
Suspected carcinogen
Cyclohexanol
Carcinogenic
Gaseous species
Hydrogen cyanide
Toxic
Carbonyl sulfide
Toxic
Carbon monoxide
Toxic
1,3-Uutadiene
Irritant
"Other major alkylbenzcnes present as major constituents of their class are also significant.
-------
TABLE E-4
POSSIBLE CONSTITUENTS OF GASIFIER OFF-GAS
CATEGORIZED BY BOILING RANGE
Present in
Known
Present In ¦
Known
Gasification
Carcinogen
Gasification
Carcinogen
Joillnq Poin; < !C0*C
3oiMna Plint ¦ *3 'S-Z'Z '•
AT 1 Oh*tic HydrocarttoM:
Aliphatic Hydrocarson:
Anylana
Octan*
1,5-3utadt«nt
j
3ucyT«ia
Cycl1c Hydrocarbons:
I i
Crotany
H«OUK
Haotana
Haxana
Olmathyl syelohexana {
i
J«tny I cycloflaxana
Honapnthana
!
j
Haxana
?»tan«
Aromatic Hydrocarbons:
Ettiylbannna-
!
•
•
i
Cyclic Hydrocarbons:
Styrara
Cyclohexadana
Toluant
o-Xylana
at-Xylana
p»Xyt«n«
X
!
i
Cyclonaxana
CycIoMxarta
Cyclopantadlana
Aromatic Hydroearton:
Oxygan-containing Ccnoouflds:
. SMStM
X
X
Aerctc ietd
Prooanctc add
X
X
Oxygan-contafninq CanpoundJ:
Nltroqafi-contalnlivj CawoumU:
Acatildaftyda
Aeaeon*
Carton aonaxlda
fetttyl tciyl icaeana
Z,S-01mathyI pyridlna
t
2-wathyloyrid1na
J-#athy IpyHdtna
<-#athy 1 pyrf dlna
.Ktro^an-csneilntng CaacounCs:
tyrtdtn#
Pyrrota
teatofltert!*
/inoonl*
X
Sulftw-canttinlnf CanooundJ:
rtydreqcn cyan i da
.tltroqan axidas
J-Mtttylttlopftana
TMoxana
X
X
1
I
Salfur-onaining Ccncounos:
j
Giro on 41suiflsa
[
Caroonyt sul««a
X
i
Olacnyl luittda
3l»«hyi jul fiea
EtSyt iwrcaoean
HydreMfl sulfiet
.lacflyl narcspcan
X
Sulfur
ThiopntM
SOURCE: Enviro Control, Inc. 1978
497
-------
TABLE E-4 (Continued)
Present fn
Chowti
Known
3asi ficati on
Carcinogen
| Ga»i ficatton
Carcinogen
:-*i * i id ¦» i =0'C *.0 -C-CC I
i
i
t
i
Soilino Poiric • JCCTC "3 JSO'C 1
1
1
Aliphatic Hydrocarbon:
Aliphatic Hydrocarbon
•
cocardnogen
|
^-Cccac '.r.r:
2acans j
! I
!
Cyclic Hydrocarbon:
i
!
P'jlyr.uct ?jr iruwtic Hydrocarbons:
i
0 i cy c 1 open tadi ene
1
Cholanthrene
Dihydronaphthaltnt
i
1
Aromatic Hydrocarbons:
4,6-01metnylindent
Cymene
5,7-0im«thylindent
i
Durene
1 -Mis tny 1 naoh th« 1 ene
x I
o-£thyltoluene
2-M»thylnapfttnalene
X
n-ctttyl toluene
naphthalene
X
^-ithyl to 1 ucnc
He«el 11 ten*
Oxygen-containing Compounds:
Hydrindene
Acetophenone
isodurent
Benzoic acid
tsopropylbenzene
/n-Cresol
X
Mesitylene
p-Cresol
X
n-Propylbenxent
*2,2' • 01 hydroxydl oheny 1
Pseuaoc-jnene
2,3-01methylonenol
X
Polynuclear Aronatic Hydrocarbons:
2,4-Oimethylpnenol
3,4-01 n» thy 1pheno1
X
2,7-0iatthyUnd«««
3,5-01methy1phenol
X
3,5-Oimetnyiindent
2,6-01methy1pheno1
X
1 Indent
X
Z,S-01methy1 phenol
*
! Oxygen-containing Compounds:
01 methyl coum rone
Ourenol
I
!
n-3utanoic add
X
a-Ethylphenol
X
Coum rone
if-€ thy 1 phenol
;
0'Cresol
X
p-Ethylphenol
0imetny1coumarone
n-Heptanolc add
X
n-?entanoic acid
X
coctpclnogen
IsooseudocuMfiol
Phenol
X
3-Me thy1-5-e thy1pheno1
1
' Ni trogen-conta i ni ng CaMOounds:
Nitrogen-containing Compounds:
1
Aniline
j
Acetaalde
X
8enzon1trl1t
|
Ijoouinolint-
1
QlmtthylanlUnt
2-WethylquinoIlnt
1
2,3-01«*lhy)pyHd1n«
i
\
8-Methytquinollnt
2,4-0imethylpyrld1nt
i
1
Prootonanrtde
X
2.5-01me thy 1 pyridine
Ouinollne
3,4-Oimethylpyridln*
1,2,3,4-TetrimetftylpyHdlnt
Toluidine
2, 4, 5-Tr i me thy 1 py r 1 <11 rw
2,4,6-Trimetny 1 pyH d1 ne
I
498
-------
TABLE E-4 (Continued)
Pr»j*nt In
Known
Present i.i ( Known
Gasification
Carcinogen
Gasification ; Carcinogen
Sailing *iint » 200": :S0":
I c jiic ' d:
iuifur-cantaintng Comcojnas;
Dlallylsulfld*
01m*thy lbanzoth ioohen*
Hatfiylbenzo thiopnane
2,3-3*nzottnopn«fl«
Soiling Point « 250*C to 30Q'C
Aromatic Hydrocarbons:
3,4' -01m* thy 1 <11 pneny!
4,4' -01m* thy Idipheny 1
01phtny i
2-M*thyld1ph«iyl
3-M*thy I di prtany I
4-Methy Id1pn«nyl
Polynuclear Aromatic Hydrocirtwis:
Acenaphthylen*
Actnaphthan*
1.2-CycloptntanonaohthaUtw
1.2-01m*thylnaphthaI an*
1.3-Oimtthy (naphthalan*
1.5-01»»tftyInapn tna1«n«
1.6-31n* thy I naphthalan*
1.7-01 rat tftylMphtta I en*
2,6>QlMtny 1 naohtna 1 an*
2,7-01n*thy 1 naphthalan*
Z.J-OliMthy 1 nioft tta !*n*
1-lthylnaphthalen*
2-gtrtytnaphthalan*
F1uor*n«
Oxygtn-contifnfng CwooiuidJ:
01ph*ny!*fl* oxid*
1-M*tftyl4<9h*nyl*n* <3xiaa
1-Xaptithofuran*
2-NapnMofuran*
a-Maphtnol
j-Mapntnol
fUsortinol
30 3 1
rr— - -
plir; ' .3 306"e
JT
Hi tro9an-coni.1w1.ny wO.xpounas:
1,3-Oimcny I iscquinolin*
2,3-01methyl quinoi in«
5,3-01m*thylquinolIne
Indot*
2-Hetnyl InCole
3-Methy I indo le
4-Methy1indo1e
5-*»tfiy! i ndo 1 e
7-tie thy I indo ie
1 -*« thy li soom no 11 ne
3-Kethylisoquinolin*
3-MethyIqui noI in*
4-M*chylquinol1n*
5-Metnytquinolin*
S-Matny lquinol in*
7-M*thylquinolin*
1-Naphthoni tn 1*
Soiling faint > 300*C
Aliphatic Hydrocartcns:
r»-H»pud»cana
tanadacan*
Polynuclear Aromattc rtydrocaroons
Anthractn*
1.2-8*nianttiractn«
2.3-8eftzchrys«nt
3.4-8anzf'uorena
SatuO* ,n ,o ]f 1 uorantlien*
2, J-3*n zfl uo rs n than*
1,4-a«nif 1 uor an then*
7,3-3anif 1uoran than*
8,9-8*nzfluorjncnsn*
1,2-8anif1uqrent
2,3«8enzf1uor*n*
1,Z-«anzj»aphthacen*
1,2-8*nzoanthracene
1,2-8
-------
TABLE E-4 (Continued)
Present in
Gasi ficatlcn
Known
Carcinogen
Present 1n
Gasi 'ication
Kaomi%
Carci neqen
, Polynuclaar Aromatic Hydrocarbons
j (cont'd)
j ! ,12-3enzperylen«
j 3,4-3enzpnenantJirene
i ' ,2-3enzpicene
j ! ,2-3enz:iyrene
I 1,2-3enzpyr«ne
I CJirysane
| Coronene
i ; ,2,3,4-Qibenzanthracene
j 1,2,5,5-Gibenzanthracene
! 1,2,7,3-Oibenzant.lracene
j 1,2, S, 7'01 bempyrtn
! 1,2,7,3-Oibenzoyr»ne
! 3,4,3,9-Gibenzpyrene
I 3,4,9, ;0-0ib«.upyr«ne
3,4,3.9-0 i ben zte trapnene
9,I0-0i>ydPoanWracen«
5,! 2 - Oi hy d rona pn thacent
9,10-OlmtthyIpfunantftrww
2,3-0im«thyI anthracene
2.7-0 i methy I an thracene
J,6-0 :sc»-
•::nt'd;
Polynuclear Aromatic Hydrocarbon
(cont'd)
Haphthactne
Napftthofluorerie
Naphtho-2' .3'-1,2-anthracene
Psry lene
Phenanthrene
4,S-P>ienanthr/tene nethane
2.3-
-------
TABLE E-4 (Concluded)
!
Pr*se«t tn !
Known |
Present in j
i
Gasification
Carcinogen
Gasification !
Car-.;n;qen
:'..v' > 3C0":
3oi1lno Point: > 200'C i i
(cont'd)
(cont'd)
Oxygen-containing Compounds
Nitrogen-containing Compounds
(cont'd)
(cont'd)
peH-Naoh thoxan thene
2-Methylcarbazole
azole
Methylthiophene
2,3-3enZf1uoreneni tri 1 e
Te trahydroben zo th i oonene
5,S-3«nzquinolint
Naphthobenzotnioonene
7,3-3enzou1noline
Caroazol*
I,2,5,S-01benzacr1d1ne
i
l.Z.7.S-01benzacHdine
X
9,10-01hydroacridine
F?uorene nitriIts
NydroacHdin#
Indeno(l ,2,3-c, (mi noohenan ttiren*
2-Methylacridine
2-Methy1«5,6-benzqu1nole
501
-------
TABLE E-5
INDEX OF INDIVIDUAL TAR ACIDS FROM LOW-TEMPERATURE
BITUMINOUS TAR BASED ON BOILING RANGE
Compound
Boiling Range, "C*2
Phenol
182
2-Methylphenol
190.3
2,6-Dimethyl phenol
201
4-Methylphenol
202.1
3-Methylphenol
202.2
2-Ethylphenol
207
2,4-Dimethylphenol
210
2,5-Dimethy1 phenol
210
2-Ethyl-6-methylphenol
212-214
3-Ethylphenol
214
2-Isopropylphenol
214
2-Ethy1-4-methylphenol
216-218
2,3-0imethylphenol
218
4-Ethyl phenol
219
3,5-0imethylphenol
219.5
2,3,6-Trimethyl phenol
220
2-n-Propylphenol
220
4-Ethy1-2-methyl phenol
222
2,4,6-Trimethy1 phenol
222
5-Ethyl-2-methylphenol
223
2-Ethyl-5-methylphenol
224.2
3,4-0imethylphenol
225
3-Ethyl-2-methylphenol
227
2,4-Dimethy1-6-ethy1 phenol
227-228
3-n-Propylphenol
228
3-Isopropylphenol
228
2-Isopropyl-3-methylphenol
228.5
2-Isopropy1-4-methylphenol
228-229/763
4-Isopropylphenol
228-229/745
4—Ethyl-3-methylphenol
2-(Propen-1-y 1)phenol
228-230
230-231
2,4,5-T ri tne thy 1 phenol
232
4-n-Propylphenol
232.6
2-Methyl-6-n-propylphenol
233
3-£thyl-5-methylphenol
233
2,3,5-Trimethylphenol
233
All temperatures are measured at atmospheric pressure unless followed by
a slash (/). The number to the right of the slash is the pressure at
which the boiling ranges were obtained, In mm. Figures in parentheses are
atmospheric boiling points estimated from reduced pressure data or from
boiling-point data of isomers and homologues, in urn.
SOURCE: En.vi.ro Control, Inc. 1978*
502
-------
TABLE E-5 (Continued)
Compound
Boiling Range, "C*2
2-IsoDropyl-5-methylphenol
233.5
4-Isopropyl-2-methylphenol
230-235
3-Ethyl-4-methylphenol
234-235
2,3,4-Trimethylphenol
235-237
5-Isopropyl-2-methylphenol
236.8-237.4
4-Isopropy1-3-methylphenol
238
2,3-0imethyl-6-ethy1pheno1
(240)166/100
4-Methyl-2-n-propylphenol
(241)121-123/18
3-Isopropyl-5-methylphenol
241
4-Indanol
245/764
Catechol
245
2,3,5,6-Tetramethylphenol
247-248
3,5-Diethylphenol
248
3-Methylcatechol
248
3,4,5-Trimethyl phenol
248-249
3,5-0imethyl-2-ethy1phenol
(250)90-93/1
3,4-0imethyl-5-ethylphenol
(250)
6-Methyl-4-indanol
(250)
7-Methyl-4-indanol
(250)
2,3,4,6-Tetramethylphenol
250
S-Indanol
255
2,6-D1-n-propylphenol
256/764
4-Methyl catechol
258
3,5-Oimethyl-2(propen-T-yl)phenol
(260)
7-Methyl-5-indanol
(260)
2,3,4,5-Tetramethylpnenol
260
5,6,7,8-Tetrahydro-l-naphthol
264.5-265/705
2-Ethylresorcinol
(265)
Pentamethy1 phenol
267
4-Ethylresorcinol
(270)131/15
2-(Cyclopenten-2-yl)phenol
(270)133-135/12
2-(Cyc1openten-l-y1)phenol
(272)
2-Phenylphenol
275
5,6,7,8-Tetrahydro-2-naphthol
275-276
4-Methy1-5,6,7,8-tetrahydro-1 -naphtho1
(280)
4-Methyl-2-phenylphenol
(280)101-105/2
2-Cyclohexylphenol
282.5-283.5
2-(Cyclopenten-2-yl)-4-methy1 phenol
(284 105-108/1.3
2-Ethylhydroquinone
(285)
1-Naphtho1
288.01
3-Methyl-5,6,7,8-tetrahydro-2-naph thol
(290)
4-Methyl-3,6,7,8-tetrahydro-2-naphthol
(290)
4-(Cyclopenten-l-yl)phenol
(293)
4-(Cyclopenten-2-yl)phenol
(293)114-117/1.5
2-Naphthol
294.85
503
-------
TABLE E-5 (Concluded)
Compound Boiling Range, "C*2
2-Methyl-l-naphthol (295)
4-Cyclohexylphenol 293.5-295.5/752
4-Methyl-1-naphthal (298)177-179/25
1 Methyl-2-naphthof (300)
1,4-Dimethyl-5,6,7,8-tetrahydro-2-naphthol (305)
5-Methyl-2-naphthol (305)
3,4-0imethyl-l-naphthol (315)205-210/15
4-Phenylphenol 319
7-Ethy1-4-methyl-l-naphthol (320)
3-Phenylphenol 325
5-Acenaphthenol (332)221/40
4-Acenaphthenol (338)
1-Fluorenol (345)
2-Fluorenol 340-350
3-Fluorenol (350)
8-Methyl-2-fluorenol (355)
504
-------
TABLE E-6
INDEX OF INDIVIDUAL TAR BASES FROM LOW-TEMPERATURE
BITUMINOUS TAR BASED ON BOILING RANGE
Compound
Boiling Range, 9Za
? di r,
2-Mecr.y icyHci
" -i
123i42
2,6-Dimethylpyridine
144.05
3-Methyl pyridine"
144.14
4-Methyl pyri dirre
145.0
2-Ethylpyridine
148.6
2,5-0i me thy"! pyridine
157.01
2,4-Qimethylpyridi ne
158.40
2-Isopropylpyridine
158.9
2,3-Dimethy]pyridine
161.16
2-Ethyl-6-methylpyridine
160-161.5
3-Ethylpyridine
162-165/762
2,4,5-Trimethylpyridine
165-168
4-Ethyl pyridine
169.6-170/750
3,5-Dimethyl pyridine
171.91.
2,4,6-Trimethyl pyridine
171-172
4-Isopropylpyridine
173
5-Ethyl-2-methylpyri di ne
174-176
2,3,5-Trimethyl pyridine
176-178/759
3-Isopropylpyridine
177-178
3,4-Qimethy1pyri di ne
179.13
4-Ethyl-2-methylpyri di ne
179-180
2,4-Dimethyl-5-ethy1pyri di ne
181-182
2,3,5-Trimethylpyridine
182-183/739
Ani1i ne
183.93
2,6-Oimethyl-4-ethylpyridine
186
2,4-0iethyl pyridine
187-188
2,3,4-Tri methyl pyri di ne
192-193
N,N-Oimethylaniline
192.5-193.5
3-Ethyl -4-Methylpyridine
195-196/753
N-Methyl ani ne
196.1
2,3,5,6-Tetramethy1pyri di ne
197-198
2,3-Cyclopentenopyri di ne
199.5
2-Methy1 aniline
200.3
4-Methylaniline
200.55
2,3,4,6-Tetramethylpyridine
203/750
3-Methylaniline
203.34
*A11 temperatures are measured at atmospheric pressure unless followed by a
slash (/).• The number to the right of the slash is the pressure at which
the boiling ranges were obtained, ln irm. Figures in parentheses are
atmospheric boiling points estimated from reduced pressure data or from,
boiling-point data of isomers and homologues, in irm.
SOURCE: Enviro Control, Inc. 1978;
505
-------
TABLE E-6 (Continued)
Compound
Soil-ine ^ance, 'Z2
N-Methyl-2-methy! ani 1 ine
207-202
N-Metnyl -4-metny1ani 1 i r.e
209-211/761 j
2,5-Dimethylaniline
213.5
2,6-Dimethylani1ine
214/739
2-Ethy1 aniline
215-216/759
2,4-Dimethylani1ine
215.3-216.G/723
3,5-Qircethylaniline
220-221 1
5,6,7,S-Tetrahydroqui no 1i ne
222.2 i
3,4-Dimethylaniline
226 i
Qui no!ine
237.1 !
2-Methylquinoline
245.8
8-Methylquinoline
247.3-248/751.3 !
2,8-Dimethylquinoline
252
3-Methylquinoline
252/735 !
I 7-Methylquinoline
251.5252.5
1 5-Mathylquinoline
253-255/735
1 6-Methylquinoline
257.4-258/745 i
2,3-Qimethylquinoline
261/730
4-Methylquinoline
264.2
2,4-Oimethylquinoline
264-265
2,7-Qimethylquinoline
264-265
2,6-Dimethylquinoline
266-267
2,6,8-Trimethylquinoline
267.4/746
2-Phenylpyridine
268-269
3-Phenyl pyridine
269-270/749 >f
2,5,8-Trimethylquinoline
(273)143-145/15 !
4,6-Oimethyl qui no!ine
273-274
4-Phenyl pyridine
274-275 |
2,4,8-Trimethylquinoline
275.8/740 |
2,7,8-Trimethylquinoline
276.1/740 !
2,3,8-Trimethylquinoline
280/747 J
2,4,7-Trimethylquinoline
280-281 i
2,5,7-Trimethylquinoline
286.6/746 !
2,4,6-Trimethylquinoline
287/758 !
2-Naph thy Taurine
294
2,4,7,8-Tetramethy1qui no 1i ne
295.5/742
1-Naphthy1 amine
300.3
2,4,5,8-Tetramethylquinoline
(310)168-172/12
N-8enzy1-2-methylaniline
(310)176/10
N-3enzy1-3-methylaniline
312
N-8enzyl-4-metny1ani1i ne
312-313
7,8-8enzoquinoline
335
6,7-Benzoquinoline
(345)200-205/14
2,3-Benzoquinoline
345-346
506
-------
TABLE E-6 (Concluded)
Ccnpcund
Selling Ranee, 3T
3,4-Benzoquino"!ine
349/759
5,6-8enzoquinoline
350/721
2,4-0imethyl benzo(?:)auino1 ine
355
1,3-Dimethylbenzol(/)quinoline
(358)240/35
9-Methylacridine
359-360/740
2-Methyl benzoyl qui no 1 ine
(360)
4-Methylbenzo(j)quinol ine
(360)
2,3-0imethy1benzo(/)quinoline
(360)
2,4-Dimethylbenzo
-------
Appendix F
Other Committee Reports
-------
8 August 1979
REPORTS OF THE FEDERAL INTERAGENCY COMUTTEE ON
THE HEALTH AND ENVIRONMENTAL EFFECTS OF ENERGY TECHNOLOGIES
REPORT NUMBER
TITLE
NTIS REPORT NUMBER
NTIS PAPER COPY COST
(at. timp of submission)
OOE/HEW/EPA-Ol
DOE/HEW/EPA-02
D0E/HEW/EPA-03
D0E/HEW/EPA-04
Health and Environmental Effects of
Coal Gasification and Liquefaction
Technologies: Background Material
for a Workshop.
Health and Environmental Effects of
Oil Shale Technology: A Workshop
Summary and Panel Reports
Health and Environmental Effects of
Coal Gasification and Liquefaction
Technologies: A Workshop Summary
and Panel Reports
Health and Environmental Effects of
Coal Technologies: Background
Information on Processes and Pollutants
PB 296 708
PB 297 096
PB 297 618
$10.75
$10.75
$12.50
To be submitted during August 1979
These and other reports of the Federal Interagency Committee on the Health and Environmental
Effects of Energy Technologies will be available from the National Technical Information Service
(NTIS), U. S. Department of Commerce, 5285 Port Royal, Springfield, VA 22161.
-------
|