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2
Coal Combustion Residues
T his chapter provides an overview of the basics of CCRs, including their
production, characteristics, and disposal and use options (see Figure 2.1).
It then examines how CCRs are generated, including the combustion
technologies used and the pollution control equipment utilized, which contribute
to the type, quantity, and characteristics of CCRs generated. Finally, it considers
the possible options for CCR management, which include disposal in landfills or
surface impoundments, use of the CCR as a component of an engineered product,
or use or disposal in a coal mine. Although placement of CCRs in coal mines is
the focus of this report, a brief presentation of the alternatives to mine placement
is included in this report to illustrate the available CCR management alternatives.
TYPES OF COAL COMBUSTION RESIDUES
Coal does not completely convert to a gas upon combustion; therefore, all
coal-fired boilers produce solid materials in the form of CCRs. The amount of
CCRs produced by utilities has increased as the demand for energy in the United
States has grown.
A variety of solid materials may be generated from the combustion of coal,
including fly ash, bottom ash, boiler slag, and residues from air pollution control
technologies, such as flue gas desulfurization (FGD) materials (Figure 2.1). Fly
ash represents a major component (62 percent) of CCRs, followed by FGD mate-
rial (19 percent), and bottom ash and boiler slag (18 percent) (USDOE, EIA,
2003b). The major types of CCRs are described in detail below. An overview of
common coal combustion technologies is provided in Sidebar 2.1.
27
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28
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COAL COMBUSTION RESIDUES 29
SIDEBAR 2.1
Technologies for Coal Combustion
Many industrial and utility boilers use coal as the primary source of fuel. The
boiler is the unit that encloses the furnace, where the fuel is combusted. When coal
is fed into the furnace, the heat generated is used to heat water circulating in tubes
surrounding the furnace. As the water heats, it turns to steam. The steam is cap-
tured and used within the facility to turn the blades of an electricity generator or a
compressor for refrigeration, to heat a process or a building, or for many other
uses.
There are three primary coal combustion technologies used in boilers:
1. Grate firing, where coal is combusted while residing on a grate within the
furnace;
2. Suspension firing (e.g., pulverized coal (PC) firing), where coal is
crushed to a fine powder prior to entering the boiler's furnace and subsequently
combusted in suspension with the combustion air; and
3. Fluidized bed combustion (FBC), where coal is combusted in a sus-
pension with a solid sorbent (usually limestone) or an inert material such as sand
(Davis, 2000).
Utility boilers generate steam to drive turbine generators for the production of
electricity. Utility boilers are commonly suspension-fired boilers, such as pulver-
ized-coal boilers. The coal-refuse-fired facilities generally use FBC technology.
Fly Ash
Fly ash consists of fine particles carried out of the boiler by the flue gases.
Most fly ash is captured by dust-collecting systems before it escapes the boiler's
stack. Common particulate matter control devices include mechanical collectors,
electrostatic precipitators, and fabric filters (Sidebar 2.2). Other constituents
mobilized in the coal combustion process may be associated with fly ash. For
example, mercury tends to adsorb to fly ash unless another material, such as
activated carbon, is added to the flue gas to capture the mercury preferentially.
Bottom Ash and Boiler Slag
Bottom ash typically consists of large ash particles that accumulate at the
bottom of the boiler. Boiler slag is a molten inorganic material that is collected at
the bottom of the boiler and discharged into a water-filled pit, where it is cooled
with water (quenched) and removed as glassy particles resembling sand. The
form of the ash or slag produced is dependent on the type of furnace and the
fusion temperature (or melting point) of the ash generated from the coal. Some
pulverized coal (PC) furnaces (see Sidebar 2.1) fire coals of high ash-fusion
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30 MANAGING COAL COMBUSTION RESIDUES IN MINES
SIDEBAR 2.2
Particulate Matter Control Devices
There are three common particulate matter control devices used with coal-fired
furnaces, described below.
Mechanical Collectors, most commonly known as cyclones or multicyclones,
force a cyclonic flow of the exit gas. This flow causes ash particles to be thrown
against the walls of the collector and to drop out of the gas. Cyclones are most
effective for larger particles; collection efficiency drops well below 90 percent for
the smallest particles.
Electrostatic Precipitators (ESPs) are the most common particulate control
technology used by coal-fired utilities. An ESP generates a high-intensity electrical
field that causes ash particles to acquire an electrical charge and migrate to an
oppositely charged collection surface. For typical coal-fired utilities, this process
results in a collection efficiency of greater than 99 percent.
Fabric Filters, also known as baghouses, capture ash as the exit gas passes
through a series of porous filter bags. Baghouses have an efficiency of greater
than 99 percent.
SOURCE: USEPA, 1999b.
temperatures and use a dry ash removal technique (Davis, 2000). Others fire coal
with a low ash-fusion temperature causing much of the ash to form a liquid slag,
which is then drained from the bottom. Boiler slag is a CCR that is expected to be
produced in diminished quantities in the future because of the retirement of the
older boilers that produce liquid slag in significant quantities.
Residues from Air Pollution Control Technologies
Several air pollution control regulations have been enacted to improve air
quality in the United States. To implement these regulations, many coal-fired
plants use pollution control devices, in addition to particulate matter controls,
which can generate their own type of residue or change the characteristics of
existing residues. The characteristics of the residue generated are dependent on
the type of pollution control equipment installed, which varies widely between
plants (and even between units at the same plant) depending on space constraints,
compatibility with existing equipment, and regulatory performance requirements.
Sulfur Dioxide Emissions Control Technology
Sulfur dioxide (SO2) emissions controls are the most common devices added
to augment the control of particulate matter. SO2 is a component of fine airborne
particulate matter in the form of aerosols and is the primary component of acid
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COAL COMBUSTION RESIDUES 31
SIDEBAR 2.3
Desulfurization Technologies
Post-combustion desulfurization technologies (or SO2 scrubbers) are catego-
rized as recovery systems and non-recovery systems. Recovery systems are those
that produce FGD wastes that are suitable for use in engineered products, such as
wallboard. Non-recovery systems produce FGD waste that must be disposed of.
Non-recovery systems are further classified as wet and dry systems. Wet systems
scrub and saturate flue gas with a slurry of water and a sorbent (usually lime or
limestone) that reacts to remove sulfur from the gas in the form of a sludge. Dry
systems typically contact flue gas with a sorbent slurry in a spray dryer without
saturating the gas with water. The dry reaction product is then collected along with
fly ash in a fabric filter or ESP. Wet systems are more effective at removing sulfur
dioxide and, therefore, are used by a larger proportion of generators. However,
because of their use of liquids, wet systems produce more waste than do dry
systems (USEPA, 1999b).
Desufurization can also be accomplished within the coal combustion process
itself. In systems utilizing FBC technology, desulfurization can be accomplished by
co-firing the coal with limestone. The limestone then serves a dual purpose: a bed
material for the furnace and an SO2 sorbent (Woodruff et al., 1998).
rain. Units that remove SO2 emissions from flue gas are referred to as flue gas
desulfurization (FGD) systems (see Sidebar 2.3). Since the implementation of the
Clean Air Act's Acid Rain Program (40 CFR 72-75) in 1990, FGD technologies
have added a significant non-ash component to CCRs (Figure 2.2). In 2005, the
Environmental Protection Agency enacted the Clean Air Interstate Rule (70 FR
25162) establishing a new emission reduction program for SO2 and NOx (nitro-
gen oxide) generating reductions of these pollutants in 28 states and the District
of Columbia. The Clean Air Interstate Rule incorporates and goes beyond the
existing Clean Air Act Acid Rain Program and may lead to more FGD materials
being produced or to a new material produced by the introduction of new tech-
nologies.
Nitrogen Oxide Emissions Control Technology
There are several types of NOx emissions control technologies. The simplest
is called a low NOx burner, which reduces the formation of NOx by controlling
the environment in which the coal combusts (flame temperature and chemical
environment). Selective Catalytic Reduction and Selective Non-Catalytic Reduc-
tion are post-combustion control technologies used for NOx emission reduction.
These processes utilize ammonia reacted with the flue gas to convert it to elemen-
tal nitrogen and water (CURC, 2005). These processes may increase the ammo-
nia content of CCRs making them less marketable (Butalia and Wolfe, 2000).
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32 MANAGING COAL COMBUSTION RESIDUES IN MINES
140
(Millions)70
Tons
0
1966 1970 1980 1990 2003
Fly Ash Bottom Ash Boiler Slag Flue Gas Desulfurization
FIGURE 2.2 Generation of fly ash, bottom ash, boiler slag, and FGD by utilities (1966-
2003).
NOTE: This figure does not include the approximately 5 million short tons of CCR
produced by independent power producers firing coal refuse.
SOURCE: American Coal Ash Association, Aurora, CO, written communication, Octo-
ber 2005. Courtesy of the American Coal Ash Association.
Mercury Emissions Controls Technology
The implementation of the Clean Air Mercury Rule in 2005 (70 FR 28606) is
expected to increase the use of mercury control technologies. The Clean Air Mer-
cury Rule is intended to reduce nationwide utility emissions of mercury by creating
a market-based cap-and-trade program occurring in two distinct phases. The first-
phase cap of 38 tons will likely be achieved by taking advantage of "co-benefit"
reductions--mercury reductions achieved by reducing SO2 and NOx emissions
under the Clean Air Act Amendments and the Clean Air Interstate Rule. The
second phase, due in 2018, caps coal-fired power plant emissions at 15 tons and
will likely necessitate installation of controls specific to mercury capture.
Some of these technologies, such as activated carbon injection, will result
in a separate waste stream, but it is also possible that emerging technologies
may simply change the characteristics of existing CCRs by increasing their
mercury content. The characteristics and potential environmental impact of
residues generated from mercury control is currently being studied by the EPA's
National Risk Management Research Laboratory. Preliminary studies indicate
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COAL COMBUSTION RESIDUES 33
that leaching of mercury from activated carbon injection materials may not be
of concern. Preliminary results of Heebink et al. (2004) show that leachate
mercury concentrations were low, regardless of the concentration of mercury in
the original sample. All concentrations were below the primary drinking water
standard of 2 ”g/L. Early results from studies of mercury leachates from FGD
associated with mercury controls, however, show that there is potential for
undesirable release of mercury into the environment from this type of CCR
(Thorneloe, 2005).
PHYSICAL AND CHEMICAL CHARACTERISTICS OF
COAL COMBUSTION RESIDUES
The chemical and physical characteristics of CCRs vary widely. For ex-
ample, a dry scrubber FGD material may contain a relatively low concentration
of metals, but a high concentration of sulfur compounds. Alternatively, a fly ash
collected with a baghouse after being treated with activated carbon may have a
relatively high concentration of mercury as well as carbon. This section describes
the factors influencing the characteristics of CCRs and presents information on
the physical and chemical characteristics of various CCRs.
Factors Influencing the Characteristics of Coal Combustion Residues
There are several factors that influence the physical and chemical character-
istics of the CCRs produced, including
1. Chemical characteristics of the source coal,
2. Chemical characteristics of any co-fired materials,
3. Combustion technology,
4. Pollution control technology used by the CCR producing facility, and
5. Residue handling technology used by the CCR producing facility.
Source Coal
Because CCRs largely represent the noncombustible constituents in coal,
their characteristics are strongly influenced by the source coal itself. As described
in Chapter 1, coal is comprised of carbonaceous materials and a complex mixture
of various minerals. Both the major and the minor mineral constituents of coal
contain metals and other elements that could be of concern if they were released
in the environment in the proximity of sensitive receptors (Schweinfurth, 2003).
Both the form and the concentrations of these trace elements vary with coal type
(e.g., lignite, bituminous) and coal region. The United States Geological Survey
(USGS) maintains an extensive database of coal quality characteristics of the
major coal basins throughout the United States (Bragg et al., 2005).
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34 MANAGING COAL COMBUSTION RESIDUES IN MINES
Co-Fired Materials
Some facilities co-fire coal with other fuels such as wood, biomass, plastics,
petroleum coke, tire-derived fuel, refuse-derived fuel, and peat or manufactured
gas plant wastes. Fifty-nine percent of non-utilities, encompassing industrial,
commercial, and institutional facilities, co-combust other fuels with coal (e.g.,
oil, gas, wood chips; Carrell, 2002). Co-firing coal with other materials can result
in a variety of chemical constituents in the final CCR. In its 1999 report to
Congress, the EPA examined data provided by the Electric Power Research
Institute regarding the residues generated from these co-fired fuels and deter-
mined that there was a potential for some of the mixtures to contain elevated
levels of metals in the bulk material. The organic chemical constituent composi-
tion of the CCRs generated from co-fired fuels was generally below detection
limits (USEPA, 1999a). Other facilities, such as the independent power produc-
ers in Pennsylvania, utilize fluidized bed combustion (FBC) boilers and co-fire
coal refuse with limestone, resulting in a highly alkaline CCR.
Combustion Technology
The effects of combustion technology on the characteristics of CCRs vary
based on the source coal and the operating conditions. However, different technolo-
gies (Sidebar 2.1), especially FBC, can have an effect on the ash characteristics.
Generally, given the same source coal and operating conditions, an FBC boiler will
yield CCRs with a higher calcium concentration (as an oxide or sulfate) and lower
silicon dioxide and aluminum oxide concentrations than a suspension-fired com-
bustion boiler due to the addition of limestone during combustion (Sellakumar et
al., 1999). Fluidized bed combustion also operates at a lower combustion tempera-
ture than PC combustion technology, resulting in different mineral transformations
in the ash (discussed in more detail later in this chapter).
Several utility-scale technologies are emerging in the commercial market to
allow the combustion of coal without the addition of post-combustion pollution
controls, including integrated gasification combined cycle (IGCC) and pressur-
ized fluidized bed combustion (PFBC). These emerging technologies have low
air emissions relative to conventional coal-firing technologies and may also al-
low for capture of CO2 from the exhaust gases (Booras and Holt, 2004). Today,
the use of these technologies is minor relative to the use of standard combustion
technologies; however, they hold promise for expanded use in the future. Re-
search has shown that the characteristics of CCRs from IGCC differ markedly
from those from traditional combustion technologies. Specifically, IGCC pro-
duces primarily slag, elemental sulfur, and sulfuric acid, all of which may hold
economic value as salable by-products (Shilling and Lee, 2003). However, addi-
tional processing may be needed to remove excess carbon in IGCC slag, before it
can be used in cement (Ratafia-Brown et al., 2002).
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COAL COMBUSTION RESIDUES 35
Pollution Control Technology
As mentioned earlier in this chapter, air emissions control technology has the
potential to affect the characteristics of an exiting CCR stream. It may improve or
diminish the marketability of CCRs for productive uses, and it may change the
profile of the toxic constituents of the CCRs. For example, NOx emission controls
by themselves do not cause the production of a solid residual stream, but their use
may lead to high ammonia content in the resulting fly ash, thereby changing the
opportunities for utilization as opposed to disposal (Rathbone and Robl, 2002).
For this reason, regulatory agencies responsible for imposing pollution control
standards should carefully consider the implications of air pollution control re-
quirements for the marketability of CCRs to ensure that the full suite of environ-
mental consequences is analyzed and understood.
Residue Handling Technology
Residue collection systems from the boiler and its auxiliaries vary between
facilities and from unit to unit. Some units use a collection system that results in a
combined residual in either a dry or a wet form. The type of materials that may be
combined prior to leaving a plant is a function of individual plant collection logis-
tics and/or any requirements to facilitate final disposal. Because residues are being
produced constantly during the combustion process and must be removed regu-
larly, facilities usually have a storage system such as a silo for dry materials or a
surface impoundment (pond) for wet materials. Whether a CCR is in a wet or dry
form and whether several CCR streams have been commingled are important fac-
tors in the management opportunities that may be available to the CCR generator.
Physical and Chemical Characteristics
Understanding the physical and chemical properties of CCRs is important
because these properties influence the opportunities for CCR use and disposal
and affect the leachability of contaminants from CCRs. The physical and chemi-
cal properties discussed include mineralogy, grain size, bulk chemical content,
trace element content, organic chemical content, and radioactive content.
Mineralogy
The mineralogical characteristics of CCRs reflect the source coal, the com-
bustion process itself, and any pollution control technologies used. Pulverized
coal combustion occurs at high temperature (typically above 1400șC) and there-
fore causes significant transformations of the inorganic minerals in coal (e.g.,
clay minerals, carbonates, sulfides, quartz) (Kim, 2002a). At such temperatures,
minerals may decompose or oxidize (Clarke and Sloss, 1992). Amorphous alumi-
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36 MANAGING COAL COMBUSTION RESIDUES IN MINES
nosilicate glass typically represents more than 60 percent of the mineral mass in
PC fly ash (Hower et al., 1997; McCarthy et al., 1999). Other major mineral
phases in PC fly ashes may include mullite (Al6Si2O13), quartz (SiO2), lime
(CaO), anhydrite (CaSO4), periclase (MgO), hematite (Fe2O3), magnetite (Fe3O4),
and tricalcium aluminate (Ca3Al2O6). Coal combustion residues containing sub-
stantial quantities of lime will have high levels of alkalinity, because lime forms
a strong base, Ca(OH)2, upon reaction with water. The lower temperature of the
FBC process (approximately 800șC), combined with the added limestone pro-
duces different assemblage of minerals in the fly ash and bottom ash. The pri-
mary minerals in FBC ash are anhydrite, lime, iron oxides, and quartz. Flue gas
desulfurization residues consist primarily of gypsum (CaSO42H2O) and calcium
sulfite hemihydrate (CaSO30.5H2O) (Tishmack, 1996).
Grain Size
The grain size of CCRs is related to where the residues are collected (e.g., fly
ash versus bottom ash). Both PC and FBC fly ash are fine grained, with a mean
particle size of approximately 20-30 mm (Chugh et al., 2000). Pulverized coal fly
ash particles tend to melt at high combustion temperatures and condense as
spheres, resulting in relatively low surface area for this small grain size (0.7 to 37
m2/g) (Nagataki et al., 1995), while FBC fly ashes maintain a more irregular
shape (Figure 2.3). The FGD residues are also fine grained, with a mean particle
size of 20-40 ”m (Tishmack, 1996). Boiler slag particles are typically the size of
fine gravel to coarse sand with 90 to 100 percent passing a 4.75 mm sieve, 40 to
60 percent passing a 2.0 mm sieve, and 10 percent or less passing a 0.42 mm
FIGURE 2.3. Scanning electron microscopy images of (left) pulverized coal fly ash and
(right) fluidized bed combustion fly ash.
SOURCE: Chugh et al., 2000.
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COAL COMBUSTION RESIDUES 37
TABLE 2.1 Typical Bulk Chemical Compositions of PC and FBC Fly Ash,
FBC Bed Material, and FGD Scrubber Sludge
FBC FGD Scrubber
PC Fly Ash FBC Fly Ash Bed Material Sludge
(% by wt) (% by wt) (% by wt) (% by wt)
SiO2 55.90 22.10 09.7 00.45
Al2O3 15.40 06.80 03.69 BDL
Fe2O3 16.10 06.67 02.16 BDL
SO3 01.15 15.67 24.42 58.73
CaO 05.06 38.70 53.10 041.0
MgO 00.78 01.29 00.88 BDL
Total Na2O 01.48 00.50 00.16 BDL
Total K2O 01.93 01.12 00.39 00.02
Loss on ignition 00.58 05.46 00.80 00.00
NOTE: These data reflect the weight percent of major elements as oxides; they do not describe the
actual mineralogy in the CCRs. BDL= below detection limit.
SOURCE: Chugh et al., 1998.
sieve. Bottom ash is predominantly sand sized, although bottom ash particles
range in size from a fine gravel to a fine sand with very low percentages of silt-
clay-sized particles (usually with 50 to 90 percent passing a 4.75 mm sieve and
10 percent or less passing a 0.075 mm sieve) (Moulton, 1973).
Bulk Chemical Content
Typical bulk chemical compositions of several common CCRs are presented
in Table 2.1. Silicon, aluminum, and iron are major constituents in both PC and
FBC fly ash, while calcium content varies substantially with source coal type.
The FBC residues from bituminous coal combustion are typically higher in cal-
cium and sulfur than PC CCRs because of the co-combustion of limestone for
SO2 control in FBCs. The pH of CCRs is primarily a factor of the amount of
alkaline metal oxides (e.g., calcium oxide, magnesium oxide) present (Daniels et
al., 2002). Although many CCRs are alkaline, Furr et al. (1977) reported pH
values of 23 fly ashes across the United States ranging from 4.2 to 11.8. The
acidic fly ashes generally came from power plants burning bituminous coal ex-
tracted from southeastern or mid-Atlantic states.
Trace Element Content
The trace elements contained in CCRs are derived from naturally occurring
minerals present in the source coal. Non-volatile constituents (e.g., lead, cadmium)
tend to be concentrated in CCRs as a result of the combustion process. The extent
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48 MANAGING COAL COMBUSTION RESIDUES IN MINES
Boiler slag, when processed, also generates a material that can be used for sand-
blasting abrasives, which does not contain the free silica of sand, making it safer
for workers. The abrasive quality of many CCRs makes them suitable for use as
traction control materials on snow- and ice-covered roadways, and the dark color
of the materials aids in the absorption of radiant energy, which enhances the
melting process. A portion of fly ash, called cenospheres, can be used as a
performance enhancing product in paints, coatings, and adhesives.
Mine-Specific Disposal and Use Options
As the consumption of coal for electric power generation has increased, so
has the demand for disposal sites for CCRs. Although the recycling of various
CCRs into engineered products is the preferred alternative, conditions do not
always lend themselves to such a solution. In these cases, CCR disposal alterna-
tives are usually limited to surface impoundments, landfills, or placement in coal
mines where the CCRs are utilized in mine reclamation. The use of CCRs in mine
reclamation reduces other environmental impacts, such as disturbance of new
land areas required for landfilling such materials. Nevertheless, there is a poten-
tial for other impacts to occur, which are explored in later chapters.
Coal mines have a number of attributes that may support large volume place-
ment of CCR in mines. Among these features are the following:
· Existing Excavation. Surface coal mining creates large excavations that
often require bulk materials for proper reclamation. Minefilling requires no new
land disturbances, whereas there is often strong public opposition to the siting of
new surface impoundments or landfills.
· Infrastructure. Active mines generally have adequate existing infrastruc-
ture, equipment, and know-how for the economical handling and engineered
placement of bulk materials.
· Geology. Coal is generally contained in a sedimentary rock sequence that
includes low-permeability shales and clays (see Chapter 3). These materials may
impede groundwater flow, including potential contaminants that might be associ-
ated with such flow.
It should be emphasized that not all prospective coal mine disposal sites have all
of the favorable features noted above. As stressed throughout this report, each
site should be evaluated on its own merits. Furthermore, the existence of the
above beneficial features should not deter a full assessment of the potential
environmental risks of disposing of CCRs in any site. Final site selection in-
volves the due consideration of such risks, but it is appropriate also to include a
consideration of benefits in the selection process.
There are two different sources of the CCRs that are typically disposed of in
mines. The first is the conventional coal-fired power plant that consumes virgin
coal. The CCRs produced are typically hauled by truck back for disposal at the
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COAL COMBUSTION RESIDUES 49
mine (or mines) that supplied the original coal, which may be many miles from
and under different ownership than the power plant. The second major source of
CCRs used in mines is the independent power producer that uses coal refuse from
nearby abandoned mines (Sidebar 2.6). The refuse material typically has poor
SIDEBAR 2.6
Pennsylvania's Program for Coal Mine Reclamation and
Mine Drainage Remediation
Pennsylvania's coal miners have extracted approximately 16.3 billion short tons
of anthracite and bituminous coal from the state's mines since commercial mining
began in 1800. While mines permitted under the Surface Mining Control and Rec-
lamation Act (SMCRA) are required to be reclaimed after the coal is extracted,
many pre-SMCRA mines were abandoned prior to reclamation. In Pennsylvania,
there are more than 5,000 abandoned, unreclaimed mining areas covering ap-
proximately 189,000 acres and more than 820 abandoned coal refuse piles. The
coal refuse piles cover 8,500 acres, contain a volume of more than 200 million
cubic yards of waste material, and can be substantial in size (see Figure 2.6).
It is estimated that the acid leached from the coal refuse in these abandoned
coal mines in Pennsylvania contributed to the degradation of more than 3,100
miles of streams. Pennsylvania's Bureau of Abandoned Mine Reclamation esti-
mates the cost to eliminate these abandoned mine problems to be $14.6 billion.
Pennsylvania receives an average of $30 million annually from the Office of Sur-
face Mining (OSM) Abandoned Mine Lands (AML) fund; at this rate, it would take
Pennsylvania nearly 500 years to complete the cleanup of its AML sites.
One approach that Pennsylvania has taken to its AML problem is encouraging
private funding for reclamation of abandoned coal refuse piles. The advent of FBC
technology in the late 1980s enabled the once-useless coal refuse to be used as
fuel. As of 2004, 15 independent power producers constructed plants near Penn-
sylvania's coal refuse piles, using the refuse as fuel for their FBC boilers. Between
1987 and 2002, these plants used 88 million short tons of coal refuse for the gen-
eration of electricity and process steam--energy that would otherwise have been
derived from another virgin fuel source. The FBC CCRs generated by coal refuse-
fired facilities are highly alkaline and have been used in mine reclamation and for
treatment of acid mine drainage in areas near the plant. For example, the Mount
Carmel co-generation plant consumed a total of 8 million short tons of coal refuse
from 1990 through 2002 and produced 5 million short tons of CCR for mine recla-
mation neighboring the plant during that period, reclaiming 209 acres.
The FBC plants' ability to use the coal refuse as fuel, coupled with the potential
to place the CCRs into nearby mines, makes the arrangement economically viable
and has enabled privately funded reclamation of 3,400 acres of AML as of 2002.
An example of this cost offset is the Big Gorilla Project (Sidebar 2.7), which was
reclaimed by the Northeastern Power Company (the independent power producer
operating the cogeneration plant at the site) at a total estimated cost of $3.4 mil-
lion. That reclamation cost is less than or approximately equal to the estimated
cost of conventional AML reclamation of the site with federal AML funds (National
Mining Association, Washington, D.C., written communication, July 2005 and April
2006).
SOURCE: PADEP, 2004.
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50 MANAGING COAL COMBUSTION RESIDUES IN MINES
FIGURE 2.6 Westwood FBC plant near Tremont in the southern anthracite field show-
ing a coal refuse pile by the plant.
NOTE: Photograph courtesy of Pennsylvania Department of Environmental Protection.
thermal qualities and a large waste rock content such that it can only be fired in
FBC boilers.
Over the last decade, traditional utilities have increased their utilization of
CCRs in mining applications. ACAA reports that CCR utilization in mines
(including minefilling) increased from approximately 1 percent in 1995 to about
1.9 percent in 2003 (ACAA, 1995, 2005a).2 The data currently available on
CCR use and disposal do not differentiate between the amount of CCRs being
used in engineered products outside of coal mines, the amount being used in coal
mines as minefill, and the amount being used in smaller engineering applica-
tions (e.g., road aggregate) within the mine area. In total, ACAA reports that 2.3
million short tons of CCRs were used in mining applications in 2003. However,
this total is known to be an underestimate of the use of CCRs in mines. In New
2 These numbers represent information obtained from ACAA's voluntary survey (Sidebar 2.5) and
therefore may not include all utilization of CCRs in mining applications.
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COAL COMBUSTION RESIDUES 51
SIDEBAR 2.7
The Big Gorilla Demonstration Project
The Big Gorilla pit was an abandoned anthracite surface mine located near
Hazelton, Pennsylvania, in the Silverbrook Basin. The pit was approximately 1,400
feet long by 400 feet wide and 90 feet deep. It was filled with about 120 million
gallons of water that had been significantly affected by acid mine drainage (see
Figure 2.7). The Silverbrook Basin is approximately five miles long and 1 mile
wide. It is drained by the Silverbrook outfall, which forms the headwaters of the
Little Schuylkill River.
The demonstration project involved the dry-to-wet placement of approximate-
ly three million tons of fluidized bed combustion (FBC) ash into standing mine
water. Placement began in August 1997 and was completed in 2004 (see Figure
2.8). The ash was dumped onto two working platforms by 45 ton trucks and then
dozed into the pool. As the mine pool was filled, compaction was accomplished
using the trucks and dozers. The ash came from Northeastern Power Company's
co-generation facility in McAdoo, Pennsylvania, which fires approximately 1,700
tons of coal refuse and 60 tons of limestone per day.
Five monitoring wells and three test boring locations have been monitored con-
tinuously. Numerous studies of the mineralogy of the ash and the evolution of the
pit lake water chemistry have been conducted. The project used approximately
three million tons of CCRs to eliminate the acidic mine pool. The results of the
demonstration project include a possible reduction in the acid loading of the Silver-
brook outfall, a decrease in concentrations of some metals, a slight increase in
concentrations of some cations, and a test of the dry-to-wet placement method.
SOURCE: Loop et al., 2004.
Mexico alone, the two largest coal mines together place approximately 2.5 mil-
lion short tons back into their mines annually (BHP Billiton, 2004). Although
Pennsylvania's coal refuse-fired facilities consume a significantly smaller quan-
tity of coal annually, they generate almost twice the amount of mine-placed
CCRs as compared to that reported by traditional utilities in the United States.
The placement of CCRs generated by coal refuse-fired facilities in Pennsylvania
for mine reclamation rose steadily from 89,000 short tons in 1988 to the almost
5 million short tons in 2002 and is expected to continue to increase as more
facilities are developed (PADEP, 2004).
Common Mine-Specific CCR Applications
There are a variety of disposal and use options for CCRs in mining opera-
tions. This section highlights the CCR applications that are unique to surface and
underground mines, such as minefilling, capping, mine sealing, and treating acid
mine drainage (AMD). Because knowledge of the methods and geometries of
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52 MANAGING COAL COMBUSTION RESIDUES IN MINES
FIGURE 2.7 Big Gorilla pit prior to 1995 showing the 120 million gallons of water that
had been significantly affected by acid mine drainage.
NOTE: Photograph courtesy of Barry Scheetz, Pennsylvania State University.
placement is needed to understand the behavior of CCRs in the environment
(discussed in Chapter 3), this section also describes methods for emplacing CCRs
in mines.
In surface mines, minefilling generally involves the placement of CCRs as a
monofill, a layered fill, or a blended mixture of coal refuse and CCR (Figure 2.9).
Surface mine placement of CCRs is part of the reclamation process, which in-
volves rehabilitation of the mine site for the purpose of reestablishing the prior
use or creating the capability for an alternate land use (see also Chapter 7). In
situations where surface mines lack sufficient spoil, CCRs have been used to
achieve the approximate original contour of the land surface.
In some cases, CCR material is used as a cover on the overburden or backfill
in addition to soil. The FBC ash may also be used to form low-permeability caps
when acid-producing spoil is present.
Surface soils in the mine setting, often used for reclamation, may have ad-
verse characteristics. Coal combustion residues have been used as soil amend-
ments to ameliorate problems with infiltration rate, water retaining capacity, and
soil acidity (Daniels et al., 2002; also see "Soil Amendments" above).
Coal combustion residues may be used to abate or prevent subsidence of
underground mines in conjunction with conventional materials or concrete.
Cementitious fly ash is especially effective for such use, and FBC fly ashes have
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COAL COMBUSTION RESIDUES 53
A
B
FIGURE 2.8 Big Gorilla pit showing the dry-to-wet placement of approximately three
million tons of FBC ash into standing mine water. (A) Big Gorilla in the midst of the
placement project. (B) Aerial shot of the filled Big Gorilla pit.
NOTE: (A) Courtesy of Barry Scheetz, Pennsylvania State University; (B) Courtesy of
Daniel Koury, Pennsylvania Department of Environmental Protection.
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54 MANAGING COAL COMBUSTION RESIDUES IN MINES
FIGURE 2.9 Methods of large-volume CCR emplacement in surface mines.
been shown to have sufficient bearing capacity for most post-mining uses (Scheetz
et al., 2004). For example, in Pennsylvania, CCRs have been used to fill cropfalls,
which are long, narrow vertical surface openings that are created by subsidence in
underground mines. The costs of using CCRs for subsidence control is substan-
tially lower than using concrete; for example, costs may range between $2.50 and
$4.50 per ton for CCR as compared to $60 to $70 per ton for concrete (Dwyer,
2004).
Underground mines may be sealed off to decrease the possibility of AMD
from polluting the surface waters, to reduce the occurrence mine fires, or for the
overall safety of the general public. Mine sealing generally involves injecting a
fly ash grout mixture into boreholes in the underground mines to seal off problem
areas.
Certain CCRs may also be used to treat pyritic spoils that result in acid mine
drainage. Alkaline CCRs (especially FBC CCRs) can be used to neutralize exist-
ing acidity in groundwater (see Chapter 3). Coal combustion residues can also act
as a seal to reduce the oxidation of pyrite in the coal spoil, thus slowing the rate
of generation of additional AMD. The FBC ash grout can be pressure-injected
through drill-holes into subsurface voids in previously backfilled surface mines
and in voids in abandoned underground mines to encapsulate the pyritic materials
with the cementitious mixture (Sheetz et al., 2004). However, the long-term
efficacy of this practice is still questionable because of lack of data.
Methods for Placement of CCRs in Coal Mines
As mentioned earlier, CCRs can be placed in mines for a variety of purposes.
CCRs can be placed for both low-volume (e.g., paving pit floors, grouting frac-
tured country rock, capping and encapsulating potential AMD-producing mate-
rial) and high-volume applications (e.g., backfilling of pits and underground
workings, alkaline addition for neutralization of AMD). In large-volume applica-
tions, CCRs can be placed as distinct monofills, multiple layers, or blended
mixtures of CCR and coal refuse materials (PADEP, 2004; Figure 2.9).
CCR placement in mines currently occurs above or below the water table
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COAL COMBUSTION RESIDUES 55
(see Chapter 3, Sidebar 3.1). Placement below the water table may involve the
use of slurry methods or direct dumping of CCR into standing water (see Sidebar
2.7). The permeability of CCRs after placement will depend on the CCR proper-
ties, with highly compacted cementitious fly ash having the lowest permeability
and coarse bottom ash having higher permeability (see Chapter 3). Lime or
cement can be added to CCR to increase its structural stability, to make it more
cement-like, and to decrease its permeability.
The method of emplacement of CCRs at the mine site is an important factor
that will influence the structural stability and hydrogeological and geochemical
processes taking place there. The flow of water through and around CCRs will
depend on the geometry of emplaced zones and the hydraulic properties of the
surrounding materials. Similarly, geochemical reactions taking place within CCR
zones and between CCR and surrounding materials will depend on the relative
surface area of the CCR zones and surrounding materials and the potential for
transport of reactants between materials (see Chapter 3). For these reasons, it is
important to consider the exact method and location of CCR placement in the
design plan, and to accurately predict the structural, hydrological, and geochemi-
cal processes that will occur after emplacement.
There are three common methods of placing CCRs in mine settings: gravity,
hydraulic, and pneumatic. These methods are described in detail below.
Gravity. Gravity placement is by far the most common method of placing CCRs
in or around surface mines. Typically, CCRs are brought to the mine and put in
place by end-dumping off trucks, although occasionally belly-dump vehicles or
conveyor belts may be used. Bulldozers or scrapers may be used for the final
placement. Generally there is no formal compaction in any manner (e.g., rolling,
vibrating) unless the layer is being used as a liner or final cover over a previously
placed fill. However, the committee did visit minefills where the CCRs were
placed in small lifts and then compacted using a traditional compaction method.
More typically, trucks that bring the material drive over the previously placed
CCR layers, resulting in some degree of compaction. This is not a systematic
compacting procedure and is not an effective compaction method over sizable lift
thicknesses. Systematic compaction can increase the strength of the fill material
and produce a uniform fill (ASTM, 2002b).
Pneumatic. Pneumatic placement is applicable primarily to underground mines
and was used commonly in Europe and in non-coal mines in the United States
two or three decades ago. However, pneumatic placement is no longer a common
practice because of the hazards associated with the technique, such as the genera-
tion of a considerable amount of static electricity, which could result in sparking.
Sparking would be hazardous in both working and abandoned underground coal
mines that may have accumulations of methane gas.
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56 MANAGING COAL COMBUSTION RESIDUES IN MINES
Hydraulic. The hydraulic method, applicable to CCR placement in both under-
ground and surface mines, consists of making a slurry of the CCR with water and
then pumping it to the location where it is to be placed. The process is straightfor-
ward and is similar to grout placement. The CCRs are stored and may be mixed
with other substances. The CCR mixture is then transferred to a mixer where
water is introduced in the proper proportion. The designed mixture may require
testing prior to use in order to ascertain the desired setting time and fluidity. The
material is then pumped to the placement location through pipes. On exiting the
pipe, the velocity of the slurry decreases and water separates from the solids. Fine
particles from the CCR may remain suspended in water for quite some time; thus,
discharge water may have to be decanted in a sludge pond for further settling.
SUMMARY
The combustion of coal generates large quantities of solid materials, collec-
tively referred to as CCRs, which are grouped into two categories: the noncom-
bustible portion of the coal itself (fly ash, bottom ash, boiler slag) and products
from various air pollution control technologies installed at the combustion facil-
ity (e.g., FGD materials). The physical and chemical characteristics of the CCRs
produced are determined by several factors including the source coal, the com-
bustion technology, the air pollution control equipment technology, and the resi-
due handling equipment. The characteristics of CCRs vary greatly and are the
major determinants of the possible uses of the residue. Thus, the committee
recommends that regulatory agencies responsible for imposing pollution con-
trol standards carefully consider the implications of air pollution control
requirements for the marketability of CCRs to ensure that the full suite of
environmental consequences is analyzed and understood.
For the purpose of this study, data were sought on the amounts of CCRs
generated and how these CCRs are subsequently disposed of or used, including
how much is placed in coal mines. However, the committee found the available
data regarding CCR generation and disposal or uses to be inadequate. The
committee recommends expanding existing data gathering mechanisms to
include comprehensive reporting of CCR generation quantities and classifi-
cations, and clarifying those mechanisms to allow for a clear determination
as to disposal or use.
This chapter outlines the many alternatives available for CCR disposal and
use, including applications in surface and underground coal mines. Many factors
enter into the decision-making process when weighing the management options
and economic impacts of CCR utilization or disposal. Such factors include the
local possibilities for utilizing a particular CCR, the costs and demands of CCRs
for alternate uses, the substitution of CCRs for unrecycled materials, the transpor-
tation distance to industries able to use CCRs, the location and costs of CCR
placement options (e.g., availability of CCR-receiving coal mines; availability of
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COAL COMBUSTION RESIDUES 57
new land for landfills and surface impoundments), the local regulatory environment,
and the potential effects on human health and the environment. The characteristics of
a particular CCR stream, coupled with the aforementioned considerations, are key to
determining the best options for disposal and use of CCRs. Therefore, the committee
concludes that understanding both the characteristics of CCRs and the options avail-
able for their disposal and use are critical to sound CCR management and that such
characteristics and options are highly site specific.
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Representative terms from entire chapter:
groundwater flow
