COAL

DEFINITION

Coal is a physically and chemically complex substance that has been defined in different ways over the years. Currently, the most widely accepted definition is that adopted by the American Society for Testing & Materials (ASTM) which is as follows:

“Coal is a readily combustible rock containing more than 50 percent by weight and more than 70 percent by volume of carbonaceous material including inherent moisture, formed from compaction and induration of variously altered plant remains similar to those in peat. Differences in the kinds of plant materials (type), in degree of metamorphism (rank), and in the range of impurity (grade) are characteristic of coal and are used in classification (ASTM, 1970, p.70).”

CLASSIFICATION

Because of the complexity of its physical and chemical properties and its varied uses, the classification of coal is not a simple task. Many classification schemes for coal have been proposed over the years using a variety of parameters as criteria. Of the various approaches to classification, rank is one of the more important. Rank is a measure of a coal’s thermal maturity, that is, its position in the coalification series. Coalification refers to the progressive transformation of peat through lignite, subbituminous, bituminous, and anthracite. The standard rank system used in North America is the ASTM system (Table 2.6.1). It is based primarily on fixed carbon, volatile matter, and calorific value and utilizes familiar rank terms such as lignite, bituminous, and anthracite. In the ASTM system, these terms have specific meaning with regard to the aforementioned parameters, but may conflict with meanings given to the same terms in another country’s classification system.

Coals are also classified by type into two broad categories: (1) sapropelic or nonbanded coal, and (2) humic or banded coal. Nonbanded coals exhibit little or no apparent stratification, are frequently granular in texture, tend toward homogeneity, and are allochthonous in origin. Examples of nonbanded coals are boghead coal, composed primarily of algal remains, and cannel coal, which consists largely of spores.

Banded coals, by contrast, are composed of a series of layers which are parallel to the bedding and which can be distinguished on the basis of macroscopic characteristics such as luster, hardness, etc. These bands are known as lithotypes and are composed, in turn, of macerals, which are the microscopically identifiable components of coal. Macerals are defined on the basis of color, morphology, association, and fluorescence. Maceral analysis plays an important role in the coal evaluation process and yields valuable information concerning the nature of the paleoenvironment in which the coal was formed, the degree of thermal maturity of the coal (rank), and its suitability for particular uses.

Of the two types, banded coals are by far the more abundant and constitute the majority of the world’s coal resources.

ORIGIN OF COAL

Coal is formed by the accumulation and preservation of organic material (primarily from plants) in swamp, marsh, or bog environments. This plant material is altered into peat by complex biochemical processes that are still poorly understood. Peat accumulates very slowly relative to the human lifespan. Accumulation rates in Florida and the Mississippi Delta are from 0.5 to 1 mm/a, whereas in Borneo rates of up to 4 mm/a have been recorded. Generally, accumulation rates are higher in tropical climates than in temperate to cool climates although the higher growth rates are partially offset by slower decomposition rates in cooler climates. Peat can accumulate whenever accumulation rates are higher than the rate of decomposition. Most ancient coals probably originated in temperate to tropical climates (Bustin, et al., 1983).

As geological conditions change in peat-forming areas, the peat deposits may become buried by subsequent influxes of sediment. Sedimentation may continue for very long periods of time and, when coupled with the subsidence of the depositional basin, can result in the burial of the peat deposit under thousands of meters (feet) of sediment. Heat and pressure generated by the weight of the sedimentary column, in addition to biochemical and geochemical processes, cause the coal to increase in rank. The level of coalification attained is primarily a product of temperature and length of time of heating. Because in most stratigraphic sequences temperature increases uniformly with depth, the more deeply buried coals are generally of higher rank. Generally, as rank increases, porosity, volume, volatile constituents, and water decrease, while fixed carbon, density, heating value, and reflectance increase.

The main byproducts of coalification are methane, carbon dioxide, and water. Water is lost early in the coalification process and the ratio of methane to carbon dioxide increases with rank (Bustin, 1983). Large volumes of methane may be generated during coalification and can be produced and marketed either in conjunction with underground mining or as an independent venture. In fact, in the Black Warrior Basin of Alabama, 25% of natural gas production on an annual basis currently comes from degasification of deeply buried coal beds.

DEPOSITIONAL ENVIRONMENTS

The thickness, lateral distribution, composition, and quality of a coal bed are determined to a great extent by the depositional environment. Moreover, Home, et al. (1978) found that the aforementioned characteristics were determined by the depositional environments that preceded, were coeval with, and that immediately followed deposition of the peat. The preceding environment shapes the topography on which the peat is deposited and therefore affects the thickness and lateral extent of the deposit. Contemporaneous environments affect seam continuity and composition whereas later environments may affect the peat by partial or complete removal of the deposit by erosion or, if brackish or marine waters are introduced, alteration of peat chemistry and therefore of coal quality.

Coal-forming environments can be divided into two broad categories: (1) paralic, which refers to coastal or near-coastal marine settings, and (2) limnic, which refers to coals formed inland, usually in intermontane regions and under freshwater conditions. Generally, limnic coals are characterized by thick beds of limited lateral extent. Although some of the coals in the western United States are limnic in origin, most North American coal deposits appear to have formed in paralic environments.

Paralic environments can occur in back barrier, deltaic, or coastal and interdeltaic settings (Bustin, 1983). Back barrier coals develop landward of barrier islands, frequently in abandoned lagoonal basins that are formed between the barrier islands and the mainland. Back barrier coals are typically rather thin, laterally discontinuous deposits that are elongate parallel with depositional strike and that are usually high in sulfur and ash.

Coastal plain coals develop on low, relatively flat, subsiding coasts that have a high water table and little influx of sediment. Some of the more persistent coals in the Appalachians of the eastern United States may have been deposited in coastal plain settings. Modern coastal plain swamps that are active sites of peat accumulation include the Everglades of Florida and the Okefenokee Swamp of Georgia (Bustin, 1983).

Many ancient coals are interpreted to have formed in deltaic systems and thus depositional environments associated with deltas have been the subject of intensive investigation.

The following comments on coal-forming environments in deltaic systems are drawn from Home, et al. (1978). Depositional modeling can be used to predict large-scale trends in coal deposits on a regional scale and are therefore useful in the initial phases of coal exploration. Further, small-scale variations in coal thickness, quality, and lateral continuity frequently can be predicted, providing data that can be extremely valuable in mine planning and development.

The following illustration (Fig. 2.6.1) was derived from a detailed data base developed from the coal-bearing carboniferous-age rocks of eastern Kentucky and southwestern Virginia and from similar environments in contemporary coastal areas. Figure 2.6.1 illustrates the typical shape and lateral extent of coal deposits which form in the different environments within the deltaic setting.

Figure 2.6.1.

Coals that form in lower delta plain environments are typically elongate parallel with depositional dip because the only environments suitable for peat accumulation are adjacent to relatively narrow levees on either side of distributary channels. Interdistributary bays occur between the distributary channels and are sites of accumulation of fine-grained bay-fill detrital sediments. Sites of peat accumulation on the lower delta plain are generally restricted to the elongate, relatively narrow areas between the levees and the interdistributary bays. Lower delta plain coals are usually relatively thin and contain splits caused by crevasse splays that breach the poorly developed levees along the distributary channels.

Upper delta plain-fluvial coals also tend to be elongate in the direction of depositional dip although they are not as continuous in that direction as the lower delta plain coals. Deposits typically formed as pod-shaped bodies on flood plains adjacent to coexisting meandering channels and exhibit significant thickness variations over short distances. Also, as in the case with lower delta plain coals, numerous splits can occur near the levees bordering active channels because of splays. Post-deposition shifting of channels can also complicate the sedimentary sequence by eroding the coal deposit and creating “washouts.”

In some locales, a transitional zone exists between the lower and upper delta plain environments that exhibits characteristics of both lower and upper delta plain sequences. In the transition zone between the lower and upper delta plains, many of the large interdistributary bays (flood basins) that occur between distributary channels have filled with sediment and provide broad basins in which large coal swamps can develop. These broad, relatively uninterrupted basins provide a favorable environment for the formation of coal deposits that are typically more laterally extensive than those of the lower and upper delta plain proper. Coals formed in this transitional zone share some characteristics with upper and lower delta plain coals such as splits that develop near levees and post-depositional washouts. Most of the more economically important coal beds in the Appalachian coal region are interpreted to have developed in this transitional zone between the lower and upper delta plains.

From the foregoing brief discussions, it is apparent that, in the initial phases of exploration, a knowledge of the depositional environments that control the shape and configuration of the coal body will enable explorationists to design a drilling program for maximum effectiveness and efficiency in defining the coal deposit. At the lease-tract or mine plan levels of exploration, more detailed drilling and evaluation may be desirable to predict areas of thick and/or high-quality coal.

Depositional environments also partially determine the sulfur content of coal deposits. Sulfur occurs in the form of iron sulfide (predominantly pyrite) in several ways in coal. A finely disseminated form sometimes referred to as framboidal pyrite is the most reactive form of pyrite and the most difficult to remove. It is so finely disseminated throughout the coal that it cannot be removed effectively in float-sink washability tests. Research suggests that framboidal pyrite originates from sulfur produced by microorganisms found in marine to brackish waters, but not in fresh water. It has been shown (Ferm, 1976; Caruccio, et al., 1977) that framboidal pyrite is most strongly associated with-coals overlain by roof rocks deposited in marine to brackish-water environments. Exceptions occur when a blanket of sediment (such as a crevasse splay) is introduced early enough to shield the peat deposit from later marine to brackish-water transgressions. It follows that coals which formed in back barrier to lower delta plain environments are more likely to be overlain by sediments deposited by marine to brackish water and hence will be more likely to contain higher amounts of framboidal pyrite.

Coals that formed in transitional lower delta plain environments are subject to a mix of fresh and brackish to marine water influences and hence are highly variable in their sulfur content. Generally, however, transitional lower delta plain coals are considered to be lower in framboidal pyrite than coals deposited in lower delta plain and back barrier settings. This trend is thought to continue for coals formed higher in the delta plain in fluvial-upper delta plain settings where marine influence is uncommon. These coals are generally considered to be lower in finely disseminated pyritic sulfur than coals formed in other delta plain depositional settings. An understanding of the depositional setting in which a coal bed formed can therefore be used to predict the amount and type of sulfur present and to guide the exploration for low-sulfur coals in areas where sulfur contents are usually high.

Investigations by Caruccio, et al. (1977) and Home, et al. (1976), serve as examples to illustrate the potential usefulness to mine developers of understanding the depositional history of a coal bed. Using a data base of 450 core holes in a 518-km² (200-sq-mile area) located in the Appalachian coal region of the eastern United States, the investigators interpreted the target coal bed to have been deposited in a lower delta plain setting. Typically, coals interpreted as lower delta plain coals, where overlain by brackish to marine rocks, have sulfur contents of greater than 2% with 75% or more of the sulfur occurring in the form of framboidal pyrite (Caruccio, et al., 1977). Where deposits interpreted as freshwater splays were emplaced over the peat surface prior to the deposition of the marine rocks, the peat apparently was shielded from the sulfur-reducing bacteria, causing the sulfur content in the peat to remain low (Home, et al., 1976).

Figures 2.6.2 and 2.6.3 summarize the investigative results of Horne (1978). Figure 2.6.2 is an interpretation of the depositional environments after deposition of a coal bed. The data suggest that the levees of a distributary channel in the southwestern part of the area were breached and splay deposits encroached to the north and east over the coal and into the marine-influenced interdistributary bay. Figure 2.6.3 shows the distribution of disseminated sulfur in a target bed. A comparison of Figs. 2.6.2 and 2.6.3 illustrates the expected association between areas where the coal is overlain by marine beds (the eastern part of Fig. 2.6.2) and higher sulfur concentrations. In the western and southern parts of the diagrams where the wedge of nonmarine splay deposits covered the coal, sulfur contents are correspondingly lower.

Figure 2.6.2.

Figure 2.6.3.

The relationships shown in these diagrams between disseminated sulfur content and specific depositional environments suggest that exploration drilling programs at the lease-tract level should be devised to gain an understanding of the depositional setting of a coal deposit and to define such depositional features as might cause significant variation in the physical or chemical characteristics of the coal.

STRUCTURAL FEATURES AND THEIR EFFECTS ON COAL DEPOSITS

Structural features are those features provided by post-depositional deformation or displacement of the rocks. Such features can form concurrently with, or shortly after, deposition of the sediment, such as slumps or differential compaction of soft sediments having different densities. These soft-sediment structures can and do sometimes affect the continuity of coal deposits. More commonly, however, it is structural features such as folds and faults that formed later in the history of the rocks as a result of tectonic forces that determine the present attitudes of the coal beds.

Inclined or Folded Strata

Rock sequences deform plastically under conditions of high temperature and confining pressure and hence may be tilted or folded into a series of subparallel to parallel upwarps and downwards termed anticlines and synclines, respectively (Fig. 2.6.4). Folding may be so intense as to lift the strata to the vertical or even to an overturned position. All uplifted strata are more susceptible to subarea! erosion with areas of maximum uplift having the greatest degree of susceptibility. Therefore anticlinal crests are often severely denuded, creating a breached structure and interrupting the areal continuity of any coal beds. The tilting and folding of strata containing coal beds therefore complicates efforts toward correlation of beds from area to area and also imposes constraints on mining operations in areas of intense structural deformation. In most cases the overburden increases more rapidly away from the outcrop in downward pitching coal beds than in flat-lying deposits, reducing the amount of coal that is economically recoverable.

Figure 2.6.4.

Faults

A fault is a fracture or fracture zone along which displacement has occurred on one side of the fracture relative to the other. Faults are important considerations in coal exploration and mining and, depending on local conditions, can render an otherwise attractive area unsuitable for mining.

There are several types of faults defined by the direction of relative motion across the fault plane. The two types of faults most commonly encountered in coal exploration are normal faults and reverse faults. Normal faults occur where the block above the fault plane (termed the hanging wall) moves down relative to the lower block (the footwall) (Fig. 2.6.5). The effect of drilling through a normal fault is that of an apparent shortening of the rock section by the elimination of strata from the column of rock penetrated by the drill. This can be illustrated by visualizing vertical boreholes that penetrate the fault plane on the front panel of Fig. 2.6.5. The point where the wellbore enters the footwall is stratigraphically lower than the corresponding point on the hanging wall by an amount equal to the vertical displacement of the fault (AB).

Figure 2.6.5.

In the case of a reverse fault, the hanging wall moves up relative to the footwall, and repeated sections of strata are encountered (Fig. 2.6.6). Vertical displacement is represented by line AB and, once again, each borehole allows a different interpretation of the nature and position of the target coal bed. Indeed, if the middle borehole was the only source of data, an observer might conclude that two coal beds were present if the intervening strata were not carefully evaluated. These examples emphasize the need for a carefully planned drilling program, especially in areas where existing data indicate the presence of faulting. Where faults are known to occur, the drilling program must be designed to yield sufficient data to allow adequate mapping of the type and extent of faulting present as well as the amounts of displacement so that the effects on the coal beds can be accurately determined.

Figure 2.6.6.

Joints and Cleats

Joints are fractures in a rock mass across which no displacement has occurred. Joints are commonly planar, occur in groups of subparallel to parallel fractures called sets, and may extend, both vertically and laterally, for distances from as little as a few millimeters (inches) up to many tens of meters (feet) or more. Where jointing is prevalent, it can be a factor in mine planning because it represents existing planes of weakness in the overburden along which the rock will preferentially break during mining. Surface mine highwalls are therefore sometimes planned to parallel the orientation of dominant joint trends and hence take advantage of these natural fracture systems to facilitate blasting and overburden removal.

Cleats are naturally occurring fractures in coal beds (primarily in bituminous coals) that are morphologically analogous to jointing in rocks. Cleats typically occur in two mutually perpendicular sets. Fractures of the dominant set are called face cleats. Face cleats are penetrative, closely spaced fractures that serve as primary conduits for fluids such as methane gas, which is a byproduct of coalification, and ground water. Butt cleats form the complementary, less dominant cleat set and are typically irregular, nonpenetrative fractures that stop against a face cleat, occur over a broader range of orientations, and serve, to a lesser extent, as conduits for fluids. Because of their permeability, cleats in general, and especially face cleats, are often sites of mineralization and deposits of minerals such as pyrite, calcite, and others.

Cleat orientations can be important in mine planning for much the same reasons as joints, that is, they represent natural planes of directional weakness which can facilitate the cutting and loading of an exposed coal bed in a surface mine. Although probably of lesser importance generally than jointing in rocks, cleat orientations have determined, in certain cases, mine layout and the direction of mining.

Clastic and Igneous Intrusions

Perhaps of lesser importance in most locales than the previously discussed structural features is the intrusion of either elastic (sedimentary) material or igneous masses into a sequence of coal-bearing rocks. These intrusions may parallel bedding planes or cut across bedding. In the former case, the features are called sills, in the latter, dikes. These structures can range in thickness from a fraction of a millimeter (inch) up to many tens of meters (feet) and, in certain mining locales, can present significant problems. In the case of a elastic intrusion, the intruded material is waste material and must be separated and removed from the coal but does not alter the physical characteristics of the coal. In an igneous intrusion, the coal in the immediate vicinity of the intrusion is thermally altered. The alteration can result in an increase in rank or even the coking of immediately adjacent coal. An added problem with igneous intrusions is that the igneous rocks are much harder than coal and the associated sedimentary rocks, thereby increasing the difficulty of mining in these areas.

EVALUATION OF COAL DEPOSITS

Determination of the Amount of Coal in Place

Once the decision has been made to proceed with a detailed evaluation of the coal deposits on a particular tract with the purpose of opening a surface mine, a data base must be generated at a level of detail sufficient to characterize the coal and overburden. A number of geological or geophysical techniques can be used to provide data. In areas where a blanket of unconsolidated material was deposited on the erosional upper surface of the underlying bedrock, seismic refraction, seismic reflection, or, in some cases, gravity surveys can reveal the configuration of the bedrock surface. Also, faults with vertical displacements no smaller than 6.1 m (20 ft), or under ideal conditions 4.6 m (15 ft), can be identified using seismic techniques (Daly, et al., 1976). In the event that igneous intrusives are present, gravity or magnetic techniques can be used to assist in definition of the igneous-sedimentary boundary.

All of the foregoing techniques can, under certain conditions, supply useful data to the coal explorationist but, as general exploration tools, they lack the resolving power for widespread exploration in the coal industry. The carefully planned drilling program remains the primary exploration technique in the coal industry and provides the bulk of the raw data from which coal and overburden characterization maps are made and upon which mining decisions are based.

At the lease tract level, drilling is used primarily to define areas of thick coal and to determine coal quality. These data are then used to calculate measured reserves. Drill-hole density necessary to prove reserves varies with the complexity of the geology and the degree of consistency in coal bed thickness. In areas of structural complexity or where coal bed thickness is highly variable, drill-hole spacing may be as close as one hole every 1.6 ha (4 acres) (Reilly, 1968). Conversely, in geologically undisturbed areas where coal bed thickness is relatively constant, drill holes are sometimes spaced 0.4 km (0.25 mile) or more apart. Local variations in coal-quality parameters (such as sulfur content) constitute another reason to increase drilling density if those parameters are critical in determining the marketability of the coal. Accuracy of the reserve estimate should be within 20% and the drilling program should be geared to produce figures at this level of accuracy (Wier, 1976).

In planning a surface mine, coring of all the exploratory holes probably will not be required. A sufficient number of holes should be cored to allow the geologist to determine the depositional environment of the coal and thereby to make decisions for location of additional test holes and for mine planning. Data from the cored holes will also be useful in determining the type of blasthole equipment and bits as well as types of mining equipment that will be most appropriate. Otherwise, exploratory holes can be drilled by the less expensive air-rotary method. When a coal sample is needed in a particular area, a rotary hole is drilled to establish the elevation of the coal. A second hole is then put down immediately adjacent to the first, still using the rotary bit but stopping the hole just above the position of the coal bed as established by the previous hole. The core barrel and bit is then substituted for the rotary bit and the coal bed is cored.

Systematic sample or core descriptions and recording of coal thicknesses and depths are necessary to insure reliable integration of the data onto the various interpretive maps which are important tools in the evaluation process.

All exploratory holes should have geophysical logs run soon after the drilling is completed. Effective geophysical logging can reduce the number of drill holes required to evaluate a property by maximizing the data obtained from each hole. Geophysical logs serve as a check on written logs and provide a precise record of coal depth and thickness. Geophysical logs of cored holes also provide a means of identifying lithologies in intervals where the core is lost by comparing the logging tools’ response to different lithologies in other cored intervals. The basic borehole geophysical suite (calibrated density, gamma, resistivity) can provide the following data: (1) coal thickness and depth;(2) lithologic data; (3) depositional data—nature of contacts and vertical stratigraphic sequences; (4) hydrologic data—aquifers, lost circulation zones, water levels; (5) identification of structural data and stratigraphic sequences; (6) recognition and correlation of specific coal intervals is augmented by their individual signatures; and (7) recognition of subtle mineralogic changes, such as alteration, that are difficult to discern from cuttings (modified from Crowder, 1986).

More sophisticated geophysical surveys can provide many more types of data such as the coal quality parameters of ash, carbon, volatile matter, heat content, moisture, mineral matter, and rank, at greater cost. Crowder (1986) estimates the cost of a basic geophysical logging suite at 10 to 20% of a total rotary drilling budget with more sophisticated logging suites increasing the cost to as much as 50%. A partial list of geophysical tools and their application to coal exploration is given in Table 2.6.2.

Once the data are assembled, the very basic task of correctly identifying and correlating the coal beds throughout the area of interest must be performed. Extra care must be taken in areas where multiple coal beds of varying thickness are present in close stratigraphic proximity to each other. Incorrect identification of the beds can result in a misleading evaluation of the property, which, in turn, can cause severe problems in the mining, preparation, or marketing aspects of the operation. Geologists commonly use physical characteristics of the overburden, physical and chemical characteristics of the coal bed, distinctive stratigraphic markers or sequences, signatures on geophysical logs, and any other pertinent data to assist in the correct identification and correlation of the coal beds. In more complex areas, additional data may have to be obtained in certain parts of the tract by the drilling of more closely spaced holes before correlations can be made with confidence.

When the coal bed stratigraphy has been worked out, it is useful to construct a series of maps using data obtained from field investigations, drilling, and laboratory work that will depict coal and overburden thickness, overburden to coal ratio, and significant analytical parameters. These maps may be prepared as a series of registered mylar overlays to allow simultaneous viewing of different combinations of data or they may be constructed separately. A structure contour map with the target coal bed as the datum horizon is also an extremely useful method to depict structural or stratigraphic features that affect the topography of the coal bed. Alternatively, the available data can be entered into a computer data base and appropriate software programs can be utilized to portray stratigraphic, mining, or economic conditions at desired scales.

Coal and overburden thickness maps (termed isopachs) are constructed by plotting the appropriate thickness values on a base map and constructing contour lines (isopachs) representing regularly increasing or decreasing thickness intervals using the plotted values as guides for positioning the contour lines. An example of a coal isopach map is given in Fig. 2.6.7. Similar isopach maps can be constructed showing overburden thickness. Isopleth maps can be constructed using the same principle as the isopach maps, but substituting various coal quality parameters for the thickness data (Fig. 2.6.8). This type of data presentation would have application where relatively small variations in coal quality would significantly impact the marketability of the coal.

Figure 2.6.7.

Figure 2.6.8.

Using the same coal and overburden thickness data, lines representing overburden to coal ratios or “mining ratios” (expressed as 5:1, 10:1, etc.) can be drawn. A ratio of 5:1 means that the line represents the limit at which 0.9 t (1 ton) of coal can be extracted by removing not more than 3.8 m³ (5 cu yd) of overburden. Strictly speaking, this is not a true ratio because it has dimensions of overburden volume per unit weight of extracted coal. The inclusion of these units gives rise to a difference between ratios computed in English units and ratios computed using metric units.

Ratios of thickness values alone cannot be used to deduce mine economics. These values must be converted to cubic meters (cubic yards) of overburden per tonne (ton) of coal to provide data to the analyst in units that can be more readily equated to mining costs. The conversion from feet (or meters) to cubic yards (or cubic meters) per ton (or metric ton) is outlined as follows from Wier (1976):

or

where OB is the thickness of overburden, C is the thickness of the coal, and SG is the specific gravity of coal. Because of the differences in the units of the English and metric systems, ratios calculated in the metric system are about 0.8 (0.842778) that of the English system. If specific gravity is not known, but the rank of the coal is known, the following specific gravity values are commonly used (Averitt, 1975):

Rank	Specific gravity
Anthracite	1.47
Bituminous	1.32
Subbituminous	1.30
Lignite	1.29

It should be noted, however, that it is important to use correct specific gravity values whenever possible because if the coal contains much mineral matter that has a higher specific gravity than coal, it will skew the results by decreasing the ratio and increasing calculated tonnages per unit area by a possibly significant amount.

Once the overburden lines have been established, the area can then be divided into mining units according to the mining plan and reserves can be calculated. The terms “measured,” “indicated,” and “inferred” are commonly used to define reserve categories with measured reserves having the highest level of reliability and inferred reserves the lowest. The distance between points of measurement distinguish the different reliability categories. Wood, et al. (1983) uses 0.8, 2.4, and 9.7 km (0.5, 1.5, and 6 miles) as the maximum distance between points of measurement for measured, indicated, and inferred coal, respectively. In mining, however, typical exploration drill-hole spacing is sufficiently close to classify all reserves as measured.

The first reserve determination is for total coal in place. The basic calculations in metric and English units, and using specific gravity for a given coal as determined in the laboratory, are as follows:

where SG is specific gravity, C is thickness of coal in meters, and A is area in square meters.

In English units:

where C, A, and SG are the same terms as in the metric equation, and 1359.7 is a constant required to establish the correct tonnage factor to use with the English units.

If average specific gravity values are used, the following values are frequently used as tonnage factors in a simplified form of the equation.

Rank	Tons of coal per acreper ft of thickness
Anthracite	2000
Bituminous	1800
Subbituminous	1770
Lignite	1750

In the case of bituminous coal the calculation would then be as follows:

Resource figures calculated from the preceding equations are estimates only and are not precise, but, with a thorough exploration drilling program, should be accurate to ± 10% (Wier, 1976). This figure must then be adjusted downward to account for losses incurred during excavating, handling, processing, and transporting the coal. Anticipating the magnitude of these losses is usually accomplished by drawing on previous mining experience in the area, and in the case of processing or preparation loss, by reviewing washability studies. In some cases, cumulative loss can approach 50% of the total in situ reserve.

Coal Quality

The determination of coal quality is an integral part of the coal exploration process. It is as important as any of the other factors that are used to determine the mining potential of a given tract. Unlike many of the other factors, however, certain coal quality parameters can be changed to meet user specifications by coal cleaning technology and/or by blending with other coals. The following discussion touches on the more commonly used types of analytical data from the viewpoint of the information they convey to the explorationist about the suitability of his product for certain end uses.

Analytical procedures for testing coal have been continuously refined and updated for the past several decades by ASTM (American Society for Testing & Materials). Many major consumers and large coal-mining companies maintain well-equipped laboratories to analyze coal. The consumer does this to check the quality of the coal he purchases, whereas the producer must stay abreast of the quality of the product, especially as the mining operations advance into new territory. Analytical work is sometimes contracted out to independent laboratories either to run the primary analyses or to serve as quality control checks on the mining company’s or consumer’s results.

The analyses most frequently performed on coal include proximate analysis, calorific value, and sulfur. The proximate analysis consists of the determination of moisture, volatile matter, fixed carbon, and ash. Other types of analyses frequently performed on coal include ultimate analyses, the determination of free swelling index, and determination of trace element content.

Moisture: Moisture occurs naturally in coal beds in a number of different forms and has been determined by many methods. The most common method is through some procedural variant of the measurement of weight loss upon heating. These procedures measure the surface moisture and the inherent moisture, which is that moisture contained in the capillary system of the coal. Moisture contained in the molecular structure of the mineral matter present in coal (water of hydration) is not accounted for by this type of determination, nor does it include the moisture liberated by the thermal decomposition of organic matter in the coal. The water of hydration is commonly assigned a value of 8% of the ash value and the water of decomposition is not considered significant in most applications. For a more detailed discussion of analytical techniques used in this and other aspects of coal characterization, see Rees (1966). Total or “as-received” moisture, which is the value frequently given in coal analyses, is a combination of surface and inherent moisture and is used for calculating other parameters to the as-received basis. Total or as-received moisture values are critical because coal contracts are often based on as-received calorific values, usually measured in British thermal units per pound of coal, which are obtained by converting dry calorific values to as-received calorific values using total moisture content. Because of the tonnages involved in most contracts, and the fact that most contain penalty clauses for coal that does not meet specifications, even a small error in the moisture content value used to determine as-received calorific value can result in significant financial losses. Moisture content also plays an important role in handling and processing coal. As little as 0.5% surface moisture can cause coal to stick in a chute. Higher moisture contents also cause a decreased coke yield in coke ovens.

Volatile Matter: Volatile matter measurements do not reflect the actual amount of a given substance present in a coal sample but rather are measures of thermal decomposition products that form during the heating of a coal sample under rigidly specified conditions. Examples of volatile materials driven off in the heating process include water, hydrogen, carbon dioxide, carbon monoxide, hydrogen sulfide, chlorine, tar, ammonia, and a variety of organic compounds.

Volatile matter is a parameter used in some coal classification systems. It is used indirectly in the ASTM system for distinguishing between coals of medium volatile bituminous and higher rank. Volatile matter values provide useful information in matching specific coals to appropriate combustion equipment and are also of importance in selecting processes and conditions for the gasification and liquefaction of coal. As a general rule, the best metallurgical grade coking coals contain between 15 and 31% volatile matter and are ranked low- to medium-volatile bituminous in the ASTM system.

Fixed Carbon: Fixed carbon is the carbon that remains in the sample after determination of the volatile matter. The numerical value of fixed carbon is obtained by subtracting the sum of moisture, ash, and volatile matter from 100.

Fixed carbon values are used on a dry, mineral-matter-free basis as boundaries between coals ranked as medium-volatile bituminous and higher in the ASTM system. Because the amount of fixed carbon and ash is an approximation of the amount of coke produced, the fixed carbon value is used to estimate coke yield. It is also used in calculating the efficiencies of combustion equipment.

Ash: Ash is the noncombustible residue that is left when coal is burned. This ash residue derives from two basic sources within the coal bed including: (1) extraneous detrital particles of shale, clay, etc., and secondary mineral material such as calcite, pyrite, and marcasite; and (2) inorganic elements chemically bound in the organic compounds making up the coal. The detritus and secondary minerals make up the most significant part of the ash content. It should be noted that the terms ash and mineral matter are not synonymous. Ash, as stated previously, is the residue left after burning a quantity of coal in the presence of air. The amount of mineral matter present in a coal can be determined by a point count performed on a specially prepared coal sample using a petrographic microscope. A simpler method for determining mineral matter if the ash and total sulfur values are known is by using the Parr formula as follows:

where MM is mineral matter, A is percentage of ash in the sample, and S is the percentage of total sulfur in the sample. The Parr formula is probably the method most widely used in the United States for determining mineral matter content.

The amount of ash contained in a coal, as well as the ash’s composition, affect the coal’s performance and therefore its success in the marketplace. Even in very clean coals the ash content may be 2 to 3% and ash contents of 10% or more are not uncommon in many productive coal beds. Carbonaceous material in the coal bed that contains excessive ash is frequently termed bone, bone coal, carbonaceous shale, black shale, rash, or any of a number of other locally used terms. The greater the ash content of a coal bed the lower is the heating value per unit weight of the coal, so that, in higher ash coal, more coal is required to produce a given amount of heat and disposal of the ash residue also becomes a problem. The ash content of a coal usually can be lessened by “washing” the coal in coal preparation plants. This usually entails grinding the coal to a specified size, then suspending it in a liquid with a specific gravity intermediate between that of coal and the mineral matter so that the mineral matter tends to sink in the solution and the coal tends to float. By repeating this procedure several times, a significant part of the mineral matter content can be removed from the coal.

Ash varies greatly in composition. It may contain varying amounts of silica and alumina derived from detrital minerals; iron oxides from siderite,pyrite, and marcasite; calcium oxides and carbonates from siderite; iron sulfide from pyrite and marcasite; and magnesium, sodium, potassium, phosphorus, and a wide range of trace elements (Tieman, 1973). Ash fusion temperatures, a measure of the temperatures at which coal ash begins to deform, softens, and becomes fluid, are important coal quality parameters that determine how the ash residue from a given coal will react when it is burned. Ash begins to deform at temperatures that range from 950° to 1700°C (1750° to 3100°F). Ash with fusion temperatures at the lower end of this spectrum is desirable in certain types of furnaces where ash is removed from the bottom in a liquid state but is undesirable in static fuel bed furnaces where removal of the residue is a difficult and costly process. Pyrite and marcasite (FeS₂), siderite (FeCO₃), calcite (CaCO₃), and other carbonate minerals are frequently responsible for low fusion temperatures in ash, whereas high silica or alumina contents are associated with higher fusion temperatures.

Calorific Value: In the ASTM system, calorific value is one of the primary rank-defining parameters for bituminous, subbituminous, and lignitic coals. Calorific value is usually reported in British thermal units per pound, or calories per gram, and can be easily converted from one system to the other.

Coal used for steam electric generation is sometimes sold at a fixed rate per million British thermal units with penalties for excess ash or sulfur (Wier, 1976). Because many contracts specify calorific value on an “as-received” basis and most analytical results are reported on a “dry” basis, dry values must be converted to “as-received” values by means of the following formula:

The conversion formula contains percent moisture as a term, so the importance of accurate moisture values cannot be overstated.

Sulfur: Sulfur presents numerous problems in coal utilization. In combustion applications it can cause corrosion in the boiler or the buildup of heavy fouling in the boiler tubes. Large amounts of SO₂ are also generated upon combustion and may contribute to atmospheric pollution unless removed by limestone-based stack scrubbers. The same potential corrosion and pollution problems also apply to the liquefaction, gasification, and coking processes with the additional concern that unacceptably high levels of sulfur might be passed along through the coke to the iron and steel resulting in an inferior product (Ward, 1984).

Three commonly recognized forms of sulfur in coal are sulfate sulfur, pyritic sulfur, and organic sulfur. Of these, sulfate is the least important. In fact, sulfate sulfur contents are frequently on the order of 0. 1%. Large sulfate values are sometimes indicative of a weathered sample. Relative amounts of pyritic and organic sulfur vary widely; in some coals total sulfur content is almost all organic whereas in other coals it is virtually all pyritic. It is important to analytically distinguish between organic and pyritic sulfur in coal because at least some of the pyritic sulfur can be removed by specific gravity separation methods. Pyritic sulfur occurs in the minerals pyrite and marcasite and, depending on the particle size of these minerals and the size to which the coal is crushed, half or more of this sulfur can be eliminated. That portion of the pyritic sulfur that occurs in finely disseminated form throughout the coal cannot be removed by specific gravity separation methods. The organic sulfur constituent is part of the hydrocarbon structure of the coal and cannot be removed by conventional coal cleaning technology. Although promising laboratory techniques designed to remove organic sulfur are under investigation, no commercially feasible process currently is available. Until washability tests are performed which can provide specific data, Wier (1976) advocates taking the sum of the organic sulfur content and one-half the pyritic sulfur content as a preliminary indicator of the final total sulfur content of the cleaned coal. Generally, only coals with low sulfur contents are used for steam electric generation. Average sulfur contents of coals received at U.S. power plants of 50 MW or greater generating capacity for the months October through December 1986 ranged from 0.16 to 5.6%. The overall average sulfur content of coal received at these same plants during the same period was 1.36% (U.S. Dept. of Energy, 1987). Variations in maximum allowable sulfur contents in different areas are due primarily to differences in local regulations and to the presence of stack scrubbers at some facilities. The practice of blending different coals to achieve required specifications allows the use of some higher sulfur coals that would not otherwise be suitable for steam-electric generation.

Likewise, in coke production, the use of a high sulfur coal results in a decrease in the amount of coke that can be produced from a given amount of coal. Coal that cannot be cleaned to a sulfur content of less than 1.5% is not likely to be used, even as a blend, for coke production.

Free Swelling Index: Another commonly performed analytical procedure for coal is the determination of the free swelling index (FSI). The FSI is considered useful, although not definitive, in evaluating the coking properties of a coal. It is a measure of the volume increase of a coal when it is heated under specific conditions and is reported in numbers from 0 to 9, with the higher values considered superior from a coking standpoint. FSI values generally increase with rank up to the anthracite rank but values within a given rank may vary widely. Generally speaking, coals with FSI values of 2 or less probably are not suitable for coke production and various users may require higher minimum FSI values for their specific equipment than others. Other tests that are used to predict the coking potential of a given coal include the Audibert-Arnu dilatometer, Gieseler plastometer, and Gray-King coke type, but the FSI is still the most commonly reported procedure of its type.

Ultimate Analysis: Ultimate analysis determines the percentages of the major constituent elements of coal. Determinations of hydrogen, carbon, nitrogen, oxygen, and total sulfur are reported. Typically, ultimate analyses are not performed on all coal samples but only on a representative number of samples. Data from ultimate analyses are used principally for research purposes and in certain classification systems, although there are commercial and industrial applications of the data. Specifically, ratios of carbon, hydrogen, and oxygen values are used to determine coal rank and as an aid in determining a coal’s suitability for coke manufacture, gasification, or liquefaction. Data on oxygen content also are used in calculating boiler efficiencies.

Nitrogen present in the coal may react to form ammonium compounds when coal is carbonized in the coking process. These compounds can be extracted and marketed as fertilizer or for use in the manufacture of nitric acid. Ammonium compounds are also formed in the gasification and liquefaction processes. Their formation, however, utilizes some of the available hydrogen that would otherwise be used in the formation of the more valuable hydrocarbon end products. Also, during coal combustion, nitrogen forms oxides which become atmospheric pollutants when released. For these reasons, low nitrogen contents are usually preferred in coal (Ward, 1984).

Other elements for which analyses are commonly sought include chlorine and phosphorus. Chlorine contributes to corrosion and fouling problems and possibly to atmospheric pollution. A knowledge of the chlorine content is also essential in determining other parameters, including total sulfur. Phosphorus, which is concentrated primarily in the mineral matter, is undesirable in coking coals because, like sulfur, it can contaminate the steel end product.

Trace Elements: Most coals contain a wide range of trace elements, some of which tend to concentrate in the organic faction of the coal, while others have an inorganic affinity and are concentrated in the mineral matter. In some cases, trace element suites are distinctive enough to serve as aids in seam correlation or as indicators of the depositional environment. Boron, in particular, is more strongly associated with coals formed under marine influences. Some trace elements may act as catalysts or inhibitors during the complex reactions involved in coal conversion and may be transferred to the end products of those processes. Trace elements may also be released to the environment through combustion or through the weathering of the coal ash. Not all of the elements released into the environment are harmful but concentrations of toxic elements such as lead, arsenic, cadmium, or mercury might preclude the use of certain coals rich in those elements. Alternatively, other trace elements may be considered as potentially marketable byproducts of coal utilization. A list of trace elements and their concentrations in coals from different coal regions in the United States and Australia is given in Table 2.6.3.

Application of Coal Petrology: Coal petrology is the study by direct examination, usually microscopically, of the organic and inorganic components of coal. Petrologic studies form the basis for a broad range of relatively new techniques which have technologic applications of importance to those involved in coal exploration. For a thorough treatment of the subject, see Bustin, et al. (1985) from which the following comments are condensed.

Coal is a heterogeneous substance that is composed of components analogous to the minerals that are the constituents of inorganically derived rocks. These components are termed macerals and differ widely in physical and chemical properties and in their response to different technological processes. A knowledge of the petrographic composition of a given coal bed will allow the explorationist to predict its behavior in certain applications.

One area of technological application of coal petrology is in the area of coal cleaning by float-sink separation. Microscopic observations of the degree of intergrowth of the organic and inorganic constituents in both the float and sink fractions will indicate whether crushing to a finer size will increase the clean coal yield. Also, observing the type, distribution, and degree of intergrowth of the sulfur will give a preliminary indication of the probable methods of cleaning.

Another area where petrographic techniques have come to play a key role is in the production of coke. Through the employment of these techniques, predictions can be made concerning a coal’s fluidity, FSI, and volatile matter content. Also, extensive research efforts through the years have shown that coal bed constituents can be classified as reactive or inert for given processes and that the information could be quantified to the point that the coal’s behavior can be predicted with some accuracy. Two salient concepts resulting from these research efforts concerning coke quality prediction are: (1) an optimum mix of reactive to inert components of a given rank of coal will produce the best coke and (2) the percentages of this optimum mix will vary with rank. The importance of petrographic analysis to the steel industry is best illustrated by the fact that most steel producers now routinely conduct petrographic analyses to monitor blend quality and to evaluate new coals.

Although nearly 90% of the coal consumed in North America is used for combustion with most of that amount used for the generation of electricity, petrology has not played a significant role in the identification of desirable combustion characteristics. The primary reason for this is that factors most significant in defining the suitability of a coal for combustion are either not directly measurable by petrographic techniques or they are more easily determined by other methods. Even so, some useful relationships have been identified through petrologic studies and it is an area of continuing research.

Finally, coal conversion technologies (primarily liquefaction) utilize petrographic data in identifying optimal coals for conversion. Rank and ratio of reactive to inert constituents are primary factors in determining a coal’s suitability for conversion.

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