January 2012

QUALITY GUIDELINES

FOR ENERGY SYSTEM STUDIES

Detailed Coal Specifications

DOE/NETL DOE/NETL-401/012111 -2010/????
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Disclaimer

This report was prepared as an account of work sponsored by an agency of the United States 

Government. Neither the United States Government nor any agency thereof, nor any of their 

employees, makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned rights. 

Reference therein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States Government or any agency thereof. The 

views and opinions of authors expressed therein do not necessarily state or reflect those of the 

United States Government or any agency thereof.
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Detailed Coal Specifications

DOE/NETL-401/012111

January 2012

NETL Contact:

Mike Matuszewski

General Engineer

Office of Program Planning and Analysis

National Energy Technology Laboratory

www.netl.doe.gov
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Prepared by:

Energy Sector Planning and Analysis (ESPA)

Vladimir Vaysman

WorleyParsons Group, Inc.

Yixin Lu

WorleyParsons Group, Inc.

DOE Contract Number DE-FE0004001
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Acknowledgments

This report was prepared by Energy Sector Planning and Analysis (ESPA) for the United States 

Department of Energy (DOE), National Energy Technology Laboratory (NETL). This work was 

completed under DOE NETL Contract Number DE-FE0004001. This work was performed 

under ESPA Task 341.03.01.

The authors wish to acknowledge the excellent guidance, contributions, and cooperation of the 

NETL staff, particularly:

Mike Matuszewski, NETL Technical Project Monitor
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Table of Contents

1 Objective .....................................................................................................................................10

2 Approach.....................................................................................................................................11

3 The U.S. Coal Industry ...............................................................................................................12

3.1 Coal Historical and Future Demand ........................................................................................12

3.2 Coal Deposits...........................................................................................................................14

3.3 Coal Production .......................................................................................................................15

3.4 Coal Production Forecast.........................................................................................................18

3.5 Coal Cleaning...........................................................................................................................19

3.5.1 Nature of Coal Impurities.....................................................................................................20

3.5.2 Cleaning Methods.................................................................................................................20

3.5.3 Special Treatment Methods...................................................................................................21

4 Definition of Coal Specifications................................................................................................23

4.1 ASTM Classification by Rank.................................................................................................23

4.2 Proximate Analysis..................................................................................................................23

4.3 Ultimate Analysis.....................................................................................................................23

4.4 Higher and Lower Heating Value ............................................................................................23

4.5 Grindability..............................................................................................................................25

4.6 Ash Properties..........................................................................................................................25

4.7 Ash Fusion Characteristics ......................................................................................................25

4.8 Trace Elements.........................................................................................................................25

4.9 Coal Moisture...........................................................................................................................25

5 Coal Types Used in the Previous System Studies ......................................................................27

6 Typical Market Quality of Selected Coals..................................................................................31

7 Recommended Coal Analysis.....................................................................................................33

7.1 Low Volatile Bituminous.........................................................................................................33

7.2 Medium Volatile Bituminous ..................................................................................................36

7.3 High Volatile Bituminous........................................................................................................38

7.4 “Super-Compliance” Subbituminous PRB Coal......................................................................43

7.5 Subbituminous.........................................................................................................................45

7.6 North Dakota Lignite ...............................................................................................................48

7.7 Texas Lignite ...........................................................................................................................51

8 References...................................................................................................................................54
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Exhibits

Exhibit 3-1 U.S. primary energy consumption, 1980-2035 (quadrillion Btu)............................. 12

Exhibit 3-2 U.S. electric power industry net generation by fuel, 2008 ....................................... 13

Exhibit 3-3 Electricity generation by fuel, 2008 and 2035 (billion kilowatt-hours) ................... 13

Exhibit 3-4 U.S. coal fields.......................................................................................................... 15

Exhibit 3-5 U.S. coal production versus demand, 1949-2009 ..................................................... 15

Exhibit 3-6 Coal production by coal rank and number of mines................................................. 16

Exhibit 3-7 2009 coal production by coal-production region...................................................... 17

Exhibit 3-8 Historical coal production by coal rank and location ............................................... 18

Exhibit 3-9 Current and projected coal production by region (quadrillion Btu) ......................... 19

Exhibit 4-1 ASTM D388 classification of coals by rank............................................................. 24

Exhibit 5-1 Coal types used in past NETL system studies.......................................................... 27

Exhibit 6-1 Form 423 summary of 2001-2003 coal quality by coal type.................................... 32

Exhibit 6-2 Average quality of commercially shipped coal by state per Utah Geological Survey

............................................................................................................................................... 32

Exhibit 7-1 Low volatile bituminous coal ................................................................................... 33

Exhibit 7-2 Medium volatile bituminous coal ............................................................................. 36

Exhibit 7-3 High volatile bituminous coal analysis (Pittsburgh No.8)........................................ 38

Exhibit 7-4 High volatile bituminous coal analysis (Illinois No. 6)............................................ 40

Exhibit 7-5 “Super-compliance” subbituminous coal analysis.................................................... 43

Exhibit 7-6 Subbituminous coal from PRB field......................................................................... 45

Exhibit 7-7 North Dakota lignite analysis (high-sodium)............................................................ 48

Exhibit 7-8 Texas lignite analysis (low-sodium)......................................................................... 51
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Acronyms and Abbreviations

APFBC Advanced pressurized fluidized bed 

combustion

ASTM American Society for Testing and 

Materials 

CO2 Carbon dioxide

CTL Coal-to-liquids

DOE Department of Energy

EIA Energy Information Administration

EPA Environmental Protection Agency

FERC Federal Energy Regulatory 

Commission

FT Fluid temperature

HAP Hazardous air pollutants

HHV Higher heating value

HRSG Heat recovery steam generator

HT Hemispherical temperature

HV High volatile

ICR Information collection request

IGCC Integrated gasification combined 

cycle

IT Initial deformation temperature

LHV Lower heating value

ND North Dakota

NETL National Energy Technology 

Laboratory

NYPA New York Power Authority

PRB Powder River Basin

QGESS Quality Guidelines for Energy 

System Studies

R&D Research and development

SCPC Supercritical pulverized coal

SNG Synthetic natural gas

ST Softening temperature

T&S Transport and storage

TX Texas

U.S. United States
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1 Objective

Specifications for selected feedstocks that are commonly found in the National Energy 

Technology Laboratory (NETL)-sponsored energy system studies are summarized in NETL’s

“Quality Guidelines for Energy System Studies” (QGESS). The purpose of this companion 

section is to document default QGESS specifications for coal compositions reflecting a spectrum 

of seven coal ranks: 

• North Dakota (ND) lignite

• Texas (TX) lignite

• “super-compliance” subbituminous, ~0.2 percent sulfur (as-received weight percent)

• subbituminous, > 0.5 percent sulfur (as-received weight percent)

• high volatile bituminous

• medium volatile bituminous

• low volatile bituminous
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2 Approach

The QGESS coal specification selection process was based on the following criteria: 

1. Recommendations for QGESS were selected from the coal analyses most commonly used 

in the previous system studies to maximize the comparability of future system studies 

with those done in the past. A list was compiled of the coal types used in studies of coalfueled energy conversion systems. Based on the frequency of coal types in this listing, 

one coal type was recommended as the QGESS default for each of the seven coal ranks.

2. Selected default coal specifications are, as much as possible, representative of the typical 

coal quality in the United States (U.S.) commercial market (i.e., as procured by the power 

plants in the U.S.). Some coal analyses in this current version of QGESS were obtained 

from the Argonne Premium Coal Sample Program that report as-mined coal properties.

(1

3.5

) The as-mined analyses are potentially different from as-shipped (or as-received) due 

to possible coal beneficiation at the mine prior to shipment (coal preparation at the mine 

is described in Section of this report). Since the purpose of these coal analyses is to 

provide a consistent basis for energy system modeling, this distinction (as-mined versus 

as-shipped composition) is not a primary concern. Other coal composition data sources 

are documented in Section 7. 

3. If there were compelling reasons to do so, a coal type other than that most frequently 

used in past studies could be recommended. For example, the most frequently used 

Pittsburgh No. 8 coal composition was similar to the currently used Illinois No. 6 

composition. Therefore, an alternative Pittsburgh No. 8 composition was selected to 

provide a greater distinction between it and Illinois No. 6 coal.
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3 The U.S. Coal Industry

This section provides background information about the U.S. coal industry, including coal 

reserves, current and future coal demand, coal production, and coal cleaning methods at the 

mine. Information on characteristics of U.S. coal, transportation, and utilization at power plants 

can be found in the Department of Energy (DOE) NETL report, “Overview of U.S. Coal Supply 

and Infrastructure.” (2

3.1 Coal Historical and Future Demand

)

Coal has been a major energy source for more than a century in the U.S. In the last five decades, 

coal production grew steadily from 434 million short tons in 1960, to 1,073 million short tons in 

2009. According to the Energy Information Administration’s (EIA) Annual Energy Outlook 

2010, although the long-term, 25-year outlook presents uncertainties -- resulting from the 

difficulty of accurately predicting future costs of producing and transporting coal, economic 

growth, world oil prices, and future greenhouse gas regulations -- coal demand is expected to be 

relatively steady (Exhibit 3-1). (3)

Exhibit 3-1 U.S. primary energy consumption, 1980-2035 (quadrillion Btu)

Source: U.S. EIA

In the last decade, natural gas utilization went through a solid growth period and has increased its 

share of the electricity market from 13.7 percent in 1997, to 21.4 percent in 2008. Renewable 

energy sources also have increased their share of total net power generation in recent years. 

Meanwhile, coal’s share of total net generation continued its downward trend, accounting for 

48.2 percent in 2008 as compared to 52.8 percent in 1997. Nevertheless, coal continues to be the 

most important source of energy for the U.S. power industry (Exhibit 3-2). (4) 
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Exhibit 3-2 U.S. electric power industry net generation by fuel, 2008

Source: U.S. EIA

According to the EIA Annual Energy Outlook for 2010, in the next 25 years coal will retain its 

largest share position of total electricity generation, while most new capacity additions will be 

natural gas and renewable energy sources (Exhibit 3-3). (3)

Exhibit 3-3 Electricity generation by fuel, 2008 and 2035 (billion kilowatt-hours)

Source: U.S. EIA
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3.2 Coal Deposits

In the U.S., coal is found in 37 states, with 6 states containing about 75 percent of recoverable 

reserves: Montana (28.7 percent), Wyoming (14.9 percent), Illinois (14.6 percent), West Virginia 

(6.7 percent), Kentucky (5.6 percent), and Pennsylvania (4.4 percent). (5

The U.S. Geological Survey has divided the coal-bearing areas of the contiguous U.S. into six 

main provinces: Eastern, Interior, Gulf, Northern Great Plains, Rocky Mountain, and Pacific. 

The provinces are subdivided into coal regions, coal fields, and coal districts. The U.S. coal 

fields, by coal rank and geographical location, are presented in 

)

Exhibit 3-4. (6

The Eastern province includes anthracite regions of Pennsylvania and Rhode Island, the Atlantic 

Coast region, and the Appalachian region. The Appalachian region is of most importance in the 

Eastern province. It is one of the great coal producing regions in the U.S., and contains the 

largest deposits of high-grade bituminous coal. The Appalachian region includes portions of 

Pennsylvania, West Virginia, Ohio, Maryland, Kentucky, Virginia, Tennessee, and Alabama. 

) 

The Interior province includes all bituminous coal in the Mississippi Valley area and the coal 

fields of Texas and Michigan. This province is subdivided into the Northern region consisting of 

the coal fields of Michigan; the Eastern region (a.k.a. Illinois basin) comprising fields of Illinois, 

Indiana, and western Kentucky; the Western region including the coal fields of Iowa, Missouri, 

Nebraska, Kansas, Arkansas, Oklahoma; and the Southwestern region of Texas. The bituminous 

coals of the Interior province are of lower rank and higher sulfur content as compared to the 

Eastern province. Much of the low sulfur, chlorine, and sodium content surface-mineable coal in 

the Illinois basin has been mined. The remaining coal with high chlorine content will have to be 

deep-mined. 

The Gulf province consists of the Mississippi region, including the lignite fields of Alabama, 

Mississippi, and Louisiana; and the Texas region that comprises the lignite fields of Arkansas 

and Texas. Coals found in the Gulf province are of the lowest quality in the U.S., with heating 

value as low as 4,000 Btu/lb, and moisture content as high as 55 percent. 

The Northern Great Plains province includes all coal fields east of the Rocky Mountains, 

encompassing lignite fields of both Dakotas, bituminous and subbituminous fields of northern 

Wyoming, and northern and eastern Montana. This province includes immense deposits of lowsulfur, near-surface, and thick subbituminous coal seams of the Powder River Basin (PRB). 

The Rocky Mountain province comprises the coal fields of mountainous areas of Montana, 

Wyoming, Utah, Colorado, and New Mexico. The deposits in this province cover a range of coal

ranks. 

The Pacific province is largely confined to the State of Washington, and ranges in rank from 

subbituminous through bituminous to anthracite.
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Exhibit 3-4 U.S. coal fields

Source: U.S. Geological Survey

3.3 Coal Production

Unlike petroleum or natural gas, domestic production of coal nearly always exceeds U.S.

consumption (Exhibit 3-5). (7) U.S. coal production has remained near 1,100 million tons 

annually since 1997.

Exhibit 3-5 U.S. coal production versus demand, 1949-2009

Source: U.S. EIA
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The distribution of the U.S. coal production by coal rank for 2009 is presented in Exhibit 3-6. (5)

Exhibit 3-6 Coal production by coal rank and number of mines

Source: Reproduced from U.S. EIA Data

The U.S. coal production decreased in 2009 by 8.5 percent to a total of 1,073 million tons from 

2008 record level of 1,172 million tons due to the ongoing economic downturn (Exhibit 3-7). (8

Both the Appalachian and Western regions had decreased coal production in 2009, while the 

Interior region remained almost steady, increasing by 0.1 percent. The decrease in coal 

production in the Appalachian region accounted for about half of the total decrease in U.S. coal 

production, while the Western region was responsible for the rest of the decrease.

) 

The EIA uses “regions” as their highest level coal location descriptor as opposed to “provinces” 

used by the U.S. Geological Survey. The three coal regions in the EIA lexicon are Appalachian, 

Interior, and Western. The balance of this discussion uses the EIA region descriptors.

495 505

72

2

1,284

33 20 69

0

200

400

600

800

1,000

1,200

1,400

Biuminous Submitumonous Lignite Anthracite

Million Short Tons

Production Number of Mines
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Exhibit 3-7 2009 coal production by coal-production region

Despite the one-year decrease between 2008 and 2009, Western coal production has been 

growing steadily since 1970, especially production of low sulfur subbituminous coals in the 

Powder River Basin (Exhibit 3-8). (7)
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Exhibit 3-8 Historical coal production by coal rank and location

Source: U.S. EIA

3.4 Coal Production Forecast

According to the EIA Annual Energy Outlook 2010 forecast, increase of coal use for electricity 

generation, along with projected startup of several coal-to-liquid (CTL) plants, should result in 

coal production growth averaging 0.2 percent per year from 2008 through 2035. This is 

significantly less than the 0.9 percent average growth rate for U.S. coal production during the 

1980 to 2008 period. It is also expected that increasingly tight pollutant emissions caps will lead 

to more use of low-sulfur coal from the Western mines. Western coal production, which has 

grown steadily since 1970, is projected to continue to increase through 2035, but at a much 

slower rate than in the past (Exhibit 3-9). (3) Both new and existing electric power plants are 

projected to be major contributors to growth in demand for Western coal. Supplies of low-cost 
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coal from the Western region are expected to satisfy most of the additional fuel needs at coalfired power plants both west and east of the Mississippi River. 

Coal production in the Interior region, which suffered a downward trend since the 1990s, is 

expected to rebound somewhat, primarily supplanting more expensive coal from Central 

Appalachia that is currently consumed at coal-fired power plants in the Southeast. Much of the 

additional output from the Interior region originates from mines tapping into the extensive 

reserves of mid- and high-sulfur bituminous coal in Illinois, Indiana, and western Kentucky. In 

addition, some of the anticipated growth in output from the Interior region results from increased 

lignite production in Texas and Louisiana. 

Total production of Appalachian region coal is projected to decline from the current levels, as 

output shifts from extensively mined, higher cost supplies to lower cost supplies from the 

Interior region and the northern part of the Appalachian basin.

Exhibit 3-9 Current and projected coal production by region (quadrillion Btu)

Source: U.S. EIA

3.5 Coal Cleaning

As-mined coal contains a mixture of different size fractions, together with unwanted impurities 

such as rock and dirt. Coal preparation (also known as beneficiation) is the stage in coal 

production when the mined coal is processed into a range of clean, graded, and uniform coal 

products suitable for the commercial market. In a few cases, the mined coal is of such quality 

that it meets the user specification without beneficiation, and it is merely crushed and screened to 

deliver the specified product. Some power plants are fed from a single source of coal, but many 

utilities buy coals from different suppliers, and some blend these in order to give a consistent 

feed to the power plant. Blending also enables selective purchasing of different grades of coal. 

More expensive, higher-quality supplies can be mixed with lower-quality coals to produce an 
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average blend suited to the plant needs, at optimum cost. Effective preparation of coal prior to 

combustion improves the homogeneity of coal supplied, reduces transport costs, improves the 

utilization efficiency, produces less ash for disposal at the power plant, and may reduce the 

emissions of oxides of sulfur. 

Few coal seams are clean enough for coal to be shipped without cleaning. Consumers typically 

require coal of consistent quality. To prepare fuel conforming to customer specifications,

practically all large, mechanized mines have preparation plants in which coal is sized and 

cleaned to the extent economically justified.

3.5.1 Nature of Coal Impurities

Coal is a heterogeneous mixture of organic and inorganic materials. Coal properties may differ 

not only from seam to seam, but also depending upon the coal location and elevation within the 

same seam. Coal impurities are typically classified as inherent and removable. 

The inherent impurities in ash-forming mineral matter are organically combined with the coal. 

Approximately 2 percent of total coal ash-forming material is considered inherent mineral 

matter. (9

Sulfur is present in the coal in three forms – pyritic sulfur (sulfur combined with iron in the form 

of pyrite), organic sulfur (sulfur combined with carbon in coal), and sulfate sulfur (sulfur in the 

form of calcium or iron sulfate). The latter usually does not exceed 0.1 percent of total sulfur.

(

) The bulk of the coal mineral matter is interstratified material which settles into the 

coal deposit as a result of water penetration during and after coal formation. Some of the mineral 

matter can be introduced into the coal during a mechanized mining process as a result of 

undesirable mixing with the overburden material. This is less likely for the larger and better strip 

mines that do not mine coal near the outcrop. The inherent impurities cannot be economically 

separated from the coal during coal preparation while removable impurities can be segregated 

and removed using cleaning methods. 

9) The larger pieces of pyritic sulfur can be removed with mineral matter using coal cleaning 

methods. Fines of the pyritic sulfur and organic sulfur cannot be economically removed using 

modern cleaning methods. 

3.5.2 Cleaning Methods

Most mechanical cleaning processes depend on differences in specific gravity of coal and 

impurities to facilitate separation. Typically, most common solid impurities are heavier than 

coal and can be removed by gravity concentration. The cleaning process may be wet or dry, with 

either water or air used as a medium. In general, wet processes are more efficient; however, 

determination of which process is more suitable for a specific coal depends upon the coal 

washability characteristics, i.e., properties of the various specific gravity fractions and the

variations of these properties with coal sizing. The most frequently used wet methods are (9): 

Jigs - Pulsating currents of water pass through a bed of coal resting on a 

screen plate. The upward flow, called “pulsion stroke,” fluidizes the 

coal, and the subsequent downward flow, called “suction stroke,” 

settles the bed. While coal particles are in suspension they are 

separated into fractions and diverted into separate streams.
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Dense-Media Method - Coal is immersed in a medium with specific gravity intermediate 

between that of coal and impurities. The impurities sink, and the coal 

floats. 

Concentration tables - This method is primarily used for washing fine coal (50 mesh sizing)

Only a small percentage of the total coal is cleaned by pneumatic (dry) process in the U.S. It is 

typically applied to the coal less than 1⁄2 inch in size. The raw coal may be screened upstream 

from the cleaning plant with larger fractions directed to the wet process and smaller to the 

pneumatic process. In pneumatic processes, air is blown upward through the bed of coal resting 

on a moving table equipped with riffles. The air flow segregates coal and impurities by bringing 

particles with lower specific gravity (mostly coal) to the top of the bed. Low gravity particles 

then move across the table in direction perpendicular to the riffles. The heavy particles (mostly 

impurities) settle in the riffles and move along the riffles, discharging at the end opposite to the 

coal feed. Fines suspended in the air are recovered in cyclone separators and/or bag filters. 

3.5.3 Special Treatment Methods

De-dusting - De-dusting is the process of coal fines removal using air separation. It 

is often utilized to remove fines ahead of wet cleaning. De-dusting is 

accomplished by passing an air stream through the coal with 

subsequent fine coal recovery in cyclone separators and bag filters. 

The fines may be added to clean coal (if low in ash) or disposed of with 

the impurities.

Dewatering - Larger size coal (above 3/8 inch) can be dewatered using gravity with

special hoppers and bins with drainage, screen conveyors, or perforated 

bucket elevators. 

When fine sizes need to be dried, or lower moisture content is required,

mechanical dewatering or thermal drying is utilized. Mechanical 

dewatering devices include shaker or vibrating screens, centrifuges, and 

thickening equipment. Thermal dryers are of fluidized bed, rotary, 

cascade, reciprocating screen, and conveyer type. All thermal dryers 

require dust collection to recover fines, which may be centrifugal 

cyclones, bag filters, or water-spray systems. Thermal drying is 

predominantly used for obtaining low moisture content, fine-size coal. 

Dust proofing - Dust proofing is accomplished by spraying oil and calcium chloride on 

streams of coal falling from chutes or loading booms. When coal is 

sprayed by oil, the film causes dust particles to adhere to the larger 

pieces or to agglomerate into larger lumps. About 13 percent of 

cleaned bituminous coal is sprayed by oil. (9) Sometimes coal is 

sprayed with oil and calcium chloride. Calcium chloride absorbs 

moisture from the air, providing a wet surface to which dust adheres. 
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Freeze proofing - Freeze proofing is used to prevent coal from freezing during 

transportation and storage. The most commonly used method is spray 

oil application, the same as dust proofing. Sometimes the railroad car 

hoppers are sprayed to ease coal unloading at the final destination. 

Less often freeze proofing is accomplished by thermal drying the fine 

coal, especially for high moisture content, low-rank coal. 
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4 Definition of Coal Specifications

4.1 ASTM Classification by Rank

Coal is a heterogeneous substance, with wide variability in composition. A system used for 

classifying coals was established by the American Society for Testing and Materials (ASTM), 

Exhibit 4-1. (9) The ASTM D388 classification system uses volatile matter and fixed carbon 

content in the proximate analysis along with the heating value of the coal to establish the coal 

rank. This ranking system provides basic information that assists in making judgments about the 

combustion properties and the commercial uses of the various types of coal.

4.2 Proximate Analysis

The proximate analysis (percent by weight) gives information on coal behavior when it is heated, 

e.g., how much coal goes off as gas, tar, and vapor, and how much remains as fixed carbon. The 

proximate analysis is described by ASTM Standard D3172. This determines volatile matter, 

fixed carbon, and ash. The quantity of volatile matter indicates ease of ignition of a coal and 

whether supplemental flame stabilization is needed.

4.3 Ultimate Analysis

The ultimate analysis (percent by weight) gives the coal composition by constituent elements. 

The ultimate analysis is described by ASTM Standard D3176. This establishes the quantities of 

carbon, hydrogen, nitrogen, and sulfur content in the coal, as well as the calculated oxygen 

content. The ultimate analysis is utilized for combustion calculations.

4.4 Higher and Lower Heating Value

The heat of combustion is usually determined by direct calorimeter measurements of the heat 

evolved. Heating value is either reported as 'higher heating value’ (HHV), or as 'lower heating 

value' (LHV). The heating value of a fuel is a measure of the sensible energy released during 

combustion when both the fuel and combustion air are brought to standard conditions, the 

combustion reactions occur, and the products of combustion are brought back to standard 

conditions.

Heating value can be defined in one of two ways depending on the convention chosen for 

reporting how hydrogen energy in the fuel is released. The water vapor produced holds the heat 

of vaporization of the water. The HHV, also called gross heating value, of a fuel includes the 

heat released if all of the water vapor in the combustion products were condensed, releasing the 

heat of vaporization of the water in the combustion products. This is typically the situation that 

exists when a bomb calorimeter is used to measure the heat of combustion. The procedures for 

measuring HHV are described in ASTM Standard D5865. In the U.S., HHV is generally used in 

the coal power industry.

The LHV is the second definition frequently used to measure energy released during combustion. 

The LHV of a fuel is the heat released if all of the water vapor in the combustion products 

remained as a vapor, retaining the heat of vaporization of the water in the combustion products. 

In the U.S., LHV is generally used in the natural-gas and oil-fueled gas turbine industry, while in 

Europe LHV is typically utilized for all power industry applications.
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Exhibit 4-1 ASTM D388 classification of coals by rank

Fixed Carbon Limits, %

(Dry Mineral-Matter-Free 

Basis)

Volatile Matter Limits, %

(Dry, Mineral-Matter-Free Basis)

Calorific Value Limits, 

Btu/lb

(Moist,

b

Mineral-Matter-Free Basis)

Groupa Equal or 

Greater Than

Less 

Than Greater Than Equal or Less Than

Equal or 

Greater Than Less Than Agglomerating 

Character

Class I – Anthracitic

1. Meta-anthracite 98 -- -- 2 -- -- Non-agglomerating

2. Anthracite 92 98 2 8 -- -- Non-agglomerating

3. Semianthracitec 86 92 8 14 -- -- Non-agglomerating

Class II - Bituminous

1. Low volatile bituminous coal 78 86 14 22 -- -- Commonly 

agglomerating

2. Medium volatile bituminous coal 69 78 22 31 -- -- Commonly 

agglomerating

3. High volatile A bituminous coal -- 69 31 -- 14,000d -- Commonly 

agglomerating

4. High volatile B bituminous coal -- -- -- -- 13,000d 14,000 Commonly 

agglomerating

5. High volatile C bituminous coal -- -- -- -- 11,500 13,000 Commonly 

agglomerating

-- -- -- -- 10,500e 11,500 Agglomerating

Class III - Subbituminous

1. Subbituminous A coal -- -- -- -- 10,500 11,500 Non-agglomerating

2. Subbituminous B coal -- -- -- -- 9,500 10,500 Non-agglomerating

3. Subbituminous C coal -- -- -- -- 8,300 9,500 Non-agglomerating

Class IV - Lignitic

1. Lignite A -- -- -- -- 6,300 8,300 Non-agglomerating

2. Lignite B -- -- -- -- -- 6,300 Non-agglomerating

Notes:

a This classification does not include a few coals, principally non-banded varieties, which have unusual physical and chemical properties and which come within the limits of 

fixed carbon or calorific value of the high volatile bituminous and subbituminous ranks. All of these coals either contain less than 48 percent dry, mineral-matter-free fixed 

carbon or have more than 15,500 moist, mineral-matter-free Btu/lb.

b Moist refers to coal containing its natural inherent moisture, but not including visible water on the surface of the coal.

c If agglomerating, classify in low volatile group of the bituminous class.

d Coals having 69 percent or more fixed carbon on the dry, mineral-matter-free basis shall be classified according to fixed carbon, regardless of calorific value.

e It is recognized that there may be non-agglomerating varieties in these groups of the bituminous class, and there are notable exceptions in high volatile C bituminous group.
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4.5 Grindability

Grindability is an empirical measurement of the relative ease with which a coal can be reduced in 

size, and is described by ASTM Standard D409.

4.6 Ash Properties

A successful boiler design requires proper sizing and arrangement of the furnace and tube 

surfaces. A first priority in any design is to minimize slagging and ash deposition problems. 

The slagging and the fouling potential of the coal directly affect furnace design, having a 

significant influence on tubing spacing. Ash analyses of the expected fuel source are performed 

before undertaking any boiler design, using ash prepared according to ASTM D3174.

• The slagging potential of ash is the tendency to form fused deposits on tube surfaces 

exposed to high temperature radiant heat. 

• The fouling potential is the tendency of ash to bond to lower temperature convection 

surfaces.

4.7 Ash Fusion Characteristics

Many comparisons of chemical makeup have been developed to analyze the behavior of ash in 

boilers. Empirical testing of ash-fusion temperature is still the most basic way of predicting 

slagging and fouling-fusion temperature. This testing is prescribed in ASTM D1857. The test 

consists of observing the gradual thermal deformation (melting) of a pyramid-shaped ash sample 

and recording the initial deformation temperature (IT), softening temperature (ST), 

hemispherical temperature (HT), and fluid temperature (FT). The stages at which these 

temperatures are recorded are generally measured under reducing and oxidizing conditions.

4.8 Trace Elements

All coals contain trace elements, albeit in very small quantities, that are measured in parts per 

million. Typically, most trace elements in coal occur in abundances not greatly different from 

those in rock making up the crust of the earth, with the exception of boron, chlorine, and 

selenium. The 1990 Amendments to the Clean Air Act listed a number of minor and trace 

elements that commonly occur in coal as “hazardous air pollutants” (HAP). 

Mercury is the element of greatest immediate concern because it is emitted from the plant stack,

and limiting legislation is due to be finalized in November, 2011. Deposits containing high 

enough concentrations of arsenic and selenium to be of concern have been observed starting in 

low temperature gas cooling all the way through the boiler or heat recovery steam generator 

(HRSG). Air emissions of lead have been regulated by some states.

4.9 Coal Moisture

All coals contain moisture. Total moisture of a coal is comprised of surface moisture and 

inherent moisture. Inherent moisture is a quality of the coal seam in its natural state of 

deposition and includes only that water considered to be part of the deposit, and not that moisture 

which exists as a surface addition. Surface moisture is the water from external sources, such as 

weather or coal washing processes. The standard test method for total moisture in coal is defined 

in ASTM D3302.
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The moisture content of coals varies widely by rank. In the high-rank, low volatile bituminous 

coals it is frequently under 5 percent. High volatile bituminous coals may have as much as 12 

percent moisture and lignite, and as high as 45 percent as mined. (10) Coal as mined, shipped,

and received may also contain varying amounts of water due to gain or loss in coal treatment 

processes, transportation, and storage. Depending on moisture in a coal and the technology 

applied, the coal may need to be dried before use. For instance, coals entering dry-feed gasifiers 

typically need to be dried to achieve appropriate gasification temperature and reduce system 

thermal loss.
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5 Coal Types Used in the Previous System Studies

A list of coal types utilized in the energy system studies completed since 2004 is tabulated in 

Exhibit 5-1. High volatile bituminous coals (such as Illinois No. 6 and Pittsburgh No. 8) have 

been utilized in multiple studies. Subbituminous coals from the Powder River Basin as well as 

North Dakota lignite are also relatively well represented. There were no system studies 

completed since 2004 that considered low volatile bituminous, medium volatile bituminous or

“super-compliance” subbituminous coal as a design fuel. 

While most of the records include a proximate analysis, an ultimate analysis, and coal heating 

value, a few also contain ash composition and fusion temperatures, grindability index, and trace 

element composition. 

Exhibit 5-1 Coal types used in past NETL system studies

Name Seam/Mine Coal Rank Notes Reports Date

ND Lignite Freedom-Beulah, 

ND

Lignite High Sodium Repowering with APFBC Series: Leland Olds

Cost and Performance for Low-Rank 

Pulverized Coal Oxycombustion Energy 

Plants

Cost and Performance Baseline for Fossil 

Energy Plants; Volume 2: Coal to Synthetic 

Natural Gas and Ammonia 

Cost and Performance Baseline for Fossil 

Energy Plants; Volume 3b: Low Rank Coal to 

Electricity : Combustion Cases

Cost and Performance Baseline for Fossil 

Energy Plants; Volume 3a: Low Rank Coal to 

Electricity : IGCC Cases

Mar-04

Oct-10

Oct-10

Mar-11

Apr-11

TX Lignite Wilcox Lignite Lignite Low Sodium

Coal analysis 

different than 

first study

Polygeneration of SNG, Hydrogen, Power, 

and Carbon Dioxide from Texas Lignite

Assessment of Alternative FutureGen Plant 

Designs, Case 7.1.3

Dec-04

Mar-06

PRB Dry Fork, WY Subbituminous Repowering with APFBC Series: Leland Olds Mar-04

PRB Wyodak Subbituminous Hydrogen Production Process Simulations Mar-05

PRB Wyodak-Anderson 

Campbell Co. WY

Subbituminous KBR transport gasifier study interim report Feb-05
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Detailed Coal Specifications January 2012

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Name Seam/Mine Coal Rank Notes Reports Date

PRB Western Energy 

Area D Rosebud 

Subbituminous Assessment of Power Plants That Meet 

Proposed Greenhouse Gas Emission 

Performance Standards

Baseline Analysis of a Coal-to-Methanol-toGasoline System

Alternative Coal Feed Strategies for IGCC 

Systems

Oct-09

Apr-10

Jul-10

Cost and Performance for Low-Rank 

Pulverized Coal Oxycombustion Energy 

Plants

Cost and Performance Baseline for Fossil 

Energy Plants; Volume 3b: Low Rank Coal to 

Electricity : Combustion Cases

Cost and Performance Baseline for Fossil 

Energy Plants; Volume 3a: Low Rank Coal to 

Electricity : IGCC Cases

Oct-10

Mar-11

Apr-11

Beluga Coal Chuitna/Beluga 

Mine

Subbituminous Beluga Coal Gasification Feasibility Study Jul-06

Healy Coal Usibelli Mine, 

Alaska

Subbituminous Alaska Coal Gasification Feasibility StudiesHealy Coal-to-Liquids PlantJul-07
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Detailed Coal Specifications January 2012

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Name Seam/Mine Coal Rank Notes Reports Date

Illinois No. 6 Old Ben No. 26 

Mine

HV Bituminous Coal and 

Trace Mineral 

Data 

Baseline Technical and Economic 

Assessment of a Commercial Scale FischerTropsch Liquids Facility

Pulverized Coal Oxycombustion Power 

Plants

Evaluation of Alternate Water Gas Shift 

Configurations for IGCC Systems

Systems Analysis of an Integrated 

Gasification Fuel Cell Combined Cycle

Cost and Performance Baseline for Fossil 

Energy Plants, Volume 4: Coal-to-FischerTropsch Liquids Using a Dry-Feed Gasifier

Cost and Performance Baseline for Fossil 

Energy Plants, Volume 1: Bituminous Coal 

and Natural Gas to Electricity, Revision 2

CO2 Capture Ready Coal Power Plants

Assessment of Hydrogen Production with 

CO2 Capture, Vol 1: Baseline State-of-the Art 

Plants

Alternative Coal Feed Strategies for IGCC 

Systems

Production of High Purity Hydrogen from 

Domestic Coal: Assessing the TechnoEconomic Impact of Emerging Technologies

Life Cycle Analysis: Existing Pulverized Coal 

Power Plant

Life Cycle Analysis: Integrated Gasification 

Combined Cycle (IGCC) Power Plant

Life Cycle Analysis: Supercritical Pulverized 

Coal (SCPC) Power Plant

Advancing Oxycombustion Technology for 

Bituminous Coal Power Plants: An R&D 

Guide

Preliminary Results of the Modified Benfield 

Process for CO2 Capture from Syngas

Ionic Liquids-Based Absorption Process for 

Warm CO2 Capture from Syngas

Apr-07

Aug-08

Aug-09

Aug-09

Sep-10

Nov-10

Apr-08

Aug-10

Jul-10

Aug-10

Sep-10

Sep-10

Dec-10

Feb-10

Mar-10

Oct-10
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Detailed Coal Specifications January 2012

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Name Seam/Mine Coal Rank Notes Reports Date

Illinois No. 6 

(cont.)

Illinois No. 6 

coal 

composition is 

different than 

QGESS

Current and Future IGCC Technologies, Vol 

1

Eliminating the Derate of Carbon Capture 

Retrofits

Greenhouse Gas Reductions in the Power 

Industry Using Domestic Coal and Biomass, 

Vol. 2: PC Plants

Dry Catalytic Reforming of Fischer-Tropsch 

Tail Gas, Rev. 1

Current and Future Technologies for 

Gasification-Based Power Generation, Vol 2

Comparison of Pratt and Whitney 

Rocketdyne IGCC and Commercial IGCC 

Performance

Oxy-Fired Pressurized Fluidized Bed 

Combustion Assessment

Industrial Size Gasification for Syngas, 

Substitute Natural Gas and Power 

Production

Oct-08

Oct-10

Jan-11

Feb-11

Nov-10

Jun-06

Sep-10

Apr-07

Pittsburgh No.

8

HV Bituminous Hydrogen Production Process Simulations Mar-05

Power Plant Water Usage and Loss Study

Technical and Economic Assessment of 

Small-Scale Fischer-Tropsch Liquids 

Facilities

May-07

Feb-07

Assessment Of Alternative FutureGen Plant 

Designs - Draft Topical Report

Apr-05

NYPA Bailey 

Clean Coal

HV A 

Bituminous

NYPA IGCC Project Site Specific Design Dec-04

Southeast 

Ohio Coal 

HV Bituminous Coal and Ash 

Data

Task 3 Gasification Plant Cost and 

Performance Optimization

May-05
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6 Typical Market Quality of Selected Coals

According to the Keystone Coal Industry Manual (11

The Form 423

), mine operators generally hold recent coal 

quality data confidential. Publicly available coal-quality data are 20 or more years old, and 72

percent of these data are from areas that are now mined out. Several public sources of typical 

market coal quality are utilized in this report. However, those sources do not yield consistent 

mine and/or seam specific data. 

1 Database (12

Average coal quality of commercially shipped coal in The Utah Geological Survey (

) contains coal quality information by coal rank and by source. 

However, the Supplier field in the Form 423 database does not provide uniform data. It may 

contain the sales company name, the mining company name, the mine name, a seam indication, 

or varying abbreviations of these depending on who completed the form. Furthermore, coal in 

Form 423 is identified by rank, but not by the seam where the coal was mined, i.e., bituminous 

coals from all regions (Appalachian, Interior, etc.) are grouped into the same category. Not all 

data fields are complete for all records.

13

Thus, the average quality of commercially shipped coal from EIA Form 423 and the Utah 

Geological Survey, presented in 

) is 

reported by state and by county, but not by the coal rank and mine. 

Exhibit 6-1 and Exhibit 6-2, can be used for indicative 

comparison only. 

 

1 The Form No. 423 is a compilation of data for cost and quality of fuels delivered to electric power plants to be 

used for determination of electric rates. Prior to 2002, the “Monthly Cost and Quality of Fuels for Electric 

Plants Database” came from FERC Form 423, and included cost information as well as Btu, sulfur, and ash 

content, but the specific supplier was not included in the FERC database. Currently the “Monthly Cost and 

Quality of Fuels for Electric Plants Database” comes from EIA Form 423 and includes supplier information as 

well as Btu, sulfur, and ash content, but the cost information is not included in the database. Both databases are 

available from the EIA website.
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Exhibit 6-1 Form 423 summary of 2001-2003 coal quality by coal type

Weighted Average, As Received

HHV, Btu/lb Sulfur, % Ash, %

Illinois No.6 11,176 2.95 8.29

PRB 8,652 0.341, 2 5.03

Texas Lignite 6,482 1.27 17.07

Notes:

1. About 49 percent of PRB supplied coal in 2003 had sulfur content not exceeding 0.3 percent

(AR, by wt); About 28 percent of PRB supplied coal in 2003 had sulfur content between 0.3

percent and 0.4 percent (AR, by wt); About 16 percent of PRB supplied coal in 2003 (all from 

the same source) had sulfur content above 0.5 percent (AR, by wt)

2. The PRB coal supply contracts appear to comprise two distinct groups. One group 

(approximately 33 percent of total tonnage) is so called “super compliance coal,” with the 

sulfur content around 0.2 percent; the second group (approximately 16 percent of total 

tonnage) is coal with relatively high sulfur content of 0.5 percent. 

Exhibit 6-2 Average quality of commercially shipped coal by state per Utah Geological Survey 

State HHV Ash Sulfur Mercury Chlorine

Btu/lb, (dry) (% dry) (% dry) (ppm dry) (ppm dry)

Illinois1 12,992 9.9 2.6 0.083 1,691

Pennsylvania1 13,089 13.2 1.9 0.258 1,048

Kentucky1 13,153 11.2 1.9 0.104 1,054

West Virginia1 13,264 12.0 1.4 0.119 1,044

Wyoming2 12,033 8.1 0.6 0.053 131

Montana2 11,633 10.0 0.8 0.070 107

North Dakota3 10,603 14.4 1.3 0.097 159

Texas3 9,332 25.5 1.6 0.125 370

Notes:

1. Coals from Illinois, Pennsylvania, Kentucky and West Virginia are predominantly high 

volatile bituminous

2. Coals from Wyoming and Montana are mostly from the Powder River Basin and 

subbituminous in rank 

3. Coals from North Dakota and Texas are mostly lignite
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7 Recommended Coal Analysis

The coal analyses recommended for the QGESS are presented in the following sections. The 

data sources, if known, are documented at the beginning of each coal rank section. Some coal 

types have been used in previous system analysis studies and the compositions presented here are 

consistent with prior modeling efforts. However, in some instances the original data source for 

those compositions is no longer known and therefore simply specified as “previous system 

studies.”

It should be noted that low volatile and medium volatile bituminous coals are mostly utilized by 

the steel industry. Combustion of these coals in wall-fired boilers may present a significant 

challenge due to their low reactivity. Regardless, recommended compositions are still provided 

for those coal types. Two options for high volatile bituminous coals, Pittsburgh No. 8 and 

Illinois No. 6, are included. There are also two options for lignite (Texas and North Dakota) and 

subbituminous coal (“super-compliance” and high [relatively] sulfur).

7.1 Low Volatile Bituminous

The low volatile bituminous coal analysis in Exhibit 7-1 is based on the Argonne Premium Coal 

Sample Database entry for coal from the Pocahontas No.3 seam. (1) The same source was used 

for the ash mineral matter analysis and the ash fusion temperatures.

Exhibit 7-1 Low volatile bituminous coal

Coal Name N/A

Coal seam nomenclature Pocahontas No.3

Mine Buchanan Co. WV

ASTM D388 Rank Low Volatile Bituminous

Proximate Analysis2,4 As-Received Dry

Moisture 0.65% 0.00%

Volatile Matter 19.14% 19.27%

Ash 4.74% 4.77%

Fixed Carbon 75.47% 75.96%

Total 100.00% 100.00%

Ultimate Analysis2,4 As-Received Dry

Carbon 86.15% 86.71%

Hydrogen 4.20% 4.23%

Nitrogen 1.26% 1.27%

Sulfur 0.66% 0.66%

Chlorine 0.19% 0.19%

Ash 4.74% 4.77%

Moisture 0.65% 0.00%

Oxygen 2.15% 2.17%

Total 100.00% 100.00%

Heating Value, Dulong calc.1,4 As-Received Dry

HHV (Btu/lb) 14,926 15,024

LHV (Btu/lb) 14,539 14,635

HHV (kJ/kg) 34,718 34,946

LHV (kJ/kg) 33,818 34,040
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Coal Name N/A

Coal seam nomenclature Pocahontas No.3

Hardgrove Grindability Index3 100 HGI

Typical Ash Mineral Analysis2

Silica SiO2 32.0%

Aluminum Oxide Al2O3 20.1%

Titanium Dioxide TiO2 1.9%

Iron Oxide Fe2O3 15.8%

Calcium Oxide CaO 12.8%

Magnesium Oxide MgO 2.0%

Sodium Oxide Na2O 2.0%

Potassium Oxide K2O 0.6%

Phosphorus Pentoxide P2O5 0.4%

Sulfur Trioxide SO3 12.4%

Undetermined 0.0%

 Total 100.00%

Typical Ash Fusion Temperatures (°F)2

Reducing

Initial - Limited deformation 2,183

Softening H=W 2,240

Hemispherical H=1/2W 2,310

Fluid 2,407

Oxidizing

Initial - Limited deformation 2,400

Softening H=W 2,414

Hemispherical H=1/2W 2,422

Fluid 2,487

Average trace element composition, dry basis, ppm

Arithmetic Mean

Standard 

Deviation

Arsenic As

Barium Ba

Boron B

Beryllium Be

Cadmium Cd

Cerium Ce

Cobalt Co

Chromium Cr

Copper Cu

Gallium Ga

Germanium Ge

Lanthanum La

Lead Pb

Lithium Li

Manganese Mn

Mercury5,6 Hg 0.079 0.009

Molybdenum Mo

Neodymium Nd
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Coal Name N/A

Coal seam nomenclature Pocahontas No.3

Average trace element composition, dry basis, ppm

(continued)

Arithmetic Mean

Standard 

Deviation

Nickel Ni

Niobium Nb

Phosphorus P

Thorium Th

Tin Sn

Selenium Se

Scandium Sc

Silver Ag

Strontium Sr

Uranium U

Vanadium V

Ytterbium Yb

Yttrium Y

Zirconium Zr

Zinc Zn

Notes:

1. Calculated Dulong as-received HHV is 14,998 Btu/lb, dry basis is 15,096 Btu/lb

2. Proximate analysis, ultimate analysis, mineral matter analysis and ash fusion temperatures are 

per the Argonne Premium Coal Sample Database (1)

3. Ash analysis and Hardgrove Grindability Index are based on typical values per reference (9)

4. This coal type has not been used in previous energy system studies

5. The mercury concentration was determined from 105 records of the EPA Information Collection 

Request (ICR) database

6. In previous system studies, coal mercury values were the mean plus one standard deviation
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7.2 Medium Volatile Bituminous

The medium volatile bituminous coal analysis in Exhibit 7-2 is based on the Argonne Premium 

Coal Sample Database for the Upper Freeport coal seam. This analysis is consistent with the 

average quality of commercially shipped coal from Indiana County, Pennsylvania. (13)

Exhibit 7-2 Medium volatile bituminous coal

Coal Name N/A

Coal seam nomenclature Upper Freeport

Mine Indiana Co, PA

ASTM D388 Rank Mid Volatile Bituminous

Proximate Analysis2,4 As-Received Dry

Moisture 1.13% 0.00%

Volatile Matter 29.43% 29.77%

Ash 13.03% 13.18%

Fixed Carbon 56.41% 57.05%

Total 100.00% 100.00%

Ultimate Analysis2,4 As-Received Dry

Carbon 73.39% 74.23%

Hydrogen 4.03% 4.07%

Nitrogen 1.33% 1.35%

Sulfur 2.29% 2.32%

Chlorine 0.00% 0.00%

Ash 13.03% 13.18%

Moisture 1.13% 0.00%

Oxygen 4.80% 4.85%

Total 100.00% 100.00%

Heating Value, Dulong calc.1,4 As-Received Dry

HHV (Btu/lb) 13,315 13,467

LHV (Btu/lb) 12,944 13,092

HHV (kJ/kg) 30,971 31,324

LHV (kJ/kg) 30,108 30,451

Hardgrove Grindability Index3 95 HGI
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Coal Name N/A

Coal seam nomenclature Upper Freeport

Typical Ash Mineral Analysis2

Silica SiO2 44.8%

Aluminum Oxide Al2O3 24.1%

Titanium Dioxide TiO2 1.3%

Iron Oxide Fe2O3 17.3%

Calcium Oxide CaO 4.2%

Magnesium Oxide MgO 1.6%

Sodium Oxide Na2O 0.0%

Potassium Oxide K2O 2.7%

Phosphorus Pentoxide P2O5 0.1%

Sulfur Trioxide SO3 3.9%

Undetermined 0.0%

 Total 100.00%

Typical Ash Fusion Temperatures (°F)2, 7

Reducing

Initial - Limited deformation 2,191

Softening H=W 2,250

Hemispherical H=1/2W 2,321

Fluid 2,433

Oxidizing

Initial - Limited deformation 2,140

Softening H=W 2,170

Hemispherical H=1/2W 2,200

Fluid 2,225

Average trace element composition, dry basis, ppm

Arithmetic Mean

Standard 

Deviation

Antimony Sb

Arsenic As

Barium Ba

Boron B

Beryllium Be

Cadmium Cd

Cerium Ce

Cobalt Co

Chromium Cr

Copper Cu

Fluorine F

Gallium Ga

Germanium Ge

Lanthanum La

Lead Pb

Lithium Li

Manganese Mn

Mercury5,6 Hg 0.238 0.099

Molybdenum Mo

Neodymium Nd

Nickel Ni

Niobium Nb

Phosphorus P
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Coal Name N/A

Coal seam nomenclature Upper Freeport

Thorium Th

Tin Sn

Selenium Se

Scandium Sc

Silver Ag

Strontium Sr

Uranium U

Vanadium V

Ytterbium Yb

Yttrium Y

Zirconium Zr

Zinc Zn

Notes:

1. Calculated Dulong as-received HHV is 12,897 Btu/lb, dry basis is 13,044 Btu/lb

2. Proximate analysis, ultimate analysis, ash mineral matter analysis, and ash fusion temperatures

are per Argonne Premium Coal Sample Database

3. Hardgrove Grindability Index is per reference (9)

4. This coal type has not been used in previous energy system studies

5. The mercury concentration was determined from 396 records of EPA Information Collection 

Request (ICR) database

6. In previous system studies, coal mercury values were the mean plus one standard deviation

7. Oxidizing ash fusion temperatures are generally higher than reducing, but these data are as 

reported by the Argonne Premium Coal Sample Database

7.3 High Volatile Bituminous

Pittsburgh No. 8 coal has been used in several past system studies as documented in Exhibit 5-1. 

However, the properties were fairly similar to Illinois No. 6 coal. To represent high volatile

bituminous coals with a relatively large deviation in heating value, a new Pittsburgh No. 8 coal 

analysis, extracted from the U.S. Geological Survey Database (14

Exhibit 7-3

), is presented. The coal 

analysis is shown in .

Exhibit 7-3 High volatile bituminous coal analysis (Pittsburgh No.8)

Coal name Pittsburgh No. 8 

Coal seam nomenclature N/A

Mine N/A

ASTM D388 Rank High Volatile A Bituminous

Proximate Analysis2,3 As-Received Dry

Moisture4 2.63% 0.00%

Volatile Matter 35.82% 36.79%

Ash 9.17% 9.42%

Fixed Carbon 52.38% 53.79%

Total 100.00% 100.00%
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Coal name Pittsburgh No. 8 

Ultimate Analysis2,3 As-Received Dry

Carbon 73.15% 75.13%

Hydrogen 4.97% 5.10%

Nitrogen 1.46% 1.50%

Sulfur 2.36% 2.42%

Chlorine 0.04% 0.04%

Ash 9.17% 9.42%

Moisture 2.63% 0.00%

Oxygen 6.22% 6.39%

Total 100.00% 100.00%

Reported Heating Value1,2,3 As-Received Dry

HHV (Btu/lb) 13,116 13,470

LHV (Btu/lb) 12,658 13,000

HHV (kJ/kg) 30,508 31,331

LHV (kJ/kg) 29,443 30,238

Hardgrove Grindability Index2 73 HGI

Typical Ash Mineral Analysis2

Silica SiO2 41.80%

Aluminum Oxide Al2O3 22.30%

Titanium Dioxide TiO2 1.03%

Iron Oxide Fe2O3 22.76%

Calcium Oxide CaO 3.20%

Magnesium Oxide MgO 0.70%

Sodium Oxide Na2O 0.48%

Potassium Oxide K2O 1.51%

Phosphorus Pentoxide P2O5 0.37%

Sulfur Trioxide SO3 2.87%

Undetermined 2.94%

Total 100.0%

Typical Ash Fusion Temperatures (°F)

Reducing

Initial – Limited deformation oF 2,260

Softening H=W oF 2,350

Hemispherical H=1/2W oF

Fluid oF 2,430

Oxidizing

Initial – Limited deformation oF

Softening H=W oF

Hemispherical H=1/2W oF

Fluid oF

Average trace element composition of selected coal samples, dry basis, ppm2

Arithmetic

Mean

Standard 

Deviation

Arsenic As 996 749

Boron B 42 15

Beryllium Be 1.2 0.7

Cadmium Cd 0.08 0.06
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Detailed Coal Specifications January 2012

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Coal name Pittsburgh No. 8 

Chlorine Cl 457 367

Cobalt Co 4.0 2.6

Chromium Cr 14.0 6.0

Copper Cu 7.1 3.5

Fluorine F 75.0 105

Mercury5 Hg 0.23 0.20

Lithium Li 12.9 7.9

Manganese Mn 19.8 13.3

Molybdenum Mo 2.7 2.6

Nickel Ni 11.1 6.5

Phosphorus P 181 221

Lead Pb 4.3 2.6

Tin Sn 0.6 0.5

Selenium Se 1.4 0.8

Thorium Th 1.8 0.7

Uranium U 0.9 1.0

Vanadium V 16.0 8.0

Zinc Zn 12.6 8.5

Notes:

1. Calculated Dulong HHV, As-Received – 13,335 Btu/lb, Dry – 13,695 Btu/lb

2. Proximate analysis, ultimate analysis, HHV, ash mineral analysis, Hardgrove Grindability Index, 

ash fusion temperature and trace element composition were average values based on 46 

Pittsburgh formation coal samples extracted from the USGS database (14)

3. This analysis is different than Pittsburgh No. 8 coal analyses that were used in past system 

studies

4. In previous system studies, this coal was dried to 2.5 percent moisture for dry-feed gasifiers

5. In previous system studies, mercury values for coal analyses were the mean plus one standard 

deviation

The coal analysis from the Old Ben Mine No. 26 has been utilized in several major studies, 

including multiple revisions of Volume 1 of the Cost and Performance Baseline Report. (15) The 

coal quality in this guideline is consistent with the commercial offerings for the high volatile 

bituminous rank coal and coals shipped from the state of Illinois. The composition documented 

in this guideline has been reported previously in other studies dating back to 1996. (16

Exhibit 7-4

) The

high volatile bituminous coal analysis (Illinois No. 6) is presented in .

Exhibit 7-4 High volatile bituminous coal analysis (Illinois No. 6)

Coal name Illinois No. 6 

Coal seam nomenclature Herrin (No. 6)

Mine N/A

ASTM D388 Rank High Volatile A Bituminous

Proximate Analysis6 As-Received Dry

Moisture7 11.12% 0.00%

Volatile Matter 34.99% 39.37%

Ash 9.70% 10.91%

Fixed Carbon 44.19% 49.72%

Total 100.00% 100.00%
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Coal name Illinois No. 6 

Ultimate Analysis6 As-Received Dry

Carbon 63.75% 71.72%

Hydrogen 4.50% 5.06%

Nitrogen 1.25% 1.41%

Sulfur 2.51% 2.82%

Chlorine 0.29% 0.33%

Ash 9.70% 10.91%

Moisture7 11.12% 0.00%

Oxygen 6.88% 7.75%

Total 100.00% 100.00%

Reported Heating Value1,6 As-Received Dry

HHV (Btu/lb) 11,666 13,126

LHV (Btu/lb) 11,252 12,712

HHV (kJ/kg) 27,113 30,506

LHV (kJ/kg) 26,151 29,444

Hardgrove Grindability Index 60 HGI

Typical Ash Mineral Analysis2

Silica SiO2 45.0%

Aluminum Oxide Al2O3 18.0%

Titanium Dioxide TiO2 1.0%

Iron Oxide Fe2O3 20.0%

Calcium Oxide CaO 7.0%

Magnesium Oxide MgO 1.0%

Sodium Oxide Na2O 0.6%

Potassium Oxide K2O 1.9%

Phosphorus Pentoxide P2O5 0.2%

Sulfur Trioxide SO3 3.5%

Undetermined 1.8%

Total 100.0%

Typical Ash Fusion Temperatures (°F) 3

Reducing

Initial – Limited deformation 2,194 oF

Softening H=W 2,260 oF

Hemispherical H=1/2W 2,345 oF

Fluid 2,415 oF

Oxidizing

Initial – Limited deformation 2,250 oF

Softening H=W 2,300 oF

Hemispherical H=1/2W 2,430 oF

Fluid 2,450 oF

Average trace element composition of coal shipped by Illinois mines, dry basis, ppm4

Arithmetic

Mean

Standard 

Deviation

Arsenic As 7.5 8.1

Boron B 90 45

Beryllium Be 1.2 0.7

Cadmium Cd 0.5 0.9
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Coal name Illinois No. 6 

Chlorine Cl 1671 1189

Cobalt Co 3.5 1.3

Chromium Cr 14 6

Copper Cu 9.2 2.5

Fluorine F 93 36

Mercury5 Hg 0.09 0.06

Lithium Li 9.4 7.1

Manganese Mn 38 32

Molybdenum Mo 8.4 5.7

Nickel Ni 14 5

Phosphorus P 87 83

Lead Pb 24 21

Tin Sn 0.9 0.7

Selenium Se 1.9 0.9

Thorium Th 1.5 0.4

Uranium U 2.2 1.9

Vanadium V 31 16

Zinc Zn 84.4 84.2

Notes:

1. Calculated Dulong HHV, As-Received - 11,634 Btu/lb, Dry - 13,089 Btu/lb

2. Typical ash mineral analysis is based on Combustion Technologies Composition Source Book, 

May, 2005

3. Reducing condition ash fusion temperature data are from source (16), and oxidizing condition 

typical ash fusion temperature data are based on the Combustion Technologies Composition 

Source Book, May, 2005

4. Average trace element composition of coal shipped by Illinois mines is based on 34 samples, 

2004 Keystone Coal Industry Manual (11)

5. A mercury value of 0.15 ppm was used for Illinois No. 6 in previous system studies, which is the 

mean plus one standard deviation

6. The system studies using this coal type are documented in Exhibit 5-1

7. In previous system studies this coal was dried to 5 percent or 6 percent moisture for dry-feed 

gasifiers
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7.4 “Super-Compliance” Subbituminous PRB Coal

“Super-compliance” subbituminous coal analysis is based on a coal sample reported by the 

Sheldon Station power plant for an energy system study conducted in 2003 (17

Exhibit 7-5

), and is presented 

in .

Exhibit 7-5 “Super-compliance” subbituminous coal analysis

Coal name PRB

Coal seam nomenclature Wyodak/Anderson

Mine Rochelle Coal Co.

ASTM D388 Rank Subbituminous C

Proximate Analysis5 As-Received Dry

Moisture 27.42% 0.00%

Volatile Matter 31.65% 43.61%

Ash 4.50% 6.20%

Fixed Carbon 36.43% 50.19%

Total 100.00% 100.00%

Ultimate Analysis5 As-Received Dry

Carbon 50.23% 69.21%

Hydrogen 3.41% 4.70%

Nitrogen 0.65% 0.89%

Sulfur 0.22% 0.30%

Chlorine 0.02% 0.03%

Ash 4.50% 6.20%

Moisture 27.42% 0.00%

Oxygen 13.55% 18.67%

Total 100.00% 100.00%

Heating Value2,5

As-Received 

(Reported)

Dry 

(Dulong calc.)

HHV (Btu/lb) 8,800 11,546

LHV (Btu/lb) 8,486 11,113

HHV (kJ/kg) 20,469 26,856

LHV (kJ/kg) 19,738 25,850

Hardgrove Grindability Index 52 HGI
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Coal name PRB

Coal seam nomenclature Wyodak/Anderson

Ash Mineral Analysis

Silica SiO2 33.40%

Aluminum Oxide Al2O3 16.30%

Titanium Dioxide TiO2 1.20%

Iron Oxide Fe2O3 5.20%

Calcium Oxide CaO 21.50%

Magnesium Oxide MgO 6.40%

Sodium Oxide Na2O 1.90%

Potassium Oxide K2O 0.35%

Phosphorus Pentoxide P2O5 1.20%

Sulfur Trioxide SO3 11.70%

Barium Oxide Ba2O 0.56%

Strontium Oxide SrO 0.27%

Manganese Dioxide MnO2 0.02%

Total 100.00%

Ash Fusion Temperatures (°F)

Reducing

Initial - Limited deformation 2,170 oF

Softening H=W 2,190 oF

Hemispherical H=1/2W 2,200 oF

Fluid 2,230 oF

Oxidizing

Initial - Limited deformation 2,200 oF

Softening H=W 2,220 oF

Hemispherical H=1/2W 2,250 oF

Fluid 2,290 oF

Trace element composition, dry basis, ppm1,3

Reported WY Average

Antimony Sb 0.62 <0.4

Arsenic As 1.5 <3

Barium Ba N/A 300

Boron B 43 70

Beryllium Be 0.4 N/A

Cadmium Cd 0.56 <0.15

Cerium Ce N/A <20

Cobalt Co N/A 2

Chromium Cr 6 7

Copper Cu 12 8

Fluorine F 76 N/A

Gallium Ga N/A 3

Germanium Ge N/A <2

Lanthanum La N/A <7

Lead Pb 5 <3

Lithium Li N/A 4.6

Manganese Mn 9 N/A

Mercury4 Hg 0.1 0.1

Molybdenum Mo N/A 1

Neodymium Nd N/A <15

Nickel Ni 5 5

Niobium Nb N/A 1.5
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Coal name PRB

Coal seam nomenclature Wyodak/Anderson

Phosphorus P N/A N/A

Thorium Th N/A 2.7

Tin Sn N/A N/A

Selenium Se 0.3 <0.8

Scandium Sc N/A 1.5

Silver Ag 0.24 N/A

Strontium Sr N/A 100

Uranium U N/A <0.9

Vanadium V 17 15

Ytterbium Yb N/A 0.5

Yttrium Y N/A 5

Zirconium Zr N/A 15

Zinc Zn 8 17.9

Notes:

1. N/A = not available

2. Calculated Dulong HHV As-Received - 8,380 Btu/lb

3. Average trace element composition found in Wyoming coals is based on 48 published analyses in 

the 2004 Keystone Coal Industry Manual (11)

4. Mercury values for other coal analyses used in previous system studies were the mean plus one 

standard deviation

5. The system studies using this coal type are documented in Exhibit 5-1

7.5 Subbituminous

The subbituminous coal analysis in Exhibit 7-6 represents a relatively smaller group of PRB 

coals with sulfur content higher than 0.5 percent. The original source of the composition data is 

not known, but it is very close to the composition reported for Wyoming coal in the Argonne 

Premium Coal Sample Database. (1)

Exhibit 7-6 Subbituminous coal from PRB field

Coal seam nomenclature Montana Rosebud

Coal field PRB, Area D

Mine Western Energy Co.

ASTM D388 Rank Subbituminous

Proximate Analysis2 As-Received Dry

Moisture3 25.77% 0.00%

Volatile Matter 30.34% 40.87%

Ash 8.19% 11.04%

Fixed Carbon 35.70% 48.09%

Total 100.00% 100.00%
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Coal seam nomenclature Montana Rosebud

Coal field PRB, Area D

Ultimate Analysis2 As-Received Dry

Carbon 50.07% 67.45%

Hydrogen 3.38% 4.56%

Nitrogen 0.71% 0.96%

Sulfur 0.73% 0.98%

Chlorine 0.01% 0.01%

Ash 8.19% 11.03%

Moisture3 25.77% 0.00%

Oxygen 11.14% 15.01%

Total 100.00% 100.00%

Heating Value1,2 As-Received

Dry (Dulong 

calc.)

HHV (Btu/lb) 8,564 11,516

LHV (Btu/lb) 8,252 11,096

HHV (kJ/kg) 19,920 26,787

LHV (kJ/kg) 19,195 25,810

Hardgrove Grindability Index 57

Ash Mineral Analysis

Silica SiO2 38.09%

Aluminum Oxide Al2O3 16.73%

Titanium Dioxide TiO2 0.72%

Iron Oxide Fe2O3 6.46%

Calcium Oxide CaO 16.56%

Magnesium Oxide MgO 4.25%

Sodium Oxide Na2O 0.54%

Potassium Oxide K2O 0.38%

Phosphorus Pentoxide P2O5 0.35%

Sulfur Trioxide SO3 15.08%

Barium Oxide Ba2O 0.00%

Strontium Oxide SrO 0.00%

Unknown MnO2 0.84%

Total 100.00%

Ash Fusion Temperatures (°F)

Reducing

Initial - Limited deformation 2,238 oF

Softening H=W 2,254 oF

Hemispherical H=1/2W 2,270 oF

Fluid 2,298 oF

Oxidizing

Initial - Limited deformation 2,284 oF

Softening H=W 2,301 oF

Hemispherical H=1/2W 2,320 oF

Fluid 2,367 oF
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Coal seam nomenclature Montana Rosebud

Coal field PRB, Area D

Trace element composition, dry basis, ppm

Reported WY Average

Antimony Sb

Arsenic As

Barium Ba

Boron B

Beryllium Be

Cadmium Cd

Cerium Ce

Cobalt Co

Chromium Cr

Copper Cu

Fluorine F

Gallium Ga

Germanium Ge

Lanthanum La

Lead Pb

Lithium Li

Manganese Mn

Mercury4 Hg 0.056 0.025

Molybdenum Mo

Neodymium Nd

Nickel Ni

Niobium Nb

Phosphorus P

Trace element composition, dry basis, ppm

(continued)

Reported WY Average

Thorium Th

Tin Sn

Selenium Se

Scandium Sc

Silver Ag

Strontium Sr

Uranium U

Vanadium V

Ytterbium Yb

Yttrium Y

Zirconium Zr

Zinc Zn

Notes:

1. Calculated Dulong HHV As-Received - 8,548 Btu/lb

2. The system studies using this coal type are documented in Exhibit 5-1

3. In previous system studies, this coal was dried to 5 percent moisture for dry-feed gasifiers

4. In previous system studies, mercury values used for coals were the mean plus one standard 

deviation
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7.6 North Dakota Lignite

The North Dakota lignite analysis is based on a coal sample reported by the Leland Olds plant 

for a 2004 system analysis study (18), and is presented in Exhibit 7-7.

Exhibit 7-7 North Dakota lignite analysis (high-sodium)

Coal name High Sodium Lignite

Coal seam nomenclature Beulah-Zap

Mine Freedom, ND

ASTM D388 Rank Lignite A

Proximate Analysis5 As-Received Dry

Moisture 36.08% 0.00%

Volatile Matter 26.52% 41.48%

Ash 9.86% 15.43%

Fixed Carbon 27.54% 43.09%

Total 100.00% 100.00%

Ultimate Analysis5 As-Received Dry

Carbon 39.55% 61.88%

Hydrogen 2.74% 4.29%

Nitrogen 0.63% 0.98%

Sulfur 0.63% 0.98%

Chlorine 0.00% 0.00%

Ash 9.86% 15.43%

Moisture 36.08% 0.00%

Oxygen 10.51% 16.44%

Total 100.00% 100.00%

Heating Value2,5 As-Received

Dry (Dulong 

calc.)

HHV (Btu/lb) 6,617 10,427

LHV (Btu/lb) 6,364 10,032

HHV (kJ/kg) 15,391 24,254

LHV (kJ/kg) 14,804 23,335

Hardgrove Grindability Index Not applicable
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Coal name High Sodium Lignite

Ash Mineral Analysis

Silica SiO2 35.06%

Aluminum Oxide Al2O3 12.29%

Titanium Dioxide TiO2 0.58%

Iron Oxide Fe2O3 5.12%

Calcium Oxide CaO 14.39%

Magnesium Oxide MgO 6.61%

Sodium Oxide Na2O 5.18%

Potassium Oxide K2O 0.64%

Phosphorus Pentoxide P2O5 0.00%

Sulfur Trioxide SO3 16.27%

Barium Oxide Ba2O 0.56%

Strontium Oxide SrO 0.27%

Manganese Dioxide MnO2 0.02%

Unknown 3.00%

Total 100.00%

Ash Fusion Temperatures (°F)6

Reducing

Initial - Limited deformation 2,045 oF

Softening H=W 2,085 oF

Hemispherical H=1/2W 2,125 oF

Fluid 2,165 oF

Oxidizing

Initial - Limited deformation 2,125 oF

Softening H=W 2,155 oF

Hemispherical H=1/2W 2,190 oF

Fluid 2,215 oF

Trace element composition, dry basis, ppm3

As Reported1

Antimony Sb N/A

Arsenic As 67

Barium Ba 7000

Boron B 1590

Beryllium Be N/A

Cadmium Cd 0.89

Cerium Ce N/A

Cobalt Co N/A

Chromium Cr 29

Copper Cu 50

Fluorine F N/A

Gallium Ga N/A

Germanium Ge N/A

Lanthanum La N/A

Lead Pb 38.7

Lithium Li N/A

Manganese Mn N/A

Mercury4 Hg 0.116 

Molybdenum Mo N/A

Neodymium Nd N/A

Nickel Ni 27

Niobium Nb N/A
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Coal name High Sodium Lignite

Phosphorus P N/A

Trace element composition, dry basis, ppm

(continued)

As Reported

Thorium Th N/A

Tin Sn N/A

Selenium Se 11

Scandium Sc N/A

Silver Ag N/A

Strontium Sr N/A

Uranium U N/A

Vanadium V 77.2

Ytterbium Yb N/A

Yttrium Y N/A

Zirconium Zr N/A

Zinc Zn 73.8

Notes:

1. N/A = not available

2. Calculated Dulong HHV As-Received – 6,665 Btu/lb

3. Trace element composition is as reported in the sample 

4. Mercury value is the mean (0.081 ppm) plus one standard deviation (0.035 ppm) of selected 

samples from the EPA Information Collection Request database

5. The system studies using this coal type are documented in Exhibit 5-1

6. Ash fusion temperatures are the midpoint of a range
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7.7 Texas Lignite

Texas lignite was used in several energy system studies since 2004. (19, 20

11

) The coal 

composition used in the two studies was not consistent. The coal analysis presented in the 

QGESS does not exactly match either study composition, but is based on mean values of the 

Texas Wilcox Group lignite coals from the 2004 Keystone Coal Industry Manual. ( ) The

Keystone Coal reference provided values closest to the weighted average Texas lignite values for 

the coals sold on the U.S. market (Exhibit 6-1), and are also very close to the FutureGen study 

composition. (19) Ash of Wilcox Group lignite contains less than 1 percent sodium. Thus, both 

low-sodium and high-sodium lignite (ND lignite) are represented in the QGESS. The Texas 

lignite analysis is presented in Exhibit 7-8.

Exhibit 7-8 Texas lignite analysis (low-sodium)

Coal seam nomenclature Wilcox Group

Coal name Mean Values

Mine TX

ASTM D388 Rank Lignite

Proximate Analysis1,3 As-Received Dry

Moisture 32.00% 0.00%

Volatile Matter 28.00% 41.18%

Ash 15.00% 22.06%

Fixed Carbon 25.00% 36.76%

Total 100.00% 100.00%

Ultimate Analysis1,3 As-Received Dry

Carbon 37.70% 55.44%

Hydrogen 3.00% 4.41%

Nitrogen 0.70% 1.03%

Sulfur 0.90% 1.32%

Chlorine 0.02% 0.03%

Ash 15.00% 22.06%

Moisture 32.00% 0.00%

Oxygen 10.68% 15.71%

Total 100.00% 100.00%

Heating Value, Dulong calc. 3 As-Received Dry

HHV (Btu/lb) 6,554 9,638

LHV (Btu/lb) 6,277 9,231

HHV (kJ/kg) 15,243 22,417

LHV (kJ/kg) 14,601 21,472

Hardgrove Grindability Index 60 HGI
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Coal seam nomenclature Wilcox Group

Typical Ash Mineral Analysis

Silica SiO2 44.10%

Aluminum Oxide Al2O3 15.03%

Titanium Dioxide TiO2 1.03%

Iron Oxide Fe2O3 8.96%

Calcium Oxide CaO 11.91%

Magnesium Oxide MgO 2.67%

Sodium Oxide Na2O 0.70%

Potassium Oxide K2O 0.78%

Phosphorus Pentoxide P2O5 0.00%

Sulfur Trioxide SO3 11.77%

Undetermined 3.05%

Total 100.00%

Typical Ash Fusion Temperatures (°F) 2

Reducing

Initial - Limited deformation 2,152

Softening H=W 2,260

Hemispherical H=1/2W 2,248

Fluid 2,362

Oxidizing

Initial - Limited deformation

Softening H=W

Hemispherical H=1/2W

Fluid

Average trace element composition, dry basis, ppm

Arithmetic Mean

Standard 

Deviation

Antimony Sb

Arsenic As

Barium Ba

Boron B

Beryllium Be

Cadmium Cd

Cerium Ce

Cobalt Co

Chromium Cr

Copper Cu

Fluorine F

Gallium Ga

Germanium Ge

Lanthanum La

Lead Pb

Lithium Li

Manganese Mn

Mercury4 Hg 0.148 0.058

Molybdenum Mo

Neodymium Nd

Nickel Ni

Niobium Nb

Phosphorus P

Thorium Th
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Coal seam nomenclature Wilcox Group

Tin Sn

Average trace element composition, dry basis, ppm

(continued)

Arithmetic Mean

Standard 

Deviation

Selenium Se

Scandium Sc

Silver Ag

Strontium Sr

Uranium U

Vanadium V

Ytterbium Yb

Yttrium Y

Zirconium Zr

Zinc Zn

Notes:

1. Coal analysis is based on mean values for Texas Wilcox Group Coals, 2004 Keystone Coal 

Industry Manual (11)

2. Ash fusion temperatures (reducing) are for Northeast of Wilcox Group

3. The system studies using this coal type (but not this composition) are documented in Exhibit 5-1

4. In previous systems studies, mercury values used for other coals were the mean plus one 

standard deviation

5. In previous systems studies, this coal was dried to 15 percent, 12 percent or 8 percent moisture 

for dry-feed gasifiers
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8 References

1 Argonne National Laboratory. (2012). Argonne Premium Coal Samples. Retrieved on 

May 7, 2013, from http://www.anl.gov/PCS/

2 National Energy Technology Laboratory (NETL). (2010). Overview of U.S. Coal Supply 

and Infrastructure. DOE/NETL-403/081709.

3 U.S. Energy Information Administration (EIA). (2010). Annual Outlook 2010. DOE/EIA0383.

4 U.S. Energy Information Administration (EIA). (2008). Electric Power Annual 2008. 

DOE/EIA-0348.

5 U.S. Energy Information Administration (EIA). (2010). Annual Coal Report 2009. 

DOE/EIA 0584.

6 U.S. Energy Information Administration (EIA). (1999). The Demonstrated Reserve Base, 

U.S. Coal Reserves: 1997, Update.

7 U.S. Energy Information Administration (EIA). (2010). Annual Energy Review 2009. 

DOE/EIA-0384.

8 U.S. Energy Information Administration (EIA). (2009). U.S. Coal Supply and Demand: 

2009 Review. 

9 Babcock & Wilcox Company (2005). Steam, its generation and use. 41st edition.

10 Combustion Engineering Inc. (1981). Combustion – Fossil Power Systems (3rd edition).

11 Keystone Coal Industry Manual. (2004). Published by Coal Age, a Mining Media 

publication.

12 U.S. Energy Information Administration (EIA). (n.d.). Electricity: Survey-level Detail 

Data Files. Retrieved on May 7, 2013, from 

http://www.eia.doe.gov/cneaf/electricity/page/data.html

13 Quick, Jeffrey. C, David E. Tabet, Sharon Wakefield, and Roger L. Bon. (2004). 

Optimizing Technology to Reduce Mercury and Acid Gas Emissions from Electric Power 

Plants. Prepared by the Utah Geological Survey. Prepared for the U.S. DOE. DE-FG26-

03NT41901.

14 U.S. Geological Survey (USGS). (2004). National Coal Resources Data System: US Coal 

Quality Database. Retrieved on May 7, 2013, from 

http://energy.er.usgs.gov/coalqual.htm

15 National Energy Technology Laboratory. (2010). Cost and Performance Baseline for 

Fossil Energy Plants; Volume 1: Bituminous Coal and Natural Gas to Electricity, 

Revision 2. DOE/NETL-2010/1397.
National Energy Technology Laboratory Office of Program Planning and Analysis

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Detailed Coal Specifications January 2012

Quality Guidelines for Energy System Studies

16 Doctor, R.D., J.C. Molburg, and P.R. Thimmapuram. (1996). KRW Oxygen-Blown 

Gasification Combined Cycle: Carbon Dioxide Recovery, Transport, and Disposal. 

Prepared by Argonne National Laboratory, Energy Systems Division. Sponsored by U.S. 

DOE, ANL/ESD-34.

17 Repowering the Sheldon Station with Advanced Pressurized Fluidized Bed Combustion. 

DOE Contract No. DE-AM26-99FT4046, 2003.

18 Repowering Leland Olds Unit 2 with Combustion Hybrid Technology. DOE Contract No. 

DE-AM26-99FT40465, July 2004.

19 Assessment of Alternative FutureGen Plant Designs, Case 7.1.3 – Series #7 Base Case 

with Shell Gasifier for Power Only w/o CO2 Capture. Internal Distribution Only. 

DOE/NETL-310/032406, March 2006.

20 Gray, David, Salvatore Salerno, Glen Tomlinson, and John Marano. (2004). 

Polygeneration of SNG, Hydrogen, Power, and Carbon Dioxide from Texas Lignite. 

Prepared by Mitretek Systems. Prepared for U.S. DOE.