.'tates Office of EPA-130/6-80-001
Environmental Protection Environmental Review August 1980
Agency Washington, DC 20460
Interim
Environmental Impact
Assessment Guidelines
For New Source
Coal Gasification Facilities
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This document is available to the public through the
National Technical Information Service, Springfield,
Virginia 22151.
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EPA 130/6-80-001
AUGUST, 1980
INTERIM FINAL
ENVIRONMENTAL IMPACT
ASSESSMENT GUIDELINES
FOR
NEW SOURCE
COAL GASIFICATION FACILITIES
EPA TASK OFFICER: JOHN W. MEAGHER
OFFICE OF ENVIRONMENTAL REVIEW
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
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PREFACE
This document is one of a series of industry specific environmental
impact assessment guidelines being developed by the Office of
Environmental Review for use in EPA's program for applying the National
Environmental Policy Act (NEPA) to EPA's issuance of New Source NPDES
permits. It is intended to be used in conjunction with Environmental
Impact Assessment Guidelines for Selected New Source Industries,
an OER publication that includes a description of impacts common to
most industrial new sources.
The requirement for federal agencies to assess the environmental
impacts of their proposed actions is included in Section 102 of NEPA.
The stipulation that EPA's issuance of a New Source NPDES permit is an
action subject to NEPA in Section 5ll(c) (1) of the Clean Water Act
of 1977. EPA's regulations for preparation of Environmental Impact
Statements are in Part 6 of Title 40 of the Code of Federal Regulations;
New Source requirements are in Subpart F of that Part.
ii
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CONTENTS
Page
List of Figures. . . . . . . . . . . . . . . . . . . . . . . . .. iv
List of Tables. . . . . . . . . . . . . . . . . . . . . . .. v
INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . .. 1
I. OVERVIEW OF THE INDUSTRY. . . . . . . . . . . . . . . . . .. 3
I.A. SUBCATEGORIZATION. . . . . . . . . . . . . . . . . .. 3
I. B. PROCESSES. . . . . . . . . . . . . . . . . . . . . .. 7
I.B.l. Gasification Process Units. . . . . . . . . .. 7
I.B.l.a. Shift Conversion. . . . . . . . . .. 7
I.B.l.b. Gas Cooling. . . . . . . . . . . .. 7
I.B.l.c. Gas Purification. . . . . . . . . . . 10
I.B.l.d. Methanation. . . . . . . . . . . .. 12
I.B.l.e. Gas Compression and Drying. . . . .. 12
I.B.2. Byproduct Recovery Process Units. . . . . . . . 12
I.B.2.a. Gas Liquor Separation. . . . . . .. 12
I.B.2.b. Phenosolvan. . . . . . . . . . . .. 14
I.B.2.c. Ammonia Recovery. . . . . . . . . . . 14
I.B.3. Specific Low Btu Gasification Processes. . .. 14
I.B.3.a. Lurgi Low/Intermediate Btu Gasification 14
I.B.3.b. Koppers-Totzek. . . . . . . . . . .. 14
I.B.3.c. Bureau of Mines Stirred Fixed Bed.. 21
I.B.3.d. Westinghouse Fluidized-Bed Gasifier. 21
I.B.3.e. Ash Agglomerating Fluidized-Bed Gasifier2l
I.B.4. Specific High Btu Gasification Processes. . .. 21
I.B.4.a. Lurgi High Btu Gasification. . . .. 26
I. B . 4 . b. HYGAS. . . . . . . . . . . . . . . . ' 26
1. B. 4 . c . B I -GAS. . . . . . . . . . . . . 26
I.B.4.d. Synthane. . . . . . . . . 26
I.B.4.e. C02 Acceptor. . . . . . . . . . . . . 32
I.C. PROJECTED TRENDS IN INDUSTRY DEVELOPMENT. . . . . 32
I.C.l. Locational Changes. . . . . . . . . 32
I.C.2. Raw Materials. . . . . . . . . . . . .. 32
I.C.3. Processes. . . . . . . . . . . . . 32
I.C.4. Pollution Control . . . . . . . .. 34
I. D. MARKETS. . . . . . . . . . . . . . . . . . . . . . .. 34
I.E. SIGNIFICANT ENVIRONMENTAL PROBLEMS. . . . . . . . 39
I.E.l. Location. . . . . . . . . ,. . . . . . . . . . . 39
I.E.2. Raw Materials Transportation. . . . . . . . . . 42
I. E. 3. Processes. . . . . . . . . . . . . . . . . .. 42
I.E.3.a. Low/Intermediate Btu Gasification.. 42
I.E.3.b. High Btu Gasification. . . . . . .. 44
1.E.4. Pollution Control. . . . . . . . . . .. 47
I. F. REGULATIONS. . . . . . . . . . . . . . . . . . . . .. 47
II. IMPACT IDENTIFICATION. . . . . . . . . . . . . . . . . . .. 54
II.A. PROCESS WASTES. . . . . . . . . . . . . . . . . . . .. 54
II.A.l. Air Emission Sources. . . . . . . . . . . . . . 54
II.A.l.a. Coal Storage and Preparation. 54
II.A.l.b. Gasification Processes. . . . . .. 54
I1.A.l.c. Acid Gas Removal. . . . . . . . .. 54
II.A.l.d. Methanation. . . . . . . . . . . .. 54
iii
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Page
II.A.I.e. Compression. . . . . . . . . . . . . 54
II. A.I. f. Sulfur Recovery. . . . . . . . 54
ILA.log. Ash and Solids Disposal. . . . . . . 56
II.A.I.h. Emissions from Ancillary Facilities. 56
II.A.2. Characteristics of Potential Atmospheric
Emissions . . . . . . . . . . . . . . . . 56
,II .A.'2. a. Trace Elements in Coal. . . . . . . .56
II.A.2.b. Trace Compounds Formed in Processing .60
II.A.2.c. Sulfur Compounds. .60
II .A. 2. d. Carbonyl Compounds. . . . . . . . . .60
ILA.3. Water Effluent Sources. . . . . . . . . . . . .60
II.A.3.a. Coal Preparation Runoff and Wet
Scrubber Dust Collector Effluent. . .62
II.A.3.b. Gasifiers. . . . . . . . . . . . . . 62
II.A.3.c. Sulfur Plant Recirculation Water Purge
II.A.3.d. Tar Separation. . . . . . . . . . . 62
II.A.3.e. Water Treatment and Boiler Blowdown . 62
II.A.4. Solid Waste Sources. . . . . . . . . . . 62
II.B. TOXICITY AND POTENTIAL FOR ENVIRONMENTAL DAMAGE FROM
SELECTED POLLUTANTS. . . . . . . . . . . . . . . . . . 64
II.B.l. Human Health Impacts. . . . . . . . . . . . . .64
II.B.l.a. Carcinogens. . . . . . . . . . . . . 64
II.B.l.b. Sulfur Dioxide and Hydrogen Sulfide. 64
II.B.l.c. Nitrogen Compounds. . . . . . . . . .66
II.B.l.d. Hydrocarbons. . . . . . . . . . . . .66
II.B.l.e. Carbon Monoxide. . . . . . . . . . . 66
II. B .1. f. Ammonia. . . . . . . . . . . . . . . 66
II.B.I.g. Trace Metals. . . . . . . . . . . . .66
II.B.2. Biological Impacts. . . . . . . . . . . . . . .66
II . C . OTHER IMP ACTS. . . . . . . . . . . . . . . . . . . . . 67
II.C.I. Raw Materials and Byproduct Handling. . . . . .67
II.C.2. Site Preparation and Plant Construction. . . . 69
II.C.3. Transportation Impacts. . . . . . . . . . . . .69
II.C.3.a. Railroads. . . . . . . . . . . . . . 69
II.C.3.b. Barges. . . . . . . . . . . . . . . .74
II.C.3.c. Trucks. . . . . . . . . . . . . . . .74
II.C.3.d. Pipelines. . . . . . . . . . . . . . 74
II. D. MODELING OF IMPACTS. . . . . . . . . . . . . . . . . . 77
III. POLLUTION CONTROL. . . . . . . . . . . . . . . . . . 78
III.A. POLLUTION CONTROL TECHNOLOGY: IN PROCESS CONTROLS 78
III.B. POLLUTION CONTROL TECHNOLOGY: END OF PROCESS CONTROLS
(EFFLUENTS FROM PROCESS) . . . . . . . . . . . . . . . .78
III-B.l. Ammonia. . . . . . . . . . . . . . . . . . . . 79
III.B.2. Phenols. . . . . . . . . . . . . . . . . . . . 79
III.B.3. Other Aqueous Pollutants. . . . . . . . . . . .79
III.C. POLLUTION CONTROL TECHNOLOGY: END OF PROCESS CONTROLS
(EMISSIONS) . . . . . . . . . . . . . . . . . . . . . . 81
IILC.l. Coal Storage and Preparation. . . . . . . . . .81
III. C. 2. Gasification Processes. . . . . . . . . . . . .81
IILC.3. Acid Gas Removal. . . . . . . . . . . . . . . .81
III.C.4. Sulfur Recovery. . . . . . . . . . . . . . . . 81
III.C.5. Briquetting . . . . . . . . . . . . . . . . . . 82
III.D. POLLUTION CONTROL TECHNOLOGY: END OF PROCESS CONTROLS
(SOLID WASTE DISPOSAL) . . . . . . . . . . . . . . . . .82
IV. OTHER CONTROLLABLE IMPACTS. . . . . . . . . . . . . . . . . 83
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Page
IV. A. AESTHETICS. . . . . . . . . . . . . . . . . . . . . . 83
IV. B. NOISE. . . . . . . . . . . . . . . . . . . . . . 83
IV. C. SOCIOECONOMIC. . . . . . . . . . . . . . . . . . . . . 84
IV.D. ENERGY SUPPLY. . . . . . . . . . . . . . . . . . . . . 86
IV.E. IMPACT AREAS NOT SPECIFIC TO COAL GASIFICATION. . .. 86
V. EVALUATION OF AVAILABLE ALTERNATIVES. . . . . . . . . . . . 87
V.A. SITE ALTERNATIVES. . . . . . . . . . . . . . . . . . 87
V.B. ALTERNATIVE PROCESSES, DESIGNS, AND OPERATIONS. . . . 88
V.B.l. Other Coal Gasification Processes. . . . . . . 88
V.B.2. Alternative Systems Within the Process. . .. 89
V.C. NO-BUILD ALTERNATIVE. . . . . . . . . . . . . . . . . 89
VI. REGULATIONS (OTHER THAN POLLUTION CONTROL) . . . 90
BIBLIOGRAPHY. . . . . . . . . . . . . . . . . . . . . . . . . . 91
v
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List of Figures
Number
Page
l.
2.
Principal coal gasification reactions and reactor types. . . . 5
Block flow diagram for a typical (275mm SCF/SD capacity)
coal gasification plant. . . . . . . . . . . . . . 8
Lurgi pressure gasifier. . . . . . . . . . . . . . . . . . . . 9
Flow diagram of the Rectisol purification process. . . . . . .11
General flow diagram of gas liquor separation process. .13
Flow diagram of an ammonia recovery process. . . . . . . . . 15
Lurgi low Btu coal gasification process. . . . . . . . . . . .18
Koppers-Totzek coal gasification process. . . . . . . . . . . 20
Bureau of Mines stirred fixed bed coal gasification process. .22
Westinghouse fluidized bed coal gasification process. . . . . 23
Ash agglomerating fluidized bed coal gasification process. . .24
Lurgi high Btu coal gasification process. . . . . . . . . . . 27
HYGAS coal gasif:':'cation process. . . . . . . . . . . . . . . .29
BI-GAS coal gasification process. . . . . . . . . . . . 30
Synthane coal gasification process. . . . . . . . . . . . . . 31
C02 acceptor coal gasification process. . . . . . . . . . . . 33
National energy consumption by sector from 1950 to 1974,
and a projection from 1974 to 1990 . . . . . . . . . . . . . . 35
u.s. natural gas reserves (excluding Alaska) and annual
consumption from 1947 to 1974 . . . . . . . . . . . . . .36
Geographic location of Petroleum Allocation Districts (PAD) . .41
3.
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ll.
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List of Tables
Number
Low and medium Btu coal gasification processes. . . . . . . . . 4
Selected design features of four low and intermediate
Btu gasification processes. . . . . . . . . . . . . .
U.S. and foreign status of low/medium-Btu gasification
technology. . . . . . . . . . . . . . . . . . . . . . . . 17
Water and material balance for a 7.08 x 106 m3/d Lurgi
gasification plant. . . . . . . . . . . . . . . . . 19
Selected design features of five high Btu gasification processes 25
Gasification material balance: Inputs and byproducts for
a Lurgi gasification plant. . . . . . . . . . . . . . . . . . . 28
Estimated costs by category for high and low Btu gasification
facilities. Costs derived from draft report on synthetic
fuels commercialization for President's Energy Resources
Counc il, 1975 . . . . . . . . . . . . . . . . . . . . . .
Markets for coal gasification plants. . . . . . . . . . . .
Summary of low to intermediate Btu gasification pollutants.
Residuals for the transportation of coal; Summary of high
Btu gasification residuals. . . . . . . . . . . . . . . . . . . 45
Wastewater characteristics from two high Btu coal
gasification processes. . . . . . . . . . . . .. ...... 46
New source performance standards from petroleum refinery;
byproduct coking and utility generation facilities ........- . . .48
Applicable National ambient air quality standards (4U C.i:"l{ SO) . .49
Nondeterioration increments by air quality classification. . . .51
EPA recommended new source performance standards for coal
handling and mining activities. . . . . . . . . . . . . . . . . 53
Process steam characteristics for coal gasification and
probability ratings (low, medium, high) for fugitive air
emissions by ~rocess . . . . . . . . . . . . . . . . . . .-. . .55
Nature and sources of major waste streams associated
with the gasification of coal. . . . . . . . . . . . . . .57,58
Ranges of chemical consituents of representative U.S. coals. . .59
Potentially hazardous substances suspected present
in coal conversion plant process streams. . . . . . . . . . . . 61
Solid wastes from coal gasification facilities. . . . . . . . . 63
Possible health problems associated with trace metals. . . . . .65
Coal pile drainage water: Analyses from nine coal-fired
steam electric generating plants. . . . . . . . . . . . . . . . 68
Outline of potential environmental impacts and relevant
pollutants resulting from site preparation and
construction practices. . . . . . . . . . . . . . . . .
Environmental and health impacts of coal transportation
By coal region and transportation mode. . . . . . . . . . . . . 75,76
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vii
Page
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INTRODUCTION
The Clean Water Act requires that EPA establish standards of performance
for categories of new source industrial wastewater discharges. Before
the discharge of any pollutant to the navigable waters of the United
States from a new source in an industrial category for which performance
standards have been proposed, a new source National Pollutant Discharge
Elimination System (NPDES) permit must be obtained from either EPA or
the State (whichever is the administering authority for the State in
which the discharge is proposed). The Clean Water Act also requires that
the issuance of a permit by EPA for a new source discharge be subject to
the National Environmental Policy Act (NEPA). which may require preparation
of an Environmental Impact Statement (EIS) on the new source. The pro-
cedure established by EPA regulations (40 CFR 6 Subpart F) for applying
NEPA to the issuance of new source NPDES permits may require preparation
of an Environmental Information Document (EID) by the permit applicant.
Each EID is submitted to EPA and reviewed to determine if there are
potentially significant effects on the quality of the human environment
resulting from construction and operation of the new source. If there are,
EPA publishes an EIS on the action of issuing the permit.
The purpose of these guidelines is to provide industry-specific guidance to
EPA personnel responsible for determining the scope and content of EID's
and for reviewing them after submission to EPA. It is to serve as supple-
mentary information to EPA's previously published document, Environmental
Impact Assessment Guidelines for Selected New Source Industries, which
includes the general fonnat for an EID and those impact assessment consi-
derations common to all or most industries. Both that document and these
guidelines should be used for development of an EID for a new source coal
gasification facility.
EPA had not yet issued new source performance standards for coal gasifica-
tion facilities at the time of publication of these guidelines. Until such
standards are proposed, EPA will not have a statutory requirement to prepare
EIS's on coal gasification facilities. This document is being published in
interim final form to familiarize EPA staff with the industry in anticipation
of the new source performance standards and because the information herein
may be useful in other EPA NEPA activities, such as scoping and EIS review.
The guidelines will be revised and published in a final form when the new
source performance standards for coal gasification facilities are issued.
These guidelines provide the reader with an indication of the nature of the
potential impacts on the environment and the surrounding region from con-
struction and operation of a coal gasification plant. In this capacity,
the volume is intended to assist EPA personnel in the identification of
those impact areas that should be addressed in an EID. In addition, the
guidelines present (in Chapter I) a description of the industry, its
principal processes, environmental problems, and recent trends in location,
raw materials, processes, pollution control and the demand for industry
output. This "Overview of the Industry" is included to familiarize EPA
staff with existing conditions in the industry.
I
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Although this document may be transmitted to an applicant for informational
purposes, it should not be construed as representing the procedural re-
quirements for obtaining an NPDES permit or as representing the applicant's
total responsibilities relating to the new source EIS program. In addition,
the content of an EID for a specific new source applicant is determined by
EPA in accordance with Section 6.604(b) of Title 40 of the Code of Federal
Regulations and this document does not supersede any directive received
by the applicant from EPA's official responsible for implementing that
regulation.
The guidelines are divided into six sections. Section I is the "Overview
of the Industry," described above. Section II, "Impact Identification,"
discusses process-related wastes and the impacts that may occur during
construction and operation of the facility. Section III, '~ollution
Control," describes the technology for controlling environmental impacts.
Section IV discusses other impacts that can be mitigated through design
considerations and proper site and facility planning. Section V, "Evalua-
tion of Alternatives," discusses the consideration and impact assessment
of possible alternatives to the proposed action. Section VI, describes
regulations other than pollution control that apply to the industry.
2
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I.
OVERVIEW OF THE INDUSTRY
I.A.
SUB CATEGORIZATION
This industry has not been subcategorized for the purpose of issuing effluent
guidelines. However a variety of parameters (i.e., pressure, bed type) can be
used to categorize various processes currently under development.
The coal gasification process should be viewed as the central step in a
complex refinerylike operation that can convert coal to a variety of pro-
ducts, including pipeline gas or chemicals such as methanol or ammonia.
The coal gasification stage, itself, may produce different mixtures of
three combustible gases including: hydrogen (H2). carbon monoxide (CO),
and methane (CH4) in varying concentrations, depending on the process used.
The simplest processes involve the direct contact of air and steam with coal
at elevated temperatures and atmospheric pressure. This produces a gas
mixture wich a low heat content that ranges from 3,721,754 to 7,443,503
joules per cubic meter (J/m3) (100 to 200 Btu per standard cubic foot).
Substitution of oxygen for air will elevate the heat content to between
9,304,385 and 11,165,254 J/m3 (250-300 Btu/scf). Both of these process
routes produce what is termed low Btu gas. As the pressure of the reactor
is raised, the formation of methane (CH4) is favored and the energy content
of the resulting gas is increased. Coal gasification processes which use
extremely high pressures (1,000 psi), can obtain gas with a heat content
ranging from 24,191,384 to 26,052,260 J/m3 (650 to 700 Btu/scf). Such pro-
cesses are termed medium Btu processes. End products from medium Btu gasi-
fiers (i.e., CO, H2, and CH4) can be used for industrial energy production.
More commonly. however, products are used in a complex set of chemical
reactions, similar to those found in a refinery. in order to produce pipe-
line quality or high Btu gas with a heat content of 35,728,813 J/m3 or
higher (960 Btu/scf or higher) or other products such as methanol or ammonia.
A list of low and medium Btu coal gasification processes is presented in
Table 1 and detailed descriptions of the processes are contained in Howard-
Smith (1976).
In addition to the difference in the quality (heat content) of product gas,
coal gasification processes also may differ in the type of reactor vessel.
Three general categories are:
. Gasifier
. Hydrogasifier
. Devolatilizer
The reactions for each are shown in simplified form in Figure 1. Gasification
systems employ one or more of these reactor types.
As shown in Figure I, the gasifier reactor produces gas through the steam-
carbon reaction (heat + C + H20 + CO + H2). The major differences in gasifier
reactor systems are in the method (direct or indirect) of providing heat.
In the hydrogasifier reactor, methane is produced by reacting hydrogen with
coal or char under pressure (C + 2H2 + CH4 + heat). Although systems of this
type differ in the method of supplying hydrogen, all hydro gasifiers produce
up to twice as much methane as gasifiers or devolatilizers of comparable
capacity.
3
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Table 1.
Low and medium Btu coal gasification processes
Agglomerating ash
Avco arc coal process
Babcock & Wilcox (DuPont)
CE entrained fuel process
Combined cycle (B&W)
Combined cycle (F-W)
Consol fixed bed
Electric arc
Fixed bed (Kellogg)
GRD gasification
Gegas
HRI fluidized bed
HRI gasification (Squires)
ICI moving burden
IFE two-stage
IGI two-stage
In-situ gasification (also known as "underground gasification")
Kerpely producer
Koppers-Totzek
Laser irradiation pyrolysis
Lurgi
Marischka
Molten--salt
Multiple fluidized bed
Otto Rummel slag bath (double shaft)
Panindco
Philadelphia & Reading
Pintsch Hillebrand
Power gas
Rapid high temperature
Riley-Morgan
Rockgas
Ruhrgas vortex
Rummel slag bath (single shaft)
Stirred fixed bed (also known as "Moras")
Texaco gasification
Thyssen Galocsy
Two-stage process (also known as "submerged coal combustion")
Two-step coal pyrolysis gasification
U-Gas
4
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Heat
Coat
Cool
Steam
Rich
Heat
GASIFIER REACTOR
- Heat + C+ H20-. CO + H2
- CO + H20~C02 + H2 +Heat
Low-Btu Gas
HYDROGASIFIER
~
and H2
Gas
C+2H2 ~ CH4 +Heat
Intermed i ate
..
- Btu Gas
..
,
-
DEVOLATILIZATION
REACTOR
Hydrogen
Cool
Heat
Source:
, Cool+H2 ~ CH4+C+Heat
Intermediaie
Btu Gas
.
University of Oklahoma, Science and Public Policy Program. 1975.
Energy alternatives: A comparative analysis. GPO 041-011-00025-4,
Washington DC.
Figure 1.
Principal coal gasification reactions and
reactor types
5
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The devolatilizer reactor decomposes large coal compounds. In this sytem,
hydrogen reacts with the coal to produce methane and heat (coal + HZ +
CH4+C+heat).
Gasification systems also can be categorized on the basis of engineering
features. Two significant features are whether or not the system is pres-
surized and the type of bed used. Gasification systems may be operated
either at high pressure or at atmospheric pressure. The main advantages
gained from pressurizing are:
. Improvement in the quality of product gas
. Maximization of the hydrogasification reaction
. Reduction of equipment size
. Elimination of the need to separately pressurize gas before intro-
ducing it into a pipeline (Interagency Synthetic Fuels Task Force
1974).
In terms of beds, there also are three basic types of gasification systems:
fixed-bed, fluidized-bed, and entrained-bed.
The following descriptions of these bed systems are based on Corey (1974).
. Fixed-bed--In this system a grate supports lumps of coal through
which the steam or hydrogen is passed. Conventional fixed-bed
systems are incompatible with caking coals (coals which, when heated,
pass through a plastic stage and cake or agglomerate into a mass).
To expand the range of coals that can be used, some fixed-bed
systems are modified to incorporate a rotating grate or stirrer to
prevent caking.
. Fluidized-bed--This system uses finely sized coal. Gas is flowed
through the coal, producing a lifting and "boiling" effect. The
result is an expanded bed with more coal surface area to promote the
chemical reactions. Fluidized-bed systems also have a limited capa-
city for operating with caking coals; consequently. these types of
coals often are pretreated to destroy caking characteristics when
the fluidized-bed system is used.
. Entrained-bed--This system also uses finely sized coal. The coal
particles are transported in the gas (for example, steam and oxygen)
prior to introduction into the reactor. The chemical reactions occur,
and the product gases and ash are taken out separately. There are no
limitations on the types of coal that can be used with the entrain-
ment system.
The environmental assessment guidelines contained in this document focus on
the Lurgi gasification process and associated clean up procedures such as
tar removal and sulfur recovery. Some emphasis has been placed on the Lurgi
process because more "hard" information is available. Nevertheless, many
of the information and assessment techniques will apply to other coal
gasification processes (Koppers-Totzek, Winkler, etc.). We also recognize
that many permit applications may include other chemical processes as well
as ancillary facilities such as an oxygen plant, coal mine, railroad spur,
pipeline, or electric generating station; however, EID guidelines for most
of these facilities will be contained in separate guidelines.
6
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LB.
PROCESSESI
The gasification plant proper normally would include all process units
necessary to produce pipeline quality gas from presized coal. Coal
preparation and classification techniques common to the coal industry
are utilized to prepare the coal. The main process area would consist
of a gasification system composed of these six process units:
. Gasification
. Shift conversion
. Gas cooling
. Gas purification unit
. Methanation
. Gas compression and drying
and a byproduct recovery system composed of four process units:
. Gas liquor separation
. Pehnosolvan unit
. Ammonia recovery
. Sulfur recovery
The discussion that follows presents a summary description of these steps
as well as brief but specific descriptions of the major low, intermediate,
and high Btu processes for the gasification of coal. A block diagram of
the process is shown in Figure Z.
LB .1.
Gasification Process Units
A variety of gasification processes are currently in operation or under
development. The gasification process has already been described in
Section I.A. and the details of various processes are discussed in Section
I.B.3. and I.B.4. Figure 3 illustrates a typical gasifier (Lurgi in this
case).
I.B.I.a. Shift Conversion. The amount of methane (the principal component
of natural gas) in the crude gas from the gasification unit is low and further
chemical conversion of the crude gas to increase the methane content is
necessary. This conversion is performed in the crude gas shift and methana-
tion units. The shift conversion unit is designed to produce the hydrogen
(HZ) required to adjust the HZ:CO ratio for the methanation unit. This is
accomplished through the "water gas shift" reaction carried out over a cata-
lyst (usually an iron-chromium oxide compound) in the presence of steam as
follows:
CO + HZO + COZ + HZ + heat
Approximately 33% of the total crude gas is subject to shift
with the balance bypassed rlirectly to the gas cooling unit.
of the two gas streams are adjusted to achieve the desired
methanation (usually about 3:1).
conversion
The proportions
H2:CO ratio for
A series of processes are utilized to produce high Btu gas.
included for completion.
These are
I.B.l.b. Gas Cooling. The gas cooling unit is designed to cool the raw
gas from gasification and shift conversion and to remove the heavier hydro-
carbons and unreacted steam before low temperature purification. The cooling
scheme is arranged to recover and use as much of the process heat as practical;
lThis section is based largely on technical information presented in
University of Oklahoma (1975) and US-DOl (1978).
7
-------
Oxy~en Plant
Gasification
tl2 + 02 DOlL OFF
OXYGEN PLANT
POWER
1.5 MW
AIR
02
COAL PREP.
OXYGEN BLOWN
GASIFIERS
COAL
(X)
STEAM
AIR
AIR GASIFIERS &
PURIFICIITION
FUEL GAS
EVA,.
STIAM
RAW WATER H20 TREATED
TREATMENT &
STORAGE
WATER
WATER
MAKE UP WATER
liME SLUDGE
QUENCH WATER
TAR SEPARATION
ASH
POWER &
STEAM PLANT
TAR & TAR OIL
Shif t Conversion
Purification
Methanation
Compression
and Drying
fUEL
INCIN &
SUPER HEATER
FLUE GAS
S
COMPRESSION
& DEHYDRAT
SNG
WATER EVAP.
VENT
AIR'
EFFLUENT AIR
COOLING
WATER SYSTEM
AIR
H2S+C~
SULfUR PLANT
LOCK HOPPER GAS
BV PASS GAS
FROM AIR GASIFIER
OlOWDOWN
EVAP POND
EVAP WATEn
METHANATION
Figure 2.
Block flow diagram for a typical (275mm SCF/SD capacity) coal gasification plant
SHIFT CONVERSION
GAS PURIF.
NAPHTHA
LIOUID FROM AIR GASIFIER
WATER
VENT
STEAM 57MW
ASH PISPOSAL
FLUE GAS
AlA
!!VAP
WET ASH TO MINE
0.05 % S
5.4 % OAF COAL
PHENOLS
NH3
AN:MONIA
SOLUTION 24.1 %
Source:
Howard-Smith,!., G. J. Werner. 19]6. Modified
from: Coal conversion technology. Noyes Data
Corporation. Park Ridge, N.T.
-------
coal feed
coal bunker
gasifier
coal lock chamber
steam spp~r~~;nn
coal distributor
rate
crude gas outlet
wash cooler
water .acket
oxygen & steam inlet
ash
rate
ash lock chamber
ash lock
ash outlE\t
Source:
u.S. Department of the Interior, Upper Missouri Region. 1978.
Final environmental impact statement, ANG Coal Gasification Company
North Dakota Project. FES78-l.
E'igure 3.
Lurgi pressure gasifier
9
-------
further cooling is done in wet and dry coolers, depending on water avail-
ability and cost.
The gas cooling in the gasification plant may be done in three parallel
stages. Two stages for cooling the crude gas bypass the shift conversion
area and the other stage cools the converted gas. Converted gas is compressed
and combined with the crude gas 'stream. The mixed gas stream, having a pre~
determined H2:CO ratio, is conveyed to the gas purification unit. The
condensate from gas cooling goes to the gas liquor separation unit for re-
covery of tar and oil.
I.B.l.c. Gas Purification. The gas purification unit removes carbon dioxide
(C02), sulfur compounds, and other impurities from the raw gas. A flow
diagram of a Rectisol process is shown in Figure 4. The Rectisol process
operates by scrubbing the acid gases with methanol. The gas can be purified
to less than 1.5% C02 by volume and sulfur compounds (H2S and CaS) removed
to a level of less than 1 ppm (by volume); the sulfur free gas then can be
passed to methanation. A variety of other processes including the Selexol,
Purisol, Estasduan, Fluor Solvent, MEA, MDEA, DEA, DIPA, DCA, Benfield,
Sulfinol and Amisol processes also are used to purify the raw gases.
The sulfur recovery system also is an interrelated part of any purification
process. Although a variety of sulfur recovery processes exists, the two
oldest and best established processes are the Claus process and the Stretford
process.
In the Claus process about one-third of the hydrogen sulfide is burned with
air in a pressurized boiler and most of the heat generated by the exothermic
reaction is used to produce steam. The sulfur oxides stream reacts With the
remaining H2S to form sulfur. After the sulfur is condensed out of the gas
stream, the reaction is completed by heating the gases to temperatures which
range from 204°C-2600C (4000F-5000F) and passing them over a bauxite alumina
catalyst. Operating pressures usually are about 4.8-7.2kg/m2 (14-2lpsi).
This latter step normally is carried out in two or more stages with interstage
cooling and condensation in order to favor the reaction.
The Stretford process uses a sodium carbonate solution which reacts with the
hydrogen sulfide to form sodium hydrosulfide. The sodium hydrosulfide is
oxidized to elemental sulfur with sodium vanadate. The vanadium is oxidized
back to the pentavalent state by blowing the solution with air using sodium
anthraquinone disulfonate as a catalyst. The finely divided sulfur appears
as a froth which is skimmed off, washed, and dried by centrifugation or
filtration.
Other processes available to reduce H2S concentrations are:
. Hot potassium carbonate scrubbing (reduction to 10 ppm)
. Rectisol-solvent based scrubbing (reduction to 0.1 ppm)
o Selexol-solvent based scrubbing (reduction to 0.1 ppm)
. Sulfinol-amine scrubbing (reduction to 1 ppm)
. MEA-monoethanolamine scrubbing (reduction to 1 ppm)
o DIPA-disopropanolamine scrubbing (reduction to 1 ppm)
In these processes, traces of S02, cas, CS2 and C02 are found in the tail
gases. Tail gas processes which can reduce sulfur compounds to as low as
0.1 ppm include Beavon, Clean Air, Sulfreen, Shell Copper Oxide, SCOT,
Wellman-Lord and Chiyoda Thoroughbred 101.
10
-------
Off GAS TO
SULFUR
RECOVERY
CRUOE AND
CONVERTED
CAS FROM
GAS COOLING
SV"'THESIS
GAS TO
METHANATION
1-1
1-1
TRUTEO
WATER
NAPHThA
TO STORAGE
MPURE WATE
o GAS LIQUID
TREA TlNO
Source:
EXPANSION
GAS TO
GASIFICA ToON
fLASH
EGENERATO
Off OAS TO
SULFUR
RECOVERY
PREWASH
TOWER.
HOT
REGEIt
"...'"'
"-.. ...
METHANOL
WATER
COLUMN
u.S. Department of the Interior, Upper Missouri Region. 1978.
statement, ANG Coal Gasification Company North Dakota Project.
Final environmental impact
FES78-1.
Figure 4.
Flow diagram of the Rectisol purification process
-------
I.B.l.d. Methanation. The methanation unit converts the low Btu synthetic
gas to methane-rich high Btu gas by the following exothermic reactions:
CO + 3HZ + CH4 + HZO + heat
COZ + 4HZ + CH4 + ZHZO + heat
Other minor reactions which also could take place are the hydrogeneration of
ethylene to ethane and hydrocracking of ethane to methane.
Feed gas entering the methanation unit from each gas purification unit first is
heated and then mixed with recycled methanated effluent gas before being
methanated in parallel catalytic reactors. The feed gas is sometimes diluted
with methanated effluent before heating to limit the temperature rise across
the reactors. The reactors often are designed as fixed-bed downflow units
which employ a pelleted reduced nickel-type catalyst.
The reaction heat is removed by generation of high pressure
heat exchangers at the outlet from each reactor. The steam
the gasifier.
steam in waste
is recycled to
Gas leaving the synthesis loop is passed through a cleanup reactor (final
methanation reactor) to accomplish essentially complete conversion of car-
bon monoxide (CO) and then cooled by successive heat exchange with fresh
feed gas, air, and cooling water. Water condensed from the gas may be
separated and forwarded for recovery as boiler feed water. The net produce
then is sent to the gas compression unit.
I.B.l.e. Gas Compression and Drying. This system is designed to deliver the
synthetic natural gas (SNG) to the pipeline at a pressure that ranges from
56-105 kg/cm2 (800-1,500 psi). The product gas compression system usually
consists of centrifugal compressors, driven by condensing steam turbines.
The product is dry, in addition to having the COZ content reduced to below
1.5%. Final product gas now is ready for metering and discharge to the
pipeline for distribution. Final drying of the product gas to pipeline gas
specifications is accomplished by a dehydration unit.
I.B.Z.
Byproduct Recovery Process Units
I.B.Z.a. Gas liquor separation.
naphtha, and dissolved compounds
sulfide (HZS).
The gas liquor may contain tar, tar oil,
such as phenols, ammonia, C02' and hydrogen
Tar is defined as a heavier-than-water organic liquid phase, whereas tar oil
is the lighter-than water organic liquid phase.
The gas liquor separation is designed to clean up tarry and oily gas liquors
by separating the incoming streams into tar, tar oil, recycled gas liquor,
and clarified aqueous liquor streams by fractional condensation and liquid
settling.
The gas liquor streams which originate from the gasification, shift con-
version, and gas cooling units are cooled, combined, and reduced in pressure.
The entrained gases, which consist primarily of COZ but with traces of CH4'
~:O, NH3' and HZS, are released and passed through a water scrubber for re-
.:overy of ammonia and then move to a low pressure flare for incineration.
A flow diagram of the process is shown in Figure 5.
12
-------
OUSTV&TARRV
GAS lIOUORS
fflOM
GASifiCATION.
SHIfT
CONVERSION &.
GAS COOLING,
f-'
UJ
Source:
SfCONOARYSfPARAYORS
GAS LIQUOR
EXPANSION
VESSElS
FINAL GAS
lIOUOR SEPARATOR
.OIL TANK
PRIMARY SEPARATORS
FINAL GAS LlOUOR
SURGE TANK
DUST
flEMOVAL UNIT
U.S. Department of the Interior, Upper Missouri Region. 1978.
statement, ANG Coal Gasification Company North Dakota Project.
Final environmental impact
FES78-1.
Figure 5.
General flow diagram of gas liquor separation process
-------
I.~.Z.~. Phenosolvan. .The process water from the gas liquor
Wh1Ch 1S usually contam1nated with phenols, ammonia, HZS, and
treated in the Phenosolvan unit for removal of phenols before
ferred to the ammonia recovery system.
separation unit,
COZ is
it is trans-
The incoming process water is passed through extractors where an organic
solvent is used to extract phenols. The organic solvent is distilled and
separated from the phenol and may be recycled to the extractors for reuse.
The crude phenol byproduct may be recovered and transferred to storage for
subsequent use as part of the byproducts feed to the boilers.
I.B.Z.c. Ammonia Recovery. The ammonia recovery unit normally involves the
selective absorption of ammonia from the gas liquor leaving the phenosolvan
unit. A water solution of NH3, COZ and HZS are removed by steam distillation
at the liquid phase, then an ammonium phosphate solution is used to &~lectively
absorb ammonia (see Figure 6).
I.B.3.
Specific Low Btu Gasification Processes
The major characteristics of five processes designed to produce either low
or intermediate Btu gas from coal are discussed briefly below and are summar-
ized in Table Z, and their status shown in Table 3. Two of these, Lurgi
and Koppers-Totzek, are used commercially; the others are in the pilot plant
stage. A large number of other processes (with, for example, different
combinations of bed types, pressure levels, and oxygen sources) have been
proposed or are in early stages of development. The five technologies
described below illustrate the current state of the art.
I.B.3.a. Lurgi Low/Intermediate Btu Gasification. There is no pretreatment
(except sizing) in the Lurgi process and only noncaking coals can be used.
As shown in Figure 7, pulverized coal is introduced into a pressurized reactor
vessel through a lock hopper. The coal passes down and is distributed onto
a rotating grate. Steam and oxygen are introduced below the grate. All the
coal is combusted, leaving only ash which is allowed to fall through the
grate. Product gas from the combustion zone above the grate leaves the
reactor at 700-8lloK (800-l,0000F). To produce Z50 billion Btu's per day,
Z7 to 33 gasifiers of 3.9 meters (13 ft.) I.D. would be required. Materials
balance and water balance for the Lurgi process are shown in Table 4.
I.B.3.b. Koppers-Totzek. In the Koppers-Totzek process, finely ground coal
after thermal drying is mixed with oxygen and steam, then pumped into an
atmospheric-pressure vessel (Figure 8). Because of the low pressures used
and the entrained flow of the materials injected, a complex and potentially
troublesome system of hoppers is avoided. Two or four injection or burner
heads may be used.
Combustion occurs at high temperatures (1644°C (3,0000F» in the center
of the reactor vessel and the product gas exits upwards through a central
vertical outlet. Molten slag exits at the bottom. A typical large
gasifier is about 3 meters (10 ft.) in diameter and 7.6 meters (Z5 ft.) long.
A Koppers-Totzek reactor will produce about twice the gas per unit reactor
volume of a Lurgi reactor because of its higher throughput capabilities
(National Academy of Engineering/National Research Council 1973).
14
-------
I-'
U1
GAS LlOUOR
fROM
PHENOSOLVAN
UNIT
Source:
PHOSl'HDRIC
ACID -
EXIT GAS
10 SULfUR
RECOVERY
CW
STRIPPER
U.S. Department of the Interior, Upper Missouri Region. 1978.
statement, ANG Coal Gasification Company North Dakota Project.
SUPE RSTILL
-
BY.PRODUCT
WATER TO .
COOLING TOWER
MAkE.UP
Figure 6.
CAUSTIC
MP
STEAM
fRACTIDNATDR
fEED TANK
FRACTIDNATDR
CW
FRACTIDNATDR
ACCUMULATQR
Final environmental impact
FES78-1.
Flow diagram of an ammonia recovery process
ANHYDROUS
AMMONIA
TO STORAGE
-------
Table 2.
Selected design features of five low
and intermediate Btu gasification processes
Name
Reactor
type
Bed type
Lurgi
Gasifier
Modified
fixed
Koppers-Totzek
Gasifier
Extrained
suspension
BuMinesb
Gasifier
Modified
fixed
f-'
0"1
Westinghouse
Gas if ier
Fluidized
Ash agglomerating
Gasifier
Fluidized
Pressure
Hydrogen
sources
Oxygen
sources
Heat
Direct
burning
Direct
burning
Direct
burning
Direct and
internal
exothermic
reactions in
desulfurizer
Direct
burning
Pretreatment
Sizing
Pulverizing
Pulverizing
Pulverizing
drying,
integrated
devolatiles/
desulfurizers
Pulverizing
Coal
inpu t
Noncaking
1/4x2",
no fines
Caking or
noncaking,
pu1verizeda
Caking or
noncaking,
coarse or
fine
Caking or
noncaking,
pulverized
Caking or
noncaking,
pulverized
apulverized means crushed so that 70%-80% of the coal passes a 200-mesh screen (0.003").
bThe BuMines process listed here is often identified as two processes. The only difference between the two
is that one is pressurized.
Source:
300-450
1bs/in2
Steam
Air/
oxygen
Atmospheric
Steam
Oxygen
Atmospheric
to 300
Ibs/in2
Steam
Air
200-300
Ibs/in2
Steam
Air
Pressurized
Steam
Air
University of Oklahoma, Science and Public Policy Program.
analysis. GPO 041-011-0025-4, Washington DC.
1975.
Energy alternatives:
A comparative
-------
Tuble 3.
U.S. AND FOREIGN STATUS OF LOw/mmum-DTU GASIFICATION TECHNOLOGY
No. of 1\09 I flers currently -':'J'_erat Ing (no. 0 f ga_~!.i ers uuilt)
Casifier Licensor/dev~loper Low-Dtu gas H"dium-~tu f!as Synthesis gas Loca t ion Scale
Lurg! Lurgi Hineralb'1techn!k Gmbll 5 (39) (22) Foreign Commercial
Wellman-Galusha McDowell Wellman Engineering Co. 8(150) US/Foreign Commercial
Woodall-Duckman/ Woodall-Duckham (USA) Ltd. (72) (8) Foreign COITlDl»rc ial
Gas Integrale
Koppers-Totzek Koppers Company, Inc. (39) Foreign Commercial
Winkler D.~vy Powergas (23) 6(14) Foreign Commercial
Chapman (Wllputte) Wilputte Corp. 2 (12) US COmIn»rc!a1
Riley Horgan Riley Stoker Corp. 1 US Con:me rcia 1
BCG/Lurgi Slagging British Gas Corp. and Lurgi 1 Foreign Demonstration
Hineraloltechnik Gmbll
Bi-Gas Bituminous Coal Research, Inc. 1 US Demons t rat ion
Fos ter Wheeler/Stoic Foster Wheeler/Stoic Corp. 1*(2) US/Foreign Demonstration/
Con,:.ercia1
Pressurized Wellman- ERDA 1* US DeIDDnstration
Galusha (HERC)
CFERC Slagging ERDA 1* US Demonstration
Texaco Texaco Development Corp. 1* US DcIT.0nstration
ECR Low-Btu Bituminous Coal Research, Inc. 1* US Dcmonstration
Cambus tion Engineering Combustion Engineering Corp. 1* US Demonstration
Bygas Institute of Gas Technology 1 US DeEr.Dost ration
t-' (Hlgh-Btu)
-...J Synthane ERDA 1 US Demonstration
(lligh-Btu)
C02 Acceptor ERDA 1 US Derr,ons t rat 100
(High-Dtu)
Cogas COGAS Development Co. 1 US Demonstration
(High-Bt u)
Foster Wheeler Foster Wheeler Energy Corp. 1 US Pilot
Babcock L WtlCOK The Babcock & Wilcox Co. 1 US Pilo t
U-Gas Institute of Gas Technology, 1 US Pilot
Phillips Petroleum Corp.
Sterns-Roger
westinghouse Westinghouse Electric Corp. US Pilot
Coalex Inex Resources. Inc. 1 US Pilot
(1*) Camme rc ia1
Wellman Incandescent Applied Technology Corp. (2*)** US/Foreign Commercial/
Demonstration
wUnder construction.
Demonstration scale indicates 2000 to 10,000 Iblhr coal feed.
Pilot scale indicates 400 to 1500 lb/hr coal feed.
**Undetermined number overseas
Source: Radian Corporation (1977)
-------
Cool
> Preparation
Raw
Gas
Purification
Gasifier
....... Steam
(X) >0
)
f
Oxygen
Ash
Source:
University of Oklahoma, Science and Public Policy Program.
comparative analysis. GPO 041-011-00025-4, Washington DC.
Figure 7.
1975. Energy alternatives: A
Adapted from Bodle and Vyas (1973).
Lurgi low Btu coal gasification process
-------
Table 4.
Water and Material balancea for a 7.08 x 106 m3/d Lurgi gasification plant
Input Quan tity Output Quantity
b c 250 x 109 Btu/day
Coal 10,770 tpd Intermediate Btu gas
Water U Solid waste 865 tpd
Sulfur dioxided 0.83 tpd
Water consumption by category
l/min
Percent
Drift
28,836
14,920
606
1,968
56.7
31.5
Discharge or evaporation
Reaction
Vent
1.3
4.2
Total
757
1,136
1,090
47,313
1.6
2.4
With ammonia
Wet ash
Fuel and incineration
2.3
100.0
Water supplies by category
Water supply source
Total
37,434
5,413
4.466
47,313
79.1
11.4
Coal
Products of methanation
9.5
100.0
U = unknown.
aAssumes the
removal.
use of a methanation step following gasification and sulfur
bu .
slng Northwest coal of 8,780 Btu/lb, 6.77% ash, and 0.85% sulfur.
c
Tons per day.
dControlled emission.
Source:
Rittman Associates, Inc. 1975b. Environmental impacts,
efficiency, and cost of energy supply and end use. Final
report, Vol. II. Columbia MD, p. 111-29.
19
-------
tv
o
Source:
Cool
Prepa ra t ion
Steam
and
Oxygen
Quench,
....
,. Heat Recovery,
and Scrubbing
...
.r
Approx. 2750° F
Atm Pressure
University of Oklahoma, Science and Public Policy Program.
comparative analysis. GPO 041-011-00025-4, Washington DC.
Figure 8.
Gosif ier
Ash
1975. Energy alternatives: A
Adapted from Bodle and Vyas (1973).
Koppers-Totzek coal gasification process
-------
The Koppers-Totzek process offers an advantage of not producing byproduct
tars, ~ils, etc., owing to its higher operating temperature. The higher
operatlng temperature, however, also is a disadvantage in SNG production.
The SNG produced has a low methane content (1%) and the size of the
methanation unit must almost be doubled. Other disadvantages are greater
oxygen consumption and low operation pressure. The resultant SNG has to
be compressed to a final pipeline pressure 'of about 7~ kg/cm2 (1050 psi).
l.B.3.c. Bureau of Mines Stirred Fixed Bed. In the BuMines process pulverized
coal is fed into the top of the reactor from a lock hopper and falls' down onto
a rotating grate similar to the one used in the Lurgi process (Figure 9).
However, a stirrer is mounted in the center of the reactor and a variable
speed. drive both rotates the stirrer and moves it vertically. This prevents
clogglng and allows caking coals to be used. Steam and air are injected from
below the grate.
The dimensions of a commercial-sized reactor have not been determined. The
plant has been operated at pressures ranging from atmospheric to 21 kg/cm2
(300 psi).
l.B.3.d. Westinghouse Fluidized-Bed Gasifier. Two pressurized, fluidized-bed
vessels are used in the Westinghouse system, one as the gasifier and the
other as a devo1atilizer/desu1furizer. Air, steam, and char react in the
gasifier to produce a hot gas which is then introduced into the devo1ati1izer/
desulfurizer with crushed coal and dolomite (lime) (Figure 10). Hot gases
from the gasifier supply the heat for devo1atilization and the char pro-
duced by devolatilization is used as the feedstock for the gasifier. Sulfur
is removed by the dolomite.
I.B.3.e. Ash Agglomerating Fluidized-Bed Gasifier. In this process, pul-
verized coal is introduced into a pressure vessel and is partially burned at
high temperature while suspended by an upward flow of air and steam. The
ash slowly agglomerates in the reactor and falls to the bottom where it is
removed. (Figure 11). Fine particulates in the produced gas are removed by
a cyclone scrubber. The gas is then cooled to about 1,032oK (1,4000F) and
passed through a filter where dolomite reacts with any hydrogen sulfide to
form a sulfurized solid. The dolomite filter is regenerated periodically
by treating it with hot carbon dioxide to drive off the sulphur. The hot,
cleaned, pressurized gas (which has a heating value of about 160 Btu's/
ft3 is then fed to a combined cycle electric power plant.
The system, now in prototype development, has a high throughput for a
particular reactor vessel size and relies on the agglomerating characteris-
tics of coal to remove ash.
I.B.4.
Specific High Btu Gasification Processes
The major characteristics of five high Btu gasification systems are identified
in Table 5. All five systems are in the developmental stage. The Lurgi
gasification process has been proven but the final upgrading and methanation
steps have not been used commercially.
Most high Btu gasification processes include pretreatment, gasification,
clean up, shift conversion, purification, and methanation steps (discussed in
Section 1.B.l). Differences between systems are greatest in the gasification
step. These differences are highlighted below.
21
-------
Coat Preparation 1300° F Low Btu Gas
1.0 Atmosphere
H2S
Absorber
Row Gas Water Steam
0.5 PSIG
13000 F Ammonium Sulfate Stack Gas
Ste am Gasifier Plant
N
:-.:> Air (NH4) 504
2
Sludge
Ash
Source:
Interagency Synthetic Fuels Task Force. 1974. Report to Project Independence blueprint, Federal
Energy Agency. Supplement 1, prepared under direction of USDI, Washington DC. Cited in
University of Oklahoma, Science and Public Policy Program. 1975. Energy alternatives: A
comparative analysis. GPO 041-011-00025-4, Washington DC.
Figure 9.
Bureau of Mines stirred fixed bed coal gasification process
-------
Particulate
Removal
System
Low Btu Gas
Hot Fuel
Gas
Dolomite
Devol at! lizer-
Desutfurize r
Do lomite
Course
Char
Coal
N
LoJ
Hot Gas
Dryer
Combustor
Gasifier
Fine Char
Air
Stea m
Ash
1975. Energy alternatives: A
Adapted from Archer, et a1. (1974).
University of Oklahoma, Science and Public Policy Program.
comparative analysis. GPO 041-011-00025-4, Washington DC.
Source:
Westinghouse fluidized bed coal gasification process
Figure 10.
-------
C028c Steam
Power
Cyclone Desulfurizer Gas
Cool
>
Gasifier
Fines
N H2S
+:--
Air
steam
Sulfur 502
Air > Conversion
Ash S
Source:
University of Oklahoma, Science and Public Policy Program.
comparative analysis. GPO 041-011-00025-4, Washington DC.
1975. Energy alternatives: A
Adapted from Archer, et al. (1974).
Figure 11.
Ash agglomerating fluidized bed coal gasification process
-------
Table 5.
Selected design features of fIve high Btu gasification processes
Reactor Pressure Hydrogen Oxygen
Name type Bed type (lbs/in2) sources sources Heat Pretreatment Coal input
Lurgi Gas if ier Mod if ied 300-500 Steam Oxygen Direct Sizing Noncaking,
fixed plant 1/4x2",
no fines
HYGAS Hydrogasifier Fluidized 1,000 Hydrogen a Oxygen Direct Sizing, 8 to 100
plant heating, mesh fines
and slurry all coals
BI-GAS Gasifier and Entrained 1,000 Steam Oxygen Direct None Liquid to
N hydrogasifier flow plant rank A
VI
bituminous
pulverized
Synthane GasH ier Fluidized 1,000 Steam Oxygen Direct Sizing and All coals
devolatilizer plant heat and fines of
volatilize 200 mesh
C02 acceptor Gas if ier Fluidized 150 Steam Air Direct and Sizing Lignite or
devolatilizer indirect subbituminous,
1/8"
~ydrogen introduced into the gasifier is produced by reaction of steam, char, and oxygen.
Source: University of Oklahoma, Science and Public Policy Program. 1975. Energy alternatives: A
comparative analysis. GPO 041-011-00025-4, Washington DC.
-------
I.B.4.a. Lurgi Righ Btu Gasification. The initial gasification step used in
Lurgi is essentially the same for low and high Btu gasification. Synthesis
gas from the gasifier shown in Figure 12 has a Btu value of approximately
285 Btu/ft3. The upgrading process is the same as the general process
described earlier including cooling shift conversion, purification, and
methanation (Corey 1974). Pilot plant configurations of these steps have
been tested in Scotland and South Africa but data concerning both plants are
proprietary.
Each gasifier reactor is capable of producing about 10 million cubic feet
(mmcf) of synthetic natural gas per day. The inputs and outputs of a 250-
mmcf-per-day Lurgi gasification plant are summarized in Table 6.
I.B.4.b. HYGAS. In the HYGAS process, pulverized coal of a nominal -8/+100
mesh size is slurried with hot aromatic by-product oil and pumped into the
gasification reactor. This reactor, which operates at 1,000 psi, has been
heated and supplied with a hydrogen-rich gas from a separate char-gasifier
vessel (Figure 13). As the coal slurry enters the reactor, light oils and
gases vaporize upward and the coal falls down into a fluidized bed. Total
coal residence time in the gasification reactor is about 30 minutes. The
devolatilized coal goes from the gasification reactor into the char gasifier
where hydrogen-rich gases are produced from the reaction of char, steam,
and oxygen (Rittman, 1975. Volume II). The RYGAS process differs from other
processes primarily in its use of slurry feed and a hydrogen-rich gasifier
atmosphere.
After leaving the gasification reactor, the raw gas is cooled, the aromatic
oil is recycled, and other tars and oils are removed as byproducts. The
gas is then processed by water-gas shift conversion, purification, and
methanation.
The HYGAS process is one of the most complex gasification systems being
developed and has separate circulation systems for coal, char, and byproduct
oil. Its advantages include the use of pumped slurries instead of lock
hoppers and the efficiency gained by using a hydrogen-rich gas for the hydro-
gasification reactions. Although commercial plant size information is not
available, about 10 gasifiers would be needed for a commercial plant.
I.B.4.c. BI-GAS. In the BI-GAS process, pulverized coal is piston-fed into
the middle of a 1,000 psi gasifier reactor where it is mixed with steam. The
coal is devolatilized by a rising flow of hot gases which are produced from
char (Figure 14) (Rittman, 1975. Volume II). The gases and char are then
separated and the char is piped to the bottom of the gasifier where it is
mixed with steam and oxygen. An ash slag is removed from the bottom of
the vessel. The process gas stream undergoes cleaning, shift conversion,
purification, and methanation.
I.B.4.d. Synthane. In the Synthane process, coal sized to pass through a
200-mesh screen is mixed with steam and oxygen in a pretreatment pressure
vessel at 1,000 psi and 4270C (8000F) (Figure 15). In this pretreatment
stage, the coal is partially oxidized and volatile matter is driven off.
The coal and gases from the pretreater are introduced at the top of the
gasifier and additional steam and oxygen are introduced at the bottom.
Partial combustion of the coal increases the temperature of this process to
26
-------
Coal
Preparat ion
N
'-J
Staa m
Oxygen
Raw Gas
Gasifier
Quench
Ash
Source:
University of Oklahoma, Science and Public Policy Program.
comparative analysis. GPO 041-011-00025-4, Washington DC.
Shift
Purification
C02 + H2S
Methanation
1975. Energy alternatives: A
Adapted from Bodle and Vyas (1973).
Figure 12.
Lurgi high Btu coal gasification process
-------
Table 6.
Item
Input:
Coal
Water
Output:
Solid waste
Gasification material balance: Inputs and by-products for a
Lurgi gasification planta
Quantity
Unit
21,450,000 (23,600)
3.5 x 107 (9.3 x 106)
kg/day (ton/day)
liter/day (gal/day)
1,407,000 (1548) kg/day (ton/day)
34,000 (37.3) kg/day (ton/day
102,000 (112) kg/day (ton/day)
105,000 (116) kg/day (ton/day)
4.3 x 106 (4.09 x 10 ) 3 J/day (Btu/day)
123,600 (32665) liter/day (gal/day)
Air emission
Ammonia
Sulfur
Tar
Naphtha
a7.08 x 106 m3/d (250 mmcf/d) plant, using Northwest coal at 2.0401 x 107
J/kg (8,780 Btu/lb), 6.77% ash, and 0.85% sulfur.
Source:
Hittman Associates, Inc. 1975a. Environmental effects, impacts,
and issues related to large-scale coal refining complexes.
NTIS FE-1508-T2. Columbia MD.
28
-------
Hot Air
and
Steam
I'Y
1.0
Light Oil
Cool
Cool
Preparation
Slurry
Preparation
H2-rich
Stea m
Oxygen
C02 + H2S
Purification
Light 011
Vaporizer
-------
Low Temp.
Reactor
-------
High Temp.
JteM!oJ_-
gas
Gasifier
Char
Ash
Source:
University of Oklahoma, Science and Public Policy Program.
comparative analysis. GPO 041-011-00025-4, Washington DC.
Shift
Conversion
Methonation
1975. Energy alternatives: A
Adapted from Bodle and Vyas (1973).
Figure 13. HYGAS coal gasification process
-------
Raw
Gas
High 8TU Gas
Coal stage 2
> Prep.
Shift Scru b Methanator
Gasifier
UJ
a
Steam
Char Sulfur Recovery
Oxygen > Stage I
Slag
Source:
University of Oklahoma, Science and Public Policy Program.
comparative analysis. GPO 041-011-00025-4, Washington DC.
1975. Energy alternatives: A
Adapted from Goodridge (1973).
Figure 14. BI-GAS coal gasification process
-------
Coal
Steam
Oxygen
Spray Shift Scrubber
Tower
Gasifier
Tar and Dust H2S
w COS
I--' C02
Steam
Oxygen Methanator
Pipeline
Char Gas
H2S
Source:
University of Oklahoma, Science and Public Policy Program.
comparative analysis. GPO 041-011-00025-4, Washington DC.
1975. Energy alternatives: A
Adapted from Bureau of Mines (1974).
Figure 15. Synthane coal gasification process
-------
980°C (1,800°F). After the coal passes through the fluidized-bed portion of
the gasification vessel, it exits as char at the bottom. The char is burned
to produce steam for the pretreater and gasifier (Hittman, 1975. Volume II).
The raw gas is cleaned of tars, char, and water and then undergoes a shift
conversion. Following those operations, the gas is bubbled through hot
carbonate to remove carbon dioxide and sulfur and is then methanated.
The Synthane process achieves a high Btu raw gas output with a relatively
simple high-pressure gasification system. However, all the coal entering the
gasifier is not burned and the remaining high sulfur char must be burned for
process heat.
I.B.4.e. C02 Acceptor. In the C02 Acceptor process, pulverized coal and hot
dolomite are introduced at the top of the reactor and steam is introduced
at the bottom (Figure 16). Both the heat of the dolomite and its energy-
producing reaction with the carbon dioxide (a product of the coal-steam
reaction) devolatilize th~ coal as it passes down the reactor vessel. The
partially combusted coal p.xits as char (Hittman, 1975. Volume II). Both
the char and spent dolomite are then introduced as separate streams into a
dolomite regenerator vessel. In this vessel, the combustion of char with
air heats the dolomite and drives off the carbon dioxid~
The C02 Acceptor process produces a gas low in carbon dioxide, carbon monoxide,
and sulfur. A shift in reaction is not necessary since the carbon monoxide-
to-hydrogen ratio is already suitable for methanation. The advantages of
the C02 Acceptor process are in the use of dolomite to remove some of the
sulfur and carbon dioxide from the synthesis gas stream. Because dolomite is
used as the oxidizing agent in the gasifier vessel, oxygen does not have to
be supplied. These advantages, however, must be balanced with the complexity
of plant design for the dolomite regeneration system.
I.C.
PROJECTED TRENDS IN INDUSTRY DEVELOPMENT
I.C.!.
Locational Changes
Currently there are no full scale commercial coal gasification facilities in
the U.S. but a number of proposals for both demonstration and commercial gas
production are in various stages of implementation. It is generally antici-
pated that most new facilities will be established in coal mining regions in
order to reduce transportation costs for the raw materials. These plants may
be mine mouth facilities or located on separate but nearby sites.
LC.2.
Raw Materials
Coal gasification processes will operate with a variety of coal types. The
Lurgi process has been unable to use caking and unsized coals but, as
mentioned earlier, this restriction may soon disappear. However, the
development of new processing techniques will largely confine the Lurgi
process to surface mined coals which have a low production cost to balance
the processing costs.
I.C.3.
Processes
As has been mentioned on several occasions in this document, a variety of
processes are under study and/or development. The focus has been on processes
32
-------
w
w
Source:
Coal
Preparation
Lock
Hopper
C02 +H2S
Raw Gas
Purification
Methanation
Dolomite
Gasifier
Flue Gas and Ash
Air
Char
University of Oklahoma, Science and Public Policy Program.
comparative analysis. GPO 041-011-00025-4, Washington DC.
Stea m
Figure 16.
1975. Energy alternatives: A
Adapted from Bodle and Vyas (1973).
C02 acceptor coal gasification process
-------
which result in
. Maximum cost effectiveness
e Low environmental impacts
. Production of high quality
products
The actual processes which will dominate the industry cannot be predicted at
this point in time.
LC.4.
Pollution Control
Radian Corporation (1977) has prepared an up to date review of pollution
control systems that are available or under development. In general the
following approaches are being used in the development of pollution control
systems for coal gasification facilities:
o Utilization of processes with reduced emissions and more controllable
fugitive emissions
. Improved gas purification processes to reduce impurities in the
product gas stream
. Upgraded sulfur recovery and tail gas cleaning processes to reduce
sulfur and complex hydrocarbon emissions
. Pro~esses to treat cyclic hydrocarbons in wastewaters
. Processes to remove acidic components from wastewaters
LD.
MARKETS
Natural gas, electricity, fuel oil, and low sulfur coal are in short supply
in many areas of the U.S. Projected demands for natural gas exceed the
future supply (US-DOl, 1978). Figure 17 shows the consumption of energy
in the U.S. from 1950 to 1974 and a projection to 1990. Beginning about
1950, the U.S. changed from a net exporter of energy to a net importer. Since
1958, energy imports have increased at rates between 7% and 10% (National
Academy of Engineering, 1974).
Total energy use in the U.S. has more than doubled since 1950, increasing at
rate of 4.25% per year. During the same period, domestic energy production
has increased at an annual rate of only 3%. During recent years, production
increase has slowed to less than 1% (Ford Foundation, Energy Policy Project,
1974).
a
Figure 18 shows domestic gas reserves and annual consumption from 1947 to
1974. It is evident that there will soon be a large unsatisfied demand for
natural gas even if all available sources are developed to the maximum. More-
over, the gas supply will continue to decline unless one or more of the following
events take place:
o New sources of natural gas are discovered
. Significant volumes of SNG are produced from coal
. Other technological means are found to produce natural gas.
Several factors contribute to the demand for natural gas. Pipelines were
built after World War II forming a transport network which made gas available
throughout much of the countrJ. A large number of homes and industries became
dependent on natural gas because of its low price, clean burning characteristics,
and availability. Industries on interruptible gas contracts could enjoy a rela-
tively continuous supply of energy at a very low price. Since 1967, however,
industrial interruptions have become common and in some areas new industrial
customers are being rejected.
34
-------
Quadrillion Btu
150 I
25
,
,
,
,
,
I'
Pro-Emba'i30 " , ,.
~ ,. ,
, ,
Current Forecast,,>" #I
, ~,,'
I' ,
,.' ,
, ,-
I' ,
,. ,
" ..~.....
, ~~
" ,'.
125
100
75
50
,-
" ' .
......;,>~~ ));- / I
J'f'; ','".# ",/"
o
1950
60
70
74
80
I
85
I
it)
Rough Equivalences for U.S. Energy Data:
1 quadrillion Btu = 500,000 barrels petroleum per day for a year
= 40 million tons of bituminous coal
= 1 trillion ft3 of natural gas
= 100 billion kwh (based on a 10,000 Btu/kwh
heat rate
Source:
U.S. Department of the Interior, Upper Missouri Region. 1978. Final
environmental impact statement, ANG Coal Gasification Company North
Dakota Project. FES78-1.
Figure 17.
National energy consumption by sector from 1950 to 1974, and a
projection from 1974 to 1990.
35
-------
Trillion Cubic Feet
320
205.4
300
Proved Reserves
280
260
240
220
200
180
160
40
35
30
Reserve
Additions
25
20
8.1
15
10
5
o
5
10
Marketed
Production
15
20
21.6
25
1947
60
74
55
65
50
70
Source:
American Gas Association, et al. 1975. Reserves of crude oil,
natural gas liquids, and natural gas in the United States and
Canada, and United States productive capacity, as of December
31, 1974.
Figure 18.
U.S. natural gas reserves (excluding Alaska) and annual consumption
from 1947 to 1974.
36
-------
Total proven reserves of natural gas in the U.S. reached a peak of 293 trillion
cubic feet (Tcf) in 1967 (Figure 18). Until that time, natural gas reserve
additions exceeded production each year. Since 1968, production has exceeded
reserve additions except for 1970 when Alaska's Prudhoe Bay reserves were
added to the proved reserves (American Gas Association, 1975). During the
past eight years, reserve additions in the lower 48 States have averaged 9.3 Tcf
annually compared to an average production of 21.4 Tcf. In 1975 proven reserves
with and without Alaska were 237 and 205 Tcf, respectively (US-DOl, 1978).
In July 1976, the Federal Power Commission in Opinion Number 770 authorized
an increase in the price of natural gas sold in interstate commerce. This
rate increase is expected to increase natural gas supplies for the short term;
however, recoverable reserves are limited and for the long term the U.S. will
need to find alternative means of producing energy. Based on these circum-
stances, it is reasonable to assume that more emphasis will be given to coal
gasification technology with a likely increase in its marketability.
In the past, the extraction of methane from coal has been demonstrated in
several pilot plants, both in the U.S. and abroad. This technology gives the
U.S. a mid-term capability for expansion of coal reserves as supplement to
domestic natural gas supplies.
However, to date, the commercial viability of a high Btu synthetic gas venture
has not been demonstrated in the U.S. Estimates in 1976 indicate an investment
of about $1 billion would be required to construct a high Btu gas plant capable
of producing 0.08 Tcf/yr (assuming an investment debt/equity ratio of 75:25).
About $525 million would be required to finance construction of a low Btu gas
plant producing the equivalent of 0.05 Tcf/yr (assuming a debt/equity ratio
of 50:50). The full costs, i.e., without incentives of both high and low
Btu synthetic gas processes, expressed in 1975 dollars on a free on board
(FOB) gasification plant basis, may be expected to range as shown in Table 7.
Transmitting the high Btu gas output to consuming areas adds costs which vary
depending on the proximity of the synthetic plants to natural gas transmission
networks and consuming markets.
The technology involved in the production of low Btu gas is well developed
and currently is applied in many commercial plants outside the U.S. A
limiting factor in the use of low/medium Btu gas is that it may not be
economically feasible to transport it more than 50 miles. This may be an
inhibiting developmental factor if a plant is intended to generate electricity
to residential, commercial, and industrial users in urban areas.
Although industry is considering a number of synthetic fuels projects, none
has actually proceeded to the construction stage. Six major projects involving
high Btu gas from coal are being planned. Several low Btu gas projects, for
utility and industrial fuels, have been suggested but have not reached the
level of planning associated with high Btu gas projects. None of the projects
has acquired the financing and approvals needed to proceed. Only a few
projects have reached the detailed design stage.
Coal gasification projects have not proceeded expeditiously because the risks
associated with initiating synthetic fuels projects are large, in comparison
with other investments which provide an equal or higher rate of return. One
major risk is the uncertainty of future world oil prices. Other important
37
-------
Table 7. Estimated costs by category for high and low Btu
gasification facilities. Costs derived from draft report on syn-
thetic fuels commercialization for President's Energy Resources
Council, 1975.
High Btu gas plant Low Btu gas plant
Cost ($/Mcf) Low High Low High
category estimates estimates estimates estimates
Fixed costs 1. 02 1.38 1.77 2.40
Operating and
maintenance .82 1.01 .61 .76
Feedstock of $11*
to $17/ton 1.19 1.84 .72 1.11
Total at plant 3.03 4.23 3.10 4.27
*Feedstock cost of coal could be estimated at $5 to $9/ton, recognizing
East and West regional experiences in coal production costs; with lower
feedstock cost, high Btu gas would range between $2.38 and $2.34/Mcf.
Source:
Federal Energy Administration. 1976. National energy outlook.
FEA-N-75/713. GPO 041-018-00976. Washington DC.
38
-------
risks include:
. Uncertainty about air and water quality standards
. Resource (coal, shale, biomass) availability as constrained
by leasing rates and environmental concerns
. Availability of water
. Federal regulation of fuel prices
. Availability of labor, materials, and equipment
. Need for environmental control technology
. Extent of socioeconomic impact
. Unforeseen project delays.
However, in recognition of the diminishing natural gas supplies, the develop-
ment of high and low Btu gasification plants may accelerate rapidly (with
proper financial incentives) after 1980 and could reach about 1,060 billion
cubic feet (Bcf) by 1985, 1,440 Bcf by 1990 (Federal Energy Administration,
1976).
Ultimately, the demand for gas products from coal will be established by
regional needs for energy and for certain petroleum based chemicals such as
ammonia. Table8 illustrates the potential markets by Petroleum Allocation
Districts (PAD) (Figure 19) for coal gasification facilities.
The determination of need for a specific gasification plant is complicated
by the relationships between various sources of energy, both nationally and
regionally. A systematic and complete analysis of project alternatives is
essential to ensure investigation of all options. A methodology for the
evaluation of alternatives is discussed in Section V.
I.E.
SIGNIFICANT ENVIRONMENTAL PROBLEMS
I.E.l.
Location
Coal gasification facilities generally are large installations which can
occupy from 200 to 1,000 acres. Much of this acreage is necessary for
containing a 90-day coal supply which safeguards the plant against a work
stoppage in the coal mines or a breakdown in the transportation system for
raw materials. The nature of these facilities locates them either in rural
areas or on the periphery of an urban area in the coal mining regions.
Because the siting of new source gasification plants can involve a significant
change in land use, particularly in rural areas, direct and indirect social
and ecological impacts occur. Direct impacts are primarily a result of the
type of facility proposed and site specific conditions. The magnitude and
significance of secondary or indirect impacts such as induced growth, in-
frastructure changes, and demographic changes depends largely on the local
economy, existing infrastructure, numbers and characteristics of construction
workers (e.g., local or nonlocal, size of worker's family), and other related
factors. Long term secondary impacts are seldom significant unless the plant,
because of its size, processing methods, and location, employs a large number
of workers and thereby leads to the creation of spin-off developments
(commercial, industrial, and residential). At the time of publication of these
guidelines, the EPA's Office of Environmental Review was developing a method
to assess the induced growth impacts of new source industries. The method
will be available in early 1981.
39
-------
Table 8.
Markets for coal gasification plants
Crude deficiency (joules)
Coal conversion region 1980 1985
Markets for high joule. gas:
P AD Region I 1. 855 x 106,- 2.37 x 106 2.932 x 106 - 4.206 x 106
PAD Region II 3.71 x 106 - 4.421 ~ 106 4.516 x 106 - 6.756 x 106
PAD Region III 2.019 ~ 106 - 3.113 x 106 3.584 x 106 - 6.483 x 106
PAD Region IV 1.676 x 105 - 2.94 x 106 2.287 x 105 - 4.82 x 105
PAD Region V 2.098 x 106 - 2.524 x 106 1. 217 x 106 - 1. 832 x 106
.j:- Markets for low joule gas:
a
Northwestern Great Plains 4.072 x 1017 - 1. 629 x 1018 8.854 x 1017 - 8.540 x 1018
Four Corners 4.426 x 1018 - 7.986 x 1018 6.402 x 1017 - 2.90 x 1019
Central 2.2134 x 1017 - 1. 9478 x 1019 4.427 x 1017 - 7.00 x 1019
Appalachian 6.644 x 1017 - 1. 062 x 1019 2.2134 x 1017 - 6.467 x 1019
PAD = Petroleum Allocation District.
Source:
u.s. Department of the Interior, Office of Coal Research. 1974. Prospective regional markets
for coal conversion plant products projected to 1980 and 1985. Washington DC.
-------
+:-
.......
,
,
,o
c.;;-;....-.. -----r.::-
/-...'..---
I
\
1;-
~ -'"-,.~-~
\~
-- f A4 HU.AS~A
"'''' ,'"
~0iAD0--
..
hOIUH OA8IClU
""",
.J
...
~,
kANUs
.......
f'4[W "o.ro
MLJ.tlOW.A
~<=
,,~
{)
"'-'tIlIOIl':O
D
Source:
Federal Energy Administration.
00097-6, Washington DC.
1976.
National energy outlook.
FEA-N-7S/713.
GPO 041-018-
Figure 19.
Geographic location of Petroleum Allocation Districts (PAD)
-------
I.E.2.
Raw Materials Transportation
The major environmental problems associated with raw materials
coal's mining and transport. Guidelines for the assessment of
impacts are contained in separate guideline documents, so this
discussion will cover only the transportation of coal.
occur during
coal mining's
After mining, coal
to the site of its
by:
must be transported either to a processing facility or
use. Raw coal is almost always transported from the mine
. Rail
. Barge (a
from the
. Truck
. Pipeline
system which often involves moving coal by truck or train
mine to a barge loading facility)
The impact of each is discussed in Section II.C.3.
I.E.3.
Processes
The primary environmental contaminants associated with low/intermediate
Btu gasification processes and high Btu gasification processes are de-
scribed below.
Low/Intermediate Btu Gasification
I.E.3.a.
Residuals from four low to intermediate Btu gasification processes are
summarized in Table 9 and are discussed briefly by categories of water, air,
and solids in the following paragraphs. The majority of the residuals data
are based on studies by Hittman, Battelle, and Teknekron.*
. It's usual to assume that water will be placed in evaporation ponds
or recycled, so water pollutants are neglible. However, it is
possible in areas where there is net rainfall that some discharge
will occur. Potential sources of water effluent are from boiler
blowdown, the raw gas cooling system, and weir overfill of the fresh
water clarifier.
.
Major air emissions (Table 9) may result from the sulfur recovery
processes, the ammonia sulfate plant for the two BuMines processes
and the Claus plant for the Koppers-Totzek processes (Hittman, 1975.
Vol. II). Regional differences in sulfur dioxide emissions result
from variations in the sulfur content of the coal. Northwest coal
is lowest and northern Appalachian coal highest in sulfur content.
*Hittman's data assume maximum environmental control; for example, it is
assumed that water is recycled and that no effluent leaves the facility.
The data have an error of less than 50%. The Battelle and Teknekron data
generally are based on technologies that provide more limited environmental
control and this is reflected in higher values for environmental residuals.
42
-------
Table 9.
Summary of low to intermediate Btu gasification pollutants
Air Solidsb
(tons per 1012 Btu's input)
Process Water (tons per 1012 Btu's)
Sulfur Oxides a Other
BuMines
Atmospheric 0 12 to 40 0 3,500 to 7,000
BuMines
Pressurized 0 14 to 40 0 3,500 to 7,000
Koppers-Totzek 0 18 to 41 l2.5c 3,500 to 8,500
Lurgi 0 3.3 0 3,500
aVariation due to sulfur content difference in coal; only Northwest coal is
used in the Lurgi calculation.
bVariation due to ash content difference in coal; only Northwest coal is
used in the Lurgi calculation.
cInc1udes 40% particulates, 20% nitrogen oxides, 23% hydrocarbons, and 17%
carbon monoxide.
Source:
Rittman Associates, Inc. 1975. Environmental impacts, efficiency,
and cost of energy supply and end use. Final report, Vol. II.
Columbia MD.
43
-------
. Solid waste volumes generated by low/intermediate Btu gasification
processes range from 3,500 to 8,500 tons for each 1012 Btu's of coal
processed (Table 9). These values include only ash removed from
the combustor and depend upon the ash content of the coal. The lowest
value is for Northwest coal, which has the lowest (6.4%) ash content, and
the highest is for Central coal, which has the highest (17.3%) ash
content. Because a typical low Btu gasification plant would produce
an additional solid waste of about 5000 tons per 1012 Btu's amount
daily, some or all of the waste require disposal in the mine. If the
sulfur recovered in the process cannot be sold, it also may require
disposal. The solid waste from a gasifier also contains small
quantities of radioactive isotopes. For the agglomerating gasifier
discussed by Teknekron (1973), these are 0.00076 curie of radium-226
and thorium-228 and -230 for each 1012 Btu's of coal gasified.
I.E.3.b. Righ Btu Gasification. Table 10 summarizes ranges of values for
residuals calculated by Rittman (1975). A brief description of discharges
to each medium follows:
. A plant synthesizing 250 mmcf of natural gas per day at 60% effi-
ciency may emit l60xl09 Btu's of waste heat per day. Presumably,
most of this will be emitted to the atmosphere through the use of
mechanical-draft, wet-cooling towers or dry cooling systems. These
cooling towers will require 20 to 35 mgd of make-up water. Thus,
in regions where water is scarce, all process wastewater and
impounded runoff (about three million gallons per day) will be
treated and used for cooling tower make-up. All blowdown streams
are collected and sent to lined evaporative ponds. For this reason,
water residuals are negligible, although settling ponds and process
units could rupture or spill into streams or other water courses.
Wastewater treatment may also be required in areas where water is not re-
cycled and where there is not a net evaporation. Characteristics of un-
treated wastewater are given in Table 11 for the Synthane gasifier unit
and the entire Lurgi Process. Effluent characteristics from the Lurgi
system assume the following treatment: three stages of tar-oil-water
separation; filtration, phenol recovery, ammonia recovery in an ammonia
still; and activated carbon treatment (Rittman, 1975. Vol. II).
. Air emissions may be produced from several byproduct streams, but
most are from combustion of fuels in the plant boiler and the sulfur
recovery plant. Stack discharges from the boiler usually are cleaned
with an electrostatic precipitator for particulates and wet scrubbing
system for gases. Emissions are given in Table 10 for five air
pollutants. The range of values for anyone process reflects
variations due to area coal characteristics. In general, emissions
are highest when Central area coal is used and lowest when Northwest
coal is used.
. Solids generation varies regionally and primarily is a function of
the ash content of the coal. Generally disposal requirements are
least for Northwest coal (low in ash content) and greatest for
northern Appalachian coal (high in ash content). For a high Btu
gasification facility using Northwest coa12 3,700 tons of material
(primarily ash) are generated for each 101 Btu's of disposal from
Central coal, and northern Appalachian coal use would produce about
44
-------
Table 10. Summary of high Btu gasification residuals
12 Air
(tons per 10 Btu's coal processed) Solids Total
Process Water (tons per landa
Particulates Nitrogen Sulfur Hydrocarbons Carbon 1012 Btu's) (acres)
oxides oxides monoxide
HYGAS (Recycled or 3- 7 60- 68 6-63 1 3.5 3,700-6,500 350
BI-GAS treatment 3- 5 54- 63 14-81 1 3.0 3,800-6,800 350
Synthane to meet 13-15 100-115 10-52 2 5.0 3,800-6,600 350
.j>. standards 2- 4 6-37 1 4.0 3,700-5,300 350
lr1 Lurgi 7 3- 7 7
CO Acceptor (Table 11) 3 38 62 0.5 2.0 8,600 350
2
aLand required is for coal storage, preparation, gasification plant facilities, and evaporation ponds.
No additional requirement is assumed for buffer areas surrounding plant facilities (although they would
probably be included in a commercial facility, on the order of 1,500 acres).
Source:
Hittman Associates, Inc. 1975. Environmental impacts, efficiency, and cost of energy supply
and end use. Final report, Vol. II. Columbia MD.
-------
Table .11.
Wastewater characteristics from two high Btu coal gasification processes
Parameter
Synthane
Gasifier Vessela
(parts per million)
Lurgi processb
Before Treatment
(parts per million)
After Treatment
(parts per million)
Thiocyanate 23 0 0
Cyanide 0.23 0 0
Ammonia 9,520 15,900 15.9
Sulfide U 1,400 1.4
~
0\
Suspended solids 140 600 33.5
Organics
Phenols 6,000 9,960 0.498
Oil 0 1,100 15.4
Chemical oxygen demand 43,000 0 0
U = unknown.
Sources:
aForney, Albert J. 1974. Analyses of tars, chars, gases and water found in effluents from the
synthane process. Bureau of Mines Technical Progress Report 76, Washington DC. Cited in
University of Oklahoma, S~ience of Public Policy Program. 1975. Energy Alternatives: A
comparative analysis.
bHittman Associates, Inc. 1975b. Environmental impacts, efficiency, and cost of energy supply
and end use. Final Report, Vol. II. Columbia ~ID, p. IV. Cited in University of Oklahoma,
Science and Public Policy Program. 1975. Energy alternatives: A comparative analysis.
-------
6,600 tons of solid wastes. For this reason, high Btu gasification
plants may have to be mine mouth activities so that solid wastes can
be returned to the mine for disposal.
In addition to ash, the C02 Acceptor process requires disposal of dolomite.
Of the 8,600 tons shown in Table 10, spent dolomite is 6,700 tons or 78% of
that total.
I.E.4.
Pollution Control
Pollution control processes reduce adverse impacts that result when control
is absent; however, the same processes can cause other kinds of impacts. The
equipment used to control various waste streams in coal gasification facilities
also can generate solid and liquid residual wastes which must be treated and
properly disposed of. The sulfur removal processes may generate substantial
quantities of sludge which must be disposed of. Likewise the biological
processes generate sludges. There is no previous experience or data accumu-
lated on this aspect.
I.F.
REGULATIONS
Currently there are no national pollution standards which directly apply
to atmospheric emissions or wastewater discharges from coal gasification
plants. There are effluent limitations for the petroleum refining and by-
product coke industries, which are sometimes compared to coal gasification.
In addition, there are emission limits for the fossil fueled electric utility
steam generation industry, which has similarities to the coal gasification
industry. These effluent and emission limits are summarized in Table 12.
It should be noted that, despite some similarities, the coal gasification
facilities are quite different from byproduct coke, petroleum refining and
utility generating facilities, and the limits developed by EPA for emissions
and effluents from gasification plants may differ significantly from the
values in Table 12.
Other pertinent air standards are the National Ambient Air Quality Standards,
which specify the ambient air quality that must be maintained outside the
plant boundary or within the boundary where the general public has access.
Applicable Federal standards are shown in Table 13. Standards designated as
primary are those necessary, with an adequate margin of safety, to protect
the public health; secondary standards are those necessary to protect the
public welfare from any known or anticipated adverse effects of a pollutant.
47
-------
Table l2a. Adjusted new source performance standards for wastewater
from petroleum refinery and byproduct coking facilities
(from 40 CFR 419 and 420)
Industry 6
(kg pollutant per 1016 J, 30-day feedstock)
Pollutant
Petroleum Refineries
Byproduct Coke
BOD
TSS
Ammonia
Oil and
Phenols
Sulfides
99
62
20
30
0.66
0.51
- 436
- 278
- 172
- 101
3.0
2.5
205
104
104
104
5.12
2.5
(as N)
Grease
See Cleland, J.G. (1976)
Table l2b. Summary of Standards of Performance for Fossil-Fuel-Fired
Steam Electric Generating Units for Which Construction is
Commenced After September 18, 1978 (from 40 CFR 60)
Pollutant
Emission Limit
Sulfur Dioxide
Nitrogen Oxides
Particulate Matter
Opacity
520 ng/J (1.2 lb/106 Btu)l
260 ng/J (0.60 lb/l06 Btu)2,3
13 ng/J (0.03 lb/l06 Btu)4
20 percent5
1.
For coal, a 90 percent reduction in potential S02 emissions is required
at all times except when emissions to the atmosphere are less than 260
ng/J (0.60 lb/l06 Btu). When S02 emissions are less than 260 ng/J
(0.60 lb/l06 Btu), a 70% reduction in emissions is required.
Except: (a) the limits for coal derived gaseous, liquid and solid fuels,
and for subbituminous coal, are 210 ng/J (0.50 lb/l06 Btu); (b) the
limit for any fuel containing more than 25% (by weight) lignite mined in
North Dakota, South Dakota or Montana and combusted in a slag tap furnace
is 340 ng/J (0.80 lb/l06 Btu); (c) Any fuel containing more than 25%
(by weight) coal refuse is exempt from NOx standards. Other deviations
from the 260 ng/J (0.60 lb/l06 Btu) limit for liquid and gaseous fuel
are in 40 CFR 60.44a.
For coal, a 65 percent reduction in potential nitrogen oxide emissions
is required.
For coal, a 99 percent reduction in potential particulate emissions is
required.
Except for one 6-minute period per hour of not more than 27% opacity.
Assumes heating values of 6.5 mmBtu/bbl for crude oil and 12,000
Btu/lb for coal, with a coke yield of .69 1b coke/lb coal.
2.
3.
4.
5.
6.
48
-------
Table 13.
Summary of National Ambient Air Quality Standards (from 40 CFR 50)
Standard
Emission
Primary
Secondary
Sulfur dioxide
80 micrograms/m3 annual
arithmetic mean
1,300 micrograms/m3 maximum
3-hour concentration*
365 micrograms/m3 maximum
24-hour concentration*
Particulate matter
75 micrograms/m3 annual
geometric mean
150 micrograms/m3 maximum
24-hour concentration*
260 micrograms/m3 maximum
24-hour concentration*
60 micrograms/m3 annual
mean
(as guide in assessing
implementation plans)
geometric
.j::--
\.0
Hydrocarbons
160 micrograms/m3 (0.24 ppm)
maximum 3-hour concentration *
160 micrograms/m3 (0.24 ppm)
maximum 3-hour concentration*
Nitrogen dioxide
100 micrograms/m3 annual
arithmetic mean
100 micrograms/m3 annual
arithmetic mean
Ozone
235 micrograms/m3 (0.12 ppm)
maximum 1-hour concentration*
235 micrograms/m3 (0.12 ppm)
maximum 1-hour concentration*
Carbon monoxide
10 mg/m3 (9 ppm)
maximum 8-hour concentration*
10 mg/m3 (9 ppm)
maximum 8-hour concentration*
40 mg/m3 (35 ppm)
maximum 1-hour concentration*
40 mg/m3 (35 ppm)
maximum 1-hour concentration*
Lead
1.5 micrograms/m3
maximum calendar quarterly
average
1.5 micrograms/m3
maximum calendar quarterly
average
*The maximum allowable concentration may be exceeded for the
prescribed period once each year without violating the standard.
-------
In 1974, the Environmental Protection Agency (EPA) issued regulations for
the prevention of significant deterioration of air quality (PSD) under the
1970 version of the Clean Air Act (Public Law 90-604). These regulations
established a plan for protecting areas that possess air quality which is
cleaner than the National Ambient Air Quality Standards (NAAQS). Under EPA's
regulatory plan, clean air areas of the Nation could be designated as one of
three "Classes." The plan permitted specified numerical "increments" of air
pollution increases from major stationary sources for each class, up to a
level considered to be "significant" for that area. Class I provided extra-
ordinary protection fromair quality deterioration and permitted only minor
increases in air pollution levels. Under this concept, virtually any
increase in air pollution in the above pristine areas would be considered
signficant. Class II increments permitted increases in air pollution levels
such as would usually accompany well-controlled growth. Class III increments
permitted increases in air pollution levels up to the NAAQS.
Sections 160-169 were added to the Act by the Clean Air Act Amendments of
1977. These amendments adopt the basic concept of the above administratively
developed procedure of allowing incremental increases in air pollutants by
class. Through these amendments, Congress also provided a mechanism to apply
a practical adverse impact test which did not exist in the EPA regulations.
The PSD requirements of 1974 applied only to two pollutants: total suspended
particulates (TSP) and sulfur dioxide (802) (See Table14). How~ver, Section
166 requires EPA to promulgate PSD regulations by 7 August 1980 addressing
nitrogen oxides, hydrocarbons, carbon monoxide, and ozone
utilizing increments or other effective control strategies. For these
additional pollutants, States may adopt non-increment control strategies
which, if taken as a whole, accomplish the purpose of PSD policy set forth
in Section 160.
Whereas the earlier EPA regulatory process had not resulted in the Class I
designation of any Federal lands, the 1977 Amendments designated certain
Federal lands Class I. All international parks, national memorial parks
and national parks exceeding 6,000 acres, are designated Class I. These 158
areas may not be redesignated to another class through State or administra-
tive action. The remaining areas of the country are initially designated
Class II. Within this Class II category, certain national primitive areas,
national wild and scenic rivers, national wildlife refuges, national sea-
shores and lakeshores, and new national park and wilderness areas which are
established after 7 August 1977, if over 10,000 acres in size, are Class II
"floor areas" and are ineligible for redesignation to Class III.
Although the earlier EPA regulatory process allowed redesignation by the
Federal land manager, the 1977 amendments place the general redesignation
responsibility with the States. The Federal land manager only has an
advisory role in the redesignation process, and may recommend redesignation
to the appropriate State or to Congress.
In order for Congress to redesignate areas, proposed legislation would be
introduced. Once proposed, this would probably follow the normal legisla-
tive process of committee hearings, floor debate, and action. In order for
a State to redesignate areas, the detailed process outlined in Section l64(b)
would be followed. This would include an analysis of the health, environ-
mental, economic, social, and energy effects of the proposed redesignation
to be followed by a public hearing.
50
-------
Table 14.
Nondeterioration increments by air quality classification
Pollutant Class I Class Il Class III Class I eXjeption
(]lg/m3) (]l g/ro3) (]l g/m3) (jl g/m )
Particulate matter:
Annual geometric mean 5 20 37 19
24-hour maximum 10 37 75 37
Sulfur dioxide:
Annual arithmetic mean 2 20 40 20
24-hour maximum 5* 91 182 91
3-hour maximum 25* 512 700 325
*A variance may be allowed to exceed each of these incremen3s on 18 days
per year, subject to limiting 24-hour increments of 36 ]lg/m for low
terrain and 62 ]lg/m3 for hig~ terrain and 3-hour increments of 130 ]lg/m3
for low terrain and 221 ]lg/m for high terrain. To obtain such a variance
requires both State and Federal approval.
Source:
Clean Air Act Amendment of 1977 (42 USC 7401 et seq.)
Public Law 95-95, 95th Congress: August 7.
H.R. 6161,
51
-------
Class I status provides protection to areas by requiring any new major
emitting facility (generally a large point source of air pollution--see
Section 169(1) for definition) in the vicinity to be built in such a way and
place as to insure no adverse impact on the Class I air quality related values.
The permit may be issued if the Class I increment will not be exceeded,
unless the Federal land manager demonstrates to the satisfaction of the
State that the facility will have an adverse impact on the Class I air
quality related values.
The permit must be denied if the Class I increment will be exceeded, unless
the applicant receives certification from the Federal land manager that the
facility will not adversely affect Class I air quality related values. The
?er~t may be issued even though the Class I increment will be exceeded
(Up to the Class I increment -- see Table 14).
In the absence of Federal effluent limitations for the coal gasification
industry, the selection cf limitations in NPDES permits will be made on the
basis of receiving water quality standards and applicable State and local
standards. It appears likely that those setting NPDES limitations will
take into account the Federal effluent guidelines and standards from related
industries, as discussed above, in their determination of standards to
preserve existing water quality.
Moreover, coal gasification facilities will depend largely on surface
mined coal; therefore, the standards established under the Federal strip
mining legislation (PL 95-87) also are pertinent. Table 15 lists recommen-
ded NSPS for coal storage, refuse storage, coal preparation, and acid and
alkaline mine drainage (mining related regulations are discussed in detail
in a separate appendix, Surface Coal Mining).
52
-------
Table 15 Nationwide performance standards for wastewater discharged after application of the best
available demonHtrated control technology by new sources in the coal mining point source category.
Tllc limitations are not applicable to excess water discharged as a result of precipitation of snow
melt in excess of the la-year, 24-hour precipitation event (40 CFR 434; 44 FR 9:2586-2592,
12 .January 1979). Units are milligrams per liter (mg/l) except as otherwise indicated.
BITUNINOUS, LIGNITE, A.~D ANTHRACITE HINING
Coal Preparation Plants
And Associated Areas
Acid or Ferruginous
Mine Drainagel
Alkaline Hine
Drainagel
iijtal suspended solids
?
70.0-
Average of
30 consecutive
daily values
?
35.0-
Parameter
Average of Average of
I-day 30 consecutive I-day 30 consecutive
Naximum daily values Maximum daily values
70.0 35.0 70.02 35.02
6.0 3.0 6.0 3.0
4.0 2.0 4.0 2.0
range 6.0-9.0 range 6.0-9.0
I-day
Haximum
VI
~
Total iron
6.0
3.0
Total manganese
pH (pH units)
range 6.0-9.0
I Drainage \"hich is not from an active mining
meet the stated limitations unless it is
the limitations.
area (for example, a regraded area) is not required to
mixed with untreated mine drainage that is subject to
2
Total suspended
\.J'yoming. In
case basis.
solids limitations do not apply in Colorado. }lontana, North Dakota. South Dakota, and
these states, limitations for total suspended solids are determined on a case by
-------
II.
IMPACT IDENTIFICATION
II.A.
PROCESS WASTES
II.A.I.
Air Emission Sources
The impact of coal gasification plant emissions to the atmosphere vary and
depend largely on:
o Gasifier design and operating parameters
o Type and source of coal used for gasification
o Coal gas treatment steps employed
o Quantity and ultimate use of the product gas
It should be noted that the coal gasification process essentially is a
closed chemical system and that major sources of airborne emissions
generally are fugitive in nature. Table 16 summarizes such emission
sources. Each of the major sources of air emissions which, at a minimum,
will require evaluation in the EID are discussed below.
II.A.I.a. Coal Storage and Preparation. Coal storage and preparation areas
are potential sources of significant quantities of dust. Coal storage piles
have large exposed surface areas which can be sources of coal dust and fine
particulates. Coal conveying, crushing, grinding, and drying operations
also are potentially significant sources of particulate emissions. In
addition, consideration should be given to the possibility of spontaneous
combustion of coal storage piles, which results in the emission of noxious
fumes.
II.A.l.b. Gasification Processes. Normally no major atmospheric emissions
are expected from the gasification processes. However, the emission of
dust, from handling dry ash or char from the gasifier, and of odor, from
the ash and char quench systems can occur and should be addressed in the EIA.
II.A.l.c. Acid Gas Removal. Acid gas removal processes are potential sources
of atmospheric emissions (particularly H2S' cas, and thiophenes).
II.A.l.d. Methanation. During methanation no air emissions are expected for
normal operations; however, during process startups and shutdowns emissions
can occur. Of particular significance is the potential for formation and
atmospheric release of nickel carbonyl.
II.A.l.e. Compression. There are no significant atmospheric emissions
directly associated with this operation. However, a large amount of energy
is required during the compression process and the energy source emissions
from power production must be assessed.
II.A.l.f. Sulfur
nificant sources
cas, and CS2).
Recovery. Sulfur recovery processes are potentially sig-
of atmospheric sulfur emissions (in particular, H2S, S02,
54
-------
Table 16. Process stream characteristics for coal gasification and
probability ratings (low, medium, high) for fugitive air elnissions by process
Process Name Process stream characteristics
Potential for
Potentially General hazardous.
Pressure Temperature hazardous Corro- house- fugitive
volatiles siveness keeping emissions
Coal preparation low low med low poor med
Oxygen blown gasification high high high med-high med med-high
Quenching and cooling low med-high high high med med-high
Tar separation low low high med poor high
VI
VI high
Shift conversion high low low good 10w-med
Phenol recovery low med high med rned rned
Acid gas removal low 1m.... high low med rned
Methanation high high med low good rned
Further gas purification low low med low med med
Sulfur recovery low low med low rned low-med
Air blown gasification high high high rned-high med med-high
Storage low low med low med med
Source: Adapted from Cavanaugh, G.D. et a1. 1977 . Potentially hazardous emissions for the extraction
and processing of coal anc oil. Prepared for US-EPA (EPA GSO/2-75-038), Research Triangle Park NC.
-------
II.A.l.g. Ash and Solids Disposal. Normally there should be very little air
contamination from solids disposal; however, odors may occur when ash is
quenched, and dust may be emitted when dry solids are handled. Plans for
the disposal of solids should be described in the EID.
II.A.l.h. Emissions from Ancillary Facilities. In addition to those
facilities physically involved in the co~l nrenarptinu and
gasification phases, other separate, but irlterrelatect-, components are re-
quired for full plant operation. These may include such operations as:
c Steam generation and distribution
o Oxygen production
. Power generation and distribution
. End product distribution (via pipeline, etc.)
Although
process,
separate
these components serve an important supporting role in the gasification
their characterisitics and associated impacts are discussed in
guidelines. ThE'Y can be maj or contributors to emissions.
II.A.2.
Characteristics of Potential Atmospheric Emissions
The potential atmospheric emissions from the gasification of coal include
the major pollutants associated with coal and char combustion (particulates,
NOx' and SOZ emissions), as well as materials which may be emitted from the
various operations in the gasification process described above. A summary
of major waste streams (air, water, solids), their principal components,
source, disposition, and associated processes are presented in Table 17.
A list of possible pollutants, which include particulates, metals, gases,
polynuclear aromatics, and other organics, also is presented in Table 17.
Of particular concern, because of their potentially adverse environmental
and health effects, are:
o Emissions of tr~~e elements present in coal
. Trace compounds formed in the gasification process
o Sulfur and carbonyl compounds.
II.A.Z.a. Tra~e Elements in Coal. The trace elements present in the processed
coal must be considered as potential atmospheric emissions. The content of
trace elements in coals from different regions and of different types is
highly variable (see Table 18). Therefore, the potential for trace element
emissions will vary with the type of coal used as well as the type of gasifi-
cation process used. Considerable- data on trace elements in coals are
available from the U.S. Bureau of Mines and the U.S. Geological Survey;
however, the composition of particular coal must be determined because most
of the data available are not site specific.
Little is known about the fate of trace metals in coal gasification. Trace
elements of particular concern, because of their potential toxicity and
volatility, include mercury, silenium, arsenic, lead, cadmium, beryllium,
and fluorine. During coal combustion, trace elements volatilize in the
firebox and then recondense into fine particulates which are emitted with
the flue gas; often these particles are so fine that they are difficult to
collect with particulate control equipment. Also during coal gasification,
volatilization is enhanced because of the reducing atmosphere in which the
process takes place.
56
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WASTE STREAM
Coal dus t
Stack gas
Acid gas
Exhaust
emissions
Runoff
leachings
Wastewater
Vt
.....,
Blowdown
Cooling vater
Sanitary sewage
Rocks and debris
Table 17.
Nature and sources of major waste streams associated with the gasification of coal
!!,-OCESS
PRINCIPAL COMPONENTS
Carbon particles
CO2"' 502' N2' 02
Nitrogen
H2' C02' CH2' COS, H2S'
N2
CO, HC, NOx' particulate
Pyrites, sediment, oil,
organic matter
Sediment
Dissolved salts
NH3' phenols, cyanide
ThIocyanate, BTX
Dissolved salts
Heat
~
Feedstock crushings and
grinding
Steam generation
Stack gas cleanup
Oxygen generation
Product of shift
conversion
Automobile traffic
Feedstock storage
Ash ponds
Land surface
Water treatment
CAsification
Product of shift
Methanation
conversion
Boilers/cooling towers
Heat exchangers
Organic/nitrogen compounda Washrooms
Feedstock cleaning
(continued on next page)
DISPOSITION
Containment and recovery
Treatment/discharge
Discharge
Sulfur recovery
Discharge
Treatment/utilization
Discharge
Treatment/utlization
Treatment and reuse
Treatment and reuse
Utilization discharge
Treatment and utlization
Disposal/utilization
Cyclone separators, bag filters, enclosure
Wellman-Lord, limestone injection, lime
scrubbing, catAlytic oxidation, double
alkali, Citrate
H2S can be selectively removed from a gas
sEream by a rectisol hot potassium
carbonate, Sulfinol, ~ffiA, DIPA, or
similar process. Claus and Stretford
processes recover elemental sulfur from
"2S rich streams Tail gases from these
units can be treated by incineration,
Beavon, Wellman-Lord, or SCOT process.
Neu t r al ha t ion
Settling
Coagulation
Chevron, Phenosolvan, Phosam, biological
oxidation
Chevron, Phenosolvan, Phosam, bio. oxidation
Waste heat recover, cooling towers
Biological oxidation
Landfill/construction material
-------
WASTE STREAM
Tar
Char
Ash
Spent catalysts
Spent purifying
media
Sludge
Refuse
Table 17.
Nature and sources of major waste Dcreams associated with the gasification of coal (Concluded)
PROCESS
PRINCIPAL COMPONENTS
COD, DS, SS, CO, CH4'
Phenols, NH3' HCN,
Thiocyanate, H2S
Fixed carbon, sulfur
Inert residue
Cobalt, molybdenum, iron
Bauxite
Nickel
Iron or zinc oxide
Spent carbon
Sul fi tes
Solids, biomass
SOURCES
Gasification
Gasificstion
Gasification, steam
generation
Shift conversion
Sulfur recovery
Methanation
Final purification
Final purification
Stack gas cleanup
Wastewater treatment
Work areas
DISPOSITION
Utilization
Disposal/utilization
Disposal/utilization
Treatment and recovery
Treatment and disposal
Treatment and disposal
Treatment and disposal
Disposal
Treatment and disposal
Trestment and disposal
Treatment and disposal
U1
-------
Table 18. Ranges of chemical constituents of
representative U.S. coals
Item Range (%) Item Range (ppm)
Major constituents: Trace elements:
C 55.2 - 80.1 As 0.5 93.0
H 4.0 - 5.8 B 5.0 - 224.0
N 0.8 - 1.8 Be 0.2 4.0
o 4.2 - 16.0 Br 4.0 52.0
Maj or characteristics: Cd 0.1 65.0
Co 1.0 43.0
Air dry loss 1.4 - 16.7 Cr 4.0 54.0
Moisture 0.1 - 20.7 Cu 5.0 61. 0
Volatility 18.9 - 52.7 F 25.0 - 143.0
C, fixed 34.6 - 65.4 Ga 1.1 7.5
Ash 2.2 - 25.8 Ge 1.0 43.0
Minor constituents: Hg 0.02 - 1.6
Mn 6.0 - 181. 0
Al 0.42 - 3.0 Mo 1.0 30.0
Ca 0.05 - 2.7 Ni 3.0 80.0
Cl 0.01 - 0.5 P 5.0 - 400.0
Fe 0.3 - 4.3 Pb 4.0 - 218.0
K 0.02 - 0.4 Sb 0.2 8.9
Mg 0.01 - 0.2 Se 0.4 7.7
Na 0.00 - 0.2 Sn 1.0 51.0
Si 0.58 - 6.1 V 11.0 78.0
Ti 0.02 - 0.2 Zn 6.0 - 535.0
S, organic 0.3 3.1 Zr 8.0 133.0
S, pyritic 0.06 - 3.8
S, S04 0.01 - 1.1
S, total 0.4 - 6.5
S, X-ray 0.5 - 5.4
Source:
Ruch, R. R., H. J. Gluskoter, and N. F. Shimp. 1974.
Occurrence and distribution of potentially volatile
trace elements in coal. EPA-650/2-74/054. Illinois
State Geological Survey.
59
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Some elements were likely to appear in groups; that is, when one was higher in
concentration, the others in the groups were higher. The groups were:
. Zinc (Zn) , cadmium (Cd)
. Arsenic (As), cobalt (Co), copper (Cu), nickel (Ni), lead (Pb),
antimony (Sb)
. Potassium (K), titanium (Ti), aluminum (AI), silicon (Si)
. Manganese (Mn), calcium (Ca)
. Sodium (Na), chlorine (CI)
Germanium (Ge), beryllium (Be), and boron (B) are likely to be associated with
the organic part of the coal, whereas mercury (Hg), zirconium (Zr). Zn, As,
Cd, Pb, Mn, and molybdenum (Mo) , are likely to be associated with the inorganic
part of the coal. Because equal cleaning processes tend to separate the in-
organic from the organic part of the mined coal, such processes will have a
significant effect on the composition of the feed to a coal gasification process.
II.A.Z.b. Trace Compounds Formed in Processing. Little information is avail-
able as to concentrations of trace compounds in atmospheric emissions from
coal gasification. Compounds which may form include the polynuclear aro-
matics and other organic materials shown in Table 19. Again, the formation
of many of these compounds is promoted by the reducing atmosphere in which
gasification takes place. Many of these compounds are of particular con-
cern because they are carcinogenic or otherwise toxic.
II.A.Z.c. Sulfur Compounds. Sulfur which is removed from the product gas
generally is reclaimed in the form of elemental sulfur. However, during
the removal and recovery processes there is a potential for atmospheric
emissions of sulfur in the form of SOZ, thiophene, HZS, cas, CSZ, and
other reduced sulfur compounds. Many of the reduced sulfur compounds are
of concern because they are potentially toxic or odorous.
II.A.Z.d. Carbonyl Compounds. Regeneration of catalysts used
cation (particularly in methanation) is a potential source of
and iron carbonyl emissions. These are of particular concern
their high toxicity.
in coal gasifi-
nickel, cobalt,
because of
In summary the permit applicant should include, at a minimum, the following
information relative to air emissions in the EID.
. Volumes, concentrations, and temperatures of each air emission point
. Conditions of discharge point including height and location
. Control technology proposed for each emission point including
efficiency
. Fugitive emissions including composition and quantity
. Control technology proposed to minimize fugitive emissions
. Distribution of trace elements in feed coal
. Projected ambient air concentrations at fence line and in neighboring
areas of high receptor incident.
II.A.3.
Water Effluent Sources
Gasification plants are not major sources of waterborne effluents.
Also
60
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Table 19. potentta11y hazardous substances suspected
present in coal conversion plant process streams
Chemical classification
Compound
Phase
Acids and anhydrides
Maleic acid
Cresyl1c acid
Sulfuric acid
Anthraquinone
acid
disulfuric
liq uid
liq uid
liquid.
liq uid
Alcohols
Aliphatic alcohols
Aromatic alcohols
liquid
liquid
Amines
Diethylamines
Methylethylamines
Ammonia
gas
gas
gas/liquid
Inorgani~ salt::;
;\_l!I!!!onia suI fate
liquid
Carbonyl compou~ds
Ketones
Aldehydes
gas/liquid
gas/liquid
Combustion cases
Carbon monoxide
Sulfur oxides
Nitrogen oxides
gas
gas
gas
Heterocyclics
Pyridines
Pyrroles
(Mono) Benzofurans
gas/liquid
gas/liquid
gas
Hydrocarbons
Benzene
Toluene
Xylene
Ethylcyclopentane
Decane
Undecane
Dodecane
Naphthalene
Ethylbenzenes
Propyl benzenes
Ethyltoluenes
Trimethylbenzene
Ole fins
gas/liquid
gas/liquid
gas/liquid
gas
gas
gas
gas
gas
gas
gas
gas
gas
gas
Phenols
Phenols
Dimenthyl phenol
Cresols
Xylenols
Phenyl phenols
Alkyl phenols
Alkyl cresols
Ethylphenols
Propylphenols
Methylethylphenol
Indanols
Beta-naphthol
Pyrocatechol
Resorcinol
Methyl resorcinol
gas/liquid
liq uid
gas/liquid
gas/liquid
gas
gas
gas
gas
gas
gas
gas
gas
gas
gas
gas
Source:
Cavanaugh, G.D., et al. 1975. Potentially hazardous
emissions for the extraction and processing of coal
and oil. USEPA 650/2-75-038, Research Triangle Park NC.
61
-------
there are few data on concentrations and volumes of effluents because there
are no commercially producing coal gasification plants in the U.S. In
general, waste liquids are evaporated or recirculated. Wastewater charac-
teristics from two high Btu coal gasification processes are presented in
Table 11. The major sources of these effluents are given below.
II.A.3.a. Coal Preparation Runoff and Wet Scrubber Dust Collector Effluent.
Effluents from these sources contain suspended fines, sulfur compounds, and
heavy metals.
II.A.3.b. Gasifiers. Liquids from gas cooling and from the waste heat
boilers normally are used as quench water in the tar separator prior to
treatment.
II.A.3.c. Sulfur Plant Recirculation Water Purge. Discharges depend on the
nature of the sulfur reclamation system used. Discharges from the Claus
process largely are waste oils; however, the liquid wastes from the Stret-
ford process include anthraquinone disulfonate, metavanadate, citrate,
thiosulfate, thiocyanate, and sodium salts.
II.A.3.d. Tar Separation. The purge water from the tar separation unit con-
tains ammonia, phenol, and tars as well as reduced sulfur compounds.
II.A.3.e. Water Treatment and Boiler Blowdown. The blowdown from boilers,
cooling towers, and water treatment facilities include waters with high
concentrations of dissolved solids.
To evaluate liquid wastestreams adequately, the EID should provide, at a
minimum, the following information:
o Existing water quantity and quality data (surface and subsurface)
o Sources and volumes of all wastewater streams
o Occurrence and duration of wastewater flows
o Composition of wastewaters
o Nature and volume of irregular flows including surface drainage
e Proposed measures to reduce or avoid potential environmental impact.
II.A.4.
Solid Waste Sources
There are several sources of solid wastes from coal gasification facilities.
The major source is the gasifier; composition and quantity of this waste
is largely dependent on the coal that enters the gasifier vessel. Other
solid wastes include flyash and sludge which are collected from the various
processes, as shown in Table 20.
These solids may contain significant
organics which could contaminate the
posed of properly.
amounts of leachable heavy metals and
environment if not treated and dis-
To evaluate the potential for impact from solid waste generation, the
applicant should provide at least the following information in the EID:
62
-------
Table 20.
Solid wastes from coal gasification faci1ities*
Source
Quantity (tons/day)
Quenched ash from gasifiers
1,550
Steam generator bottom ash
38
Steam generator fly ash
114
Intake water clarifier sludge
2
Biotreatment sludge
4
Miscellaneous fly ash
150
Spent catalysts
*P1ant size, 7.08 x 106 m3/d (250 mmscf/day).
2
Source:
Rittman Associates, Inc. 1975. Environmental effects, impacts,
and issues related to large scale coal refining complexes.
Available from National Technical Information Service, NTIS
FE-1508-T2. Washington DC.
63
-------
o Source and quantity of solid wastes generated
o Composition of solid wastes generated
o Composition of possible leachate from solid wastes
o Proposed measures to handle and dispose of solid wastes
II.B.
TOXICITY AND POTENTIAL FOR ENVIRONMENTAL DAMAGE FROM SELECTED
POLLUTANTS
ILB.l.
Human Health Impacts
A coal gasification plant's airborne and waterborne emissions may contain
substances which could have serious impacts on human health. Both heavy
metals and a variety of complex hydrocarbons including polycyclic organics
may be emitted from coal gasification facilities (see Table 19). However
it should be noted that coal gasification is a closed process and therefore
the emission problems will be considerably less than with coking plants.
Because of lack of experience in the U.S., the quantities and significance
of emissions are not well established nor understood and, therefore, the
background data and documentation relative to specific health impacts are
slight. A complete review of the literature is now available (ORNL 1977).
Some evaluations can be made by review of evidence gathered for coking plants,
electric generating stations, and other facilities that emit similar constitu-
ents. The following describes the health-related effects of selected pollut-
ants.
II.B.l.a. Carcinogens. ~orrelations have been drawn repeatedly between ex-
p0su~es of coke even workers to soot, coal dust, and other coal combustion
or pyrolysis products and an elevated incidence of cancer of the lung and
urinary tract as well as other vital locations (National Institute for
Occupational Safety and Health 1975). Reports of increased skin cancer in
workers at coal hydrogenation plants also suggest an elevated carcinogenic
risk. Those exposed to the process had a skin cancer incidence between 16
and 37 times higher than that of the regional and national populace
(Sexton 1975).
Other factors that may be of consequence are the carbonization temperature,
the type of retort, and the time of exposure to the tars (National Insti-
tute for Occupational Safety and Health 1975; Doll 1974; Kawai 1967). During
the quenching and cooling of the offgas and the tar separation, the worker
may be exposed to selenium, benzene, nickel, and lead in the emissions from
the tar separation unit. Other suspected carcinogens that may be in the
emissions include arsenic. cadmium. beryllium, chrysene, benzo(e)pyrene,
benz(a)anthracene, and benzo(a)pyrene.\ If methanation occurs during the
reaction, then nickel carbonyl and benzene may be among the emissions
(Cavanaugh 1975). If coal ash is taken directly from the process to the
environment, it could emit known carcinogens to the environment.
II.B.I.b. Sulfur Dioxide and Hydrogen Sulfide. The impact
trations of sulfur dioxide and sulfates (especially in the
particulates), has been well documented (USEPA 1970).
of high cone en-
presence of
Likewise hydrog~n sulfide is stron~ly irritating to the respiratory organs.
At high concentrations (1,000 mg/m ), hydrogen sulfide is extremely toxic
and may paralyze the brain center that controls the respiratory movements
(Cavanaugh 1975).
64
-------
Table 21.
Possible health problems associated with trace metals
Metal or metal compound
Nickel carbonyl
Antimony. arsenic,
cadmium, cobalt,
copper, iron, lead,
magnesium, manganese,
tin, and zinc oxides
Nickel
Cadmium
Chromium and compounds
Bery1ium and compounds
Arsenic
Cobalt
Lead and compounds
Mercury and compounds
Vanadium
Health problems
Suspected carcinogenesis
Fume fever
Nasal cancers
Prostate cancer
Carcinogenesis
Carcinogenesis
Poisoning
Cancer of the skin
Poisoning
Carcinogenesis
Nasal cancers
Kidney damage
Mutagenic and
teratongenic effects
Inhibition of lipid
formation
65
Reference
(Sunderman and
Donnelly 1965)
(Cavanaugh 1975)
(Wa1dbott 1973)
(Gilman and
Ruckerbauer 1963)
(Pott 1965);
(Kipling and Waterhouse
1967)
(Hueper 1961)
(Reeves et a1. 1967);
(Wager et a1. 1969)
(Nishimuta 1966)
(Wickstrom 1972)
(Lee and Fraumeni
1969)
(Gilman and
Ruckerbauer 1963)
(Zawirsica and Medras
1968)
(Zollinger 1953)
(D'Itri 1972)
(Stokinger 1963)
-------
II.B.l.c. Nitrogen Compounds. Nitrogen oxides are a problem only where coal
is burned as a fuel. Nitrogen oxides are pulmonary irritants and may impair
the ability of the lungs to clear inhaled infectious organisms. Exposure
to nitrogen dioxide also can be corrosive to the mucous lining of the lungs.
At high concentrations, it may cause pulmonary edema and even death, while
chronic exposure may produce emphysema, po1yeythamia, and leukocytosis. In
addition, nitrogen oxides have been shown to be involved in the formation
of photochemical smog (USEPA 1971c).
II.B.l.d. Hydrocarbon~. Hydrocarbons playa vital role in the formation of
photochemical smog (USEPA' 1971b).
II.B.l.e. Carbon Monoxide. The toxicity of carbon monoxide is associated with
its reactions with hemoproteins. It is anticipated that there will be no
increase of ambient concentrations beyond national ambient air standards and,
therefore, it is expected that no adverse impact will be associated with the
emission of carbon monoxide from coal gasification plants (USEPA 1971a).
II.B.l.f. Ammonia. Ammonia is a highly irritating gas with a strong, pungent
odor. It forms ammonium hydroxide when it comes in contact with the moisture
of the throat and bronchi. Ammonium hydroxide is caustic, but it is not a
threat to human health. Extremely high concentrations, however, (1,700-
4,500 mg/m3) can produce pulmonary edema (Wa1dbott 1973).
II,B l.g. Tr~ :_Metal~. Among the possible health problems associated with
trace r. :als . ,'e those shown in Table 21. The appropriate references should
be re:v':\ved by the permit applicant to ascertain the significance of the
impact < ~ssociated with trace metal emissions from the proposed coal
gasificat In facility.
To adequ;:1:ply ev' uate potential impacts to human health the applicant
should include at least the following information in the EIA:
e A~'~lysis of coal to be used in the gasification process
t: Pre jec ::lon of emissions of potentially toxic substances (volumes
and duration)
. Analysis of sensitive receptors (by use of isopleths or other suit-
able technique)
G Projection of ground level maximum concentrations of potentially
hazardous substances
. Description of proposed measure to avoid or reduce potential adverse
effects from toxic materials.
ILB.2.
Biological Impacts
.The biological environment also may be affected bv certain Pollutants
I . ,
especlally heavy metals, which are toxic to many terrestrial and aquatic
organisms, both complex and simple.
The potential impacts on terrestrial and acruatic biota may be categorized
by the following waste streams and pollutanrs:
66
-------
. Air pol:utants - emissions of heavy metals, sulfur dioxide, and
particulates.
. Wastewater discharges - water pollutants such
toxic organics from leaching of solid wastes,
from stabil{zation/evaporation ponds, cooling
atmospheric washout of air pollutants.
. Solid wastes - stockpiling and dumping of slags and other solid
wastes.
as heavy metals and
infiltration, or leaks
tower drift and
At a minimum the following information should be
assess adequately the magnitude and significance
resources:
. Discharges and sinks for specific toxic materials such as heavy
metals and organics (include information on volume, duration, and
time of discharges)
o Characteristics of the aquatic and terrestrial biota of the impact
area (species composition, diversity, abundance, densities, impor-
tance values)
. Determination of tolerance or
species of plants and animals
o Proposed measures to avoid or
communities.
developed in the EID to
of impacts to biological
sensitivity thresholds
in the impact area
reduce adverse impacts
for selected
to biological
II. C.
OTHER IMPACTS
II.C.l.
Raw Materials and Byproduct Handling
The principal area of concern with respect to handling raw materials is
with the coal. Potential environmental impacts associated with coal
handling result from runoff from coal storage areas and from dust generated.
Coals may contain various elements (Table 22) which may enter thin films
of water that exist when the coal is damp and exposed to air. Rainfall will
wash off this film and produce an initial runoff that is often acid and
usually high in concentrations of iron, copper, and/or zinc, and that has
objectionable amounts of suspended solids and organic material. The acid
and reducing nature of the runoff is caused by the sulfur compounds in the
coal; these characteristics increase the solubility of many metallic im-
purities.
In addition to possible impacts associated with. coal handling and processing,
the transport of byproducts from coal gasification plants may represent a
significant environmental impact in the form of spills, ruptures, and so
forth; for example, the shipment of byproducts such as elemental sulfur and
coal tars, could pose a spill hazard. Certain waste products (liquors, ash,
slag, etc.) also may require transport from the plant for final disposal
which could result in spills and contamination. Usually these materials only
have a low or moderate toxicity rating but spills are not desirable aesthetic-
ally and the potential does exist for degradation of water quality as a result
of direct spillage or indirect contamination through leaching. Therefore the
applicant should project the probability of such accidents ,occurring and dis-
close any plans that are proposed to handle these potential hazards.
67
-------
Table 22. Coal pile drainage water:
steam electric generating plants.
Contaminant
Range
Alkalinity
Acidity
BOD
COD
Total solids
Total dissolved
Total suspended
Annnonia (N)
Nitrate (N)
P
Turbidity
Hardness (CaC03)
Sulfate
Chloride
Al
Cr
Cu
Fe
Zn
o 82
8 - 27,810
o 10
85 1,099
1,330 - 45,000
247 - 44,050
22 3,302
o 1.8
0.3 2.2
0.2 1.2
3 505
130 1,850
133 - 21,920
4 481
825 1,200
o 16
1.6 3.4
0.1 - 93,000
0.01 - 23
solids
solids
Analyses from nine coal-fired
Analyses (mg. 1)
Average of
three plants,
high sulfur coal
One plant
low sulfur coal
o
24,800
NA
NA
NA
26,500
NA
NA
NA
NA
NA
NA
16,000
NA
1,012
8
2.6
48,800
18
24
6
NA
NA
NA
NA
NA
NA
NA
NA
6
NA
NA
NA
NA
NA
NA
1
NA
NA = Not available.
US Environmental Protection Agency. 1974. Development document for
effluent guidelines and new source performance standards for the
steam electric power generating point source category. EPA 440/1-74
029-a. Effluent Guidelines Division, Office- of Water and Hazardous
Materials, Washington DC.
Source:
68
-------
II.C.2.
Site Preparation and Plant Construction
The environmental effects of site preparation and construction of new coal
gasification facilities are common to most major land disturbing activities.
Although erosion, dust, noise, vehicular traffic and emissions, and some 105s
of wildlife habitats are to be expected, they also should be minimized through
good construction practices wherever possible. At present, however, neither
the quantities of the various pollutants resulting from site preparation and
construction nor their effects on the integrity of aquatic and terrestrial
ecosystems has been studied sufficiently to permit broad generalizations.
Therefore in addition to the impact assessment framework provided in the EPA
document, Environmental Impact Assessment Guidelines for Selected New Source
Industries, a suggested checklist of important study items is presented in
Table23 for further guidance to the applicant. The basic components of site
preparation and plant construction outlined in the table include preconstruction,
site work, permanent facilities, and ancillary facilities. At this time only
potentially significant areas of impact are presented in the checklist but a
system of values and significance should be acquired at an individual site or
for a region. The permit applicant also should tailor all proposed conserva-
tion practices to the specific site(s) being considered in order to account
for and to protect certain site specific or endangered species, archaeological/
historical sites high quality streams, wetlands, or other sensitive areas on
the site. All mitigating conservation measures which are proposed to avoid
or reduce adverse impacts from preparations of the sit8 and construction
activities sho~ld be described in the EID
II.C.3.
Transportation Impacts
In this section we will discuss, in some detail, the emissions of various
transportation modes involved with coal gasification facilities.
II.C.3.a. Railroads. Railroads,
70% of all bituminous coal mined
in transporting raw coal:
. Conventional
. Unit
o Dedicated
diesel and electric powered, transport nearly
in the U.S.* Three types of trains are used
When conventional trains are used, cars carrying coal are treated like any
other car. Unit trains are ~ade up entirely of cars carrying coal. When
coal is transported by conventional trains, the Interstate Commerce Commission's
(ICC) general rates apply. In contrast, a special rate of almost one third
less applies to special unit trains.
Unit trains offer several other advantages including better use of equipment,
elimination of standard railroad tie-ups such as classification yards and lay-
over points, and promotion of better coordination between mine production and
consumers, particularly consumers dependent on coal supplied by a single mine
(National Academy of Engineering, 1974).
*.~though data for all coals are not available, bituminous coal represents all
but a small fraction of coal mined.
69
-------
Table 23. Outline of potential environmental
and relevant pollutants resulting from site
ration and construction practices.
Construction
practice
1.
Preconstruction
a. Site inventory
(1) Vehicular traffic
(2) Test pits
b. Environmental
monitoring
c. Temporary controls
(1) Sedimentation
ponds
(2) Dikes and berms
(3) Vegetation
(4) Dust control
2.
Site 1,,'ork
a.
Clearing and
demolition
(1) Clearing
(2) Demolition
b. Temporary
facilities
(1) Shops and
sheds
storage
(2) Access roads and
parking lots
Potential environmental
impacts
Short term and nominal
Dust, sediment, tree injury
Tree root injury, sediment
Negligible if properly done
Short term and nominal
Vegetation destroyed,
quality improved
Veg8tation destroyed,
quality improved
Fertilizers in excess
Negligible if properly
water
water
done
Short term
Decreased area of protective
tree, shrub, ground covers;
stripping of topsoil; in-
creased soil erosion, sedi-
mentation, stormwater runoff;
increased stream water tem-
peratures; modification of
stream banks and channels,
water quality
Increased dust, noise, solid
. wastes
Long term
Increased surface areas impervious
to water infiltration, increased
water runoff, petroleum products
Increased surface areas impervious
to water infiltration, increased
water runoff, generation of dust
on unpaved areas
(continued on next page)
70
impacts
prepa-
Primary
pollutants
Dust, noise, sediment
Visual
Sediment spoil, nutri.
ents, solid waste
Dust, sediment, noise
solid wastes, wood
wastes
Gases, odors, fumes
particw.ates, dust,
deicing chemicals,
noise, petroleum
products, waste-
water, solid wastes,
aerosols, pesticide:;
-------
Table 23. Outline of potential environmental impacts
and relevant pollutants resulting from site prepa-
ration and construction practices (Continued).
Construction
practice
Potential environmental
impacts
Primary
pollutants
(3) Utility trenches
and backfills
(4) Sanitary facili-
ties
(5) Fences
(6) Laydown areas
(7) Concrete batch
plant
(8) Temporary and
permanent pest
control (ter-
mites, weeds,
insects)
c. Earth-Hork
(1) Excavation
(2) Grading
(3) Trenching
(4) Soil trea~ijent
d. Site drainage
(1) Foundation
drainage
(2) Dewatering
(3) Well points
(4) Stream channel
relocation
e. Landscaping
(1) Temporary seeding
(2) Permanent seeding
and sodding
Increased visual impacts, soil
erosion, sedimentation for
short periods
Increased visual impacts, sol~d
wastes
Barriers to animal migration
Visual impacts, increased runoff
Increased visual impacts; dispo-
sal of wastewater, increased
dust and noise
Nondegradable or slowly degradable
pesticides are accumulated by
plants and animals, then passed
up the food chain to man. De-
grcdable pesticides having short
biGlogical half-lives are pre-
ferred for use
Long term
Stripping, soil stockpiling,
and site grading; increased
erosion, sedimentation, and
runoff; soil compaction; in-
creased in-soil levels of
potentially hazardous materials;
side effects on living plants
and animals, and the incorpora-
tion of decomposition products
into food chains, water quality
Long term
Decreased volume of underground
water for short and long time
periods, increased stream flow
volumes and velocities, down-
stream damages, water quality
Decreased soil erosion and over-
land flow of stormwater,
stabilization of exposed cut
and fill slopes, increased
water infiltration and under-
ground storage of water,
minimized visual impacts
(continued on next page)
Dust, noise, sediment,
debris, wood wastes,
solid wastes, pesti-
cides, particulates,
bituminous products,
soil conditioner
chemicals
Sediment
Nutrients, pesticides
-------
Table 23. Outline of potential environmental impacts
and relevant pollutants resulting from site prepa-
ration and construction practices (Continued).
Construction
practice
3.
Permanent facilities
a. Coal gasification
plant and heavy
traffic areas
(1) Parking lots
(2) Switchyard
(3) Railroad spur
line
b. Other buildings
(1) Warehouses
(2) Sanitary waste
treatment
c. Possible ancillary
facilities
(1) Intake and dis-
charge channel
(2) Water supply and
treatment
(3) Stormwater drain-
age
(4) Wastewater treat-
ment
(5) Dams and
impoundments
(6) Breakwaters, jet-
ties, etc.
(7) Fuel handling
equipment
(8) Seed storage
areas and prepa-
ration facilities
(9) Oxygen plant and
gas upgrading
plant
(10) Cooling towers,
power transmis-
sion lines,
pipelines, sub-
stations
Potential environmental
impacts
Long term
Stormwater runoff, petroleum
products
Visual impacts, sediment, runoff
Stormwater runoff and sedimenta-
tion
Long term
Impervious surfaces, stormwater
runoff, solid wastes, spillages
Odors, discharges, bacteria,
viruses
Long term
Shoreline changes, bottom topog-
raphy changes, fish migration,
benthic fauna changes
Waste discharges, water quality
Sediment, water quality
Sediment, water quality
Dredging, shoreline erosion
Circulation patterns in the
waterway
Spillages, fire, and visual im-
o pacts
Visual impacts, waste discharges
Sediment runoff, landscape alter-
ation, waste discharges
Visual impacts, sedimentation and
erosion
(continued on next page)
72
Primary
pollutants
Sediment, dust, noise,
particulates
Solid wastes
Sediment, trace ele-
ments, noise,
caustic chemical
wastes, spoil, floc-
culants, particulat-~
fumes, solid wastes,
nutrients.
-------
Table 23. Outline of potential environmental impacts
and relevant pollutants resulting from site prepa-
ration and construction practices (Concluded).
Construction
practice
Potential environmental
impacts
Primary
pollutants
(11) Conveying systems
(cranes, hoists,
chutes)
(12) Cooling lakes and
ponds
(13) Solid waste
handling equipment
(incinerators,
trash compactors)
d. Security fencing
(1) Access road
(2) Fencing
Visual impacts
Conversion of terrestrial and free
flowing stream environment to a
lake environment(land use trade-
offs); hydrological changes,
habitat changes, sedimentation,
water quality
Noise, visual impacts
Long term
Increased runoff
Barriers to animal movements
Particulates, dust,
solid wastes
Sediments, wood
wastes
Source:
Rittman Associates, Inc. 1974. General environmental guidelines for
evaluating and reporting the effects of nuclear power plant site prep-
aration, plant and transmission facility construction. Modified from:
Atomic Industrial Forum, Inc. Washington DC.
73
-------
The dedicated railroad, the third rail option, is used exclusively for trans-
porting coal. A dedicated railroad generally is used only when an existing
railroad is not available and when the railroad will link a mine to a single-
source user.
II.C.3.b. Barges. Barges only move about 11% of the raw coal shipped in the
u.s. (based on the fact that bituminous accounts for over 90% of all coal
produced in the U.S.). In such areas as the Ohio River Valley, barges can be
loaded directly from the mine. When mines are not located adjacent to a
navigable river, the coal has to be transported to the barge loading facility
by either truck or train (usually by train).
ILC.3.c.
advantage
effective
Trucks. Moving as much coal as barges do, trucks offer the
of flexibility; their major disadvantage is a failure to be
for moving large quantities long distances.
major
cost
II.C.3.d. Pipelines. Slurry pipelines can be used to transport pulverized coal
suspended in water. In t~is system, coal has to be processed to obtain the
proper particle size. Pumping stations, dewatering facilities, and in some
cases, storage facilities also are required. The major advantage of slurry
pipelines for transporting coal long distances is low operating cost
(Mutschler and others, 1973). High capital costs and water requirements are
major disadvantages.
In terms of potential environmental impacts, four impact categories
addressed in the EID (see Table 24 for an estimate of environmental
for six transporation technologies by region):
. Water
., Air
. Solids
. Land
should be
residuals
1. Water - Barges may contribute dissolved solids to the river water.
Drying the coal, after transporting via a slurry pipeline, produces
a water effluent with negligible amounts of coal in it. Other modes
of coal transportation do not involve water.
2. Air - Particulates, ranging from 1 to 46 tons per 1012 Btu's trans-
ported (Table 24), represent those associated with wind losses along
the route and at the end points. A 2% wind loss is assumed for con-
ventional trains as opposed to 1% for unit trains. river barges, and
trucks. Based on these assumptions, transportation methods emit more
particulates than any of the technologies in the coal development
system. Other air emissions from transportation methods are due to
diesel fuel combustion; thus, haul distances govern the magnitude of
the total amounts emitted. In any case, the nitrous oxide and sulfur
dioxide emissions are low, ranging from 0.5 to 4.3 tons and 0.1 to 4.4
tons, respectively, for each 1012 Btu's transported. Comparisons
between transporation modes are meaningful because equal haul distances
have not been assumed.
3. Solids - Solids arise from water and air emissions.
74
-------
Table 24.
Environmental and Health Impacts of Coal Transportation: By coal region and transportation mode
Fila Occupational health
Air pollutants (tons/1012 B tu ' s) 1012 Btu's
(J) .j...J
UJ UJ
Q) i=1 0
.j...J 0 UJ ,...,
Cd ,..Q UJ ffi
,..., !-< Q) Cd ::I UJ UJ
::I Cd '0 Q) .j...J Q) >-.
-. (J) >Q UJ ..., Cd
..., O ..c '0 I ..c !-< "d
.j...J !-< Q) ..., "d Q) .j...J ::I I
!-< ~ ~ "d "d ,..., i=1 !-< Cd or-; i=1
Cd 0 0 >-. 0 ,..., 0 Cd
-------
Table 24.
Residuals for the transportation of coal (Concluded)
F/ra Occupational health
Air pollutants (tons/1012 B tu ' s) 1012 Btu's
.j..J
()) ()) ())
Q) ~ 0
.j..J 0 ()) M
cu ..c U) ~ ~
M ~ Q) cu ;:I U) ())
;:I CU "d Q) .j..J Q) >,
tJ tJ >, ()) >,~ ()) 'M CU
'M O .£: "d I .£: ~ "d
.j..J ~ Q) 'M "d Q) 0J .j..J ;:I I
~ >.: >.: "d "d M J:: ~..... cu 'r; J::
cu 0 0 >, 0 ri 0 CUtJO Q) J:: CU
p... Z tI) ::r: u
requirement
Source: University of Oklahoma, Science and Public Policy Program 1975
-------
4. Land - The National Academy of Engineering (NAE) has pointed out that
most new overland transportation systems will need additional rights-
of-way and new facilities. Railroad land use requirements for coal
transport are based on the percentage of coal to total rail freight
and on the percentage of coal originating in the area. Because haul
distances are not equal among the 6 transportation modes, values given
in Table 24 are not directly comlarable. Land use for coal transported
ranges from 1 to 70 acres per 10 2 Btu's transported. Of additional
interest are the assumptions that rail rights-of-way averages 6 acres
per mile (approximately 55 feet wide) a conveyor requires 30 feet of
right-of-way along its length (3.64 acres per mile). and trucks average
1.67 x 10-6 acres per ton-mile (allow 50% error in the data) (University
of Oklahoma, 1975).
II.D.
MODELING OF IMPACTS
The ability to forecast environmental impacts accurately often is
by the use of mathematical modeling of the dispersion and
dissipation of air and water pollutants as well as the effects of
improved
storm runoff.
Two of the most widely used and accepted water quality models are:
. DOSAG (and its modifications)
. The QUAL series of models developed by the Texas Water Development
Board and modified by Water Resources Engineers, Inc.
Some of the parameters that these models simulate are:
. Dissolved oxygen
o BOD
o Temperature
o pH
. Solids
In addition, there are many available water quality models that were de-
veloped in association with NPDES activity and the need for optimization of
waste load schemes for an entire river basin.
There also are available mathematical models that may be used for air
pollution studies:
o For short term dispersion modeling of point sources, EPA's PTMAX,
VALLEY PTDIS, PTMTP and CRSTER models may be employed.
. For modeling of long term concentrations over larger areas, the
EPA's Climatological Dispersion and AQDM models may be used for
point and area sources.
In general, the use of mathematical models is indicated when arithmetic
calculations are too repetitious or too complex. Their use also simplifies
analysis of systems with intricate interaction of variables. Models thus
offer a convenient way of describing the behavior of environmental systems,
but their use and applicability should be determined on a case by case
basis. (For a more detailed discussion of modeling techniques see section
II.F., Modeling of impacts, in Environmental Impact Assessment Guidelines
For New Source Fossil-Fueled Steam Electric Generating Stations.)
77
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III.
POLLUTION CONTROL
IILA.
POLLUTION CONTROL TECHNOLOGY: IN PROCESS CONTROLS
Emissions can be reduced
which should be examined
fully in the EID.
within the process through a variety of steps
carefully during project planning and described
Principal methods to be considered to reduce effluents and emissions
include:
. Use of process wastewater for
. Use of process wastewater for
o Recovery of sulfur from waste
o Recycling of waste gas
o Wetting and covering of coal storage and preparation areas.
cooling purposes
scrubbing purposes
gases
III.B.
POLLUTION CONTROL TECHNOLOGY: END OF PROCESS CONTROLS (EFFLUENTS
FROM PROCESS)
The handling of the process and cooling water stream can represent one of
the major pollution problems in an SNG plant. For economic and other reasons
many gasification plants are seriously considering recycling all process
water. The SNG plant water treatment systems have to be designed specifically
for each plant. No one process will be universally applicable. The variety
of coal sources and gasifier operating conditions differentiate the aqueous
wastes in the various processes under development.
Water treatment technology, historically, has been divided into primary,
secondary. and tertiary or advanced treatment. Primary treatment usually
occurs first and is designed to remove much of the suspended solids and
biochemical oxygen demand (BOD). The conventional operations in primary
treatment, sometimes called clarification, are coagulation, flocculation, and
sedimentation. Secondary or biochemical treatment oxidizes dissolved
organic material to reduce BOD by about 90%. Tertiary or advanced treat-
ment involves treatment of pollutants with lower BOD. The operations in-
volved in this level of treatment have, in general, not been in operation
commercially for over five years.
The Lurgi process is designed for zero water effluents. Thus, all potential
contaminants that can be carried by the water are retained at the plant site.
Approximately 80% of the total water make-up comes from the water supply
source and only about 5% of the total water consumed leaves the plant as part
of the wet ash and in the byproduct ammonia solution. Almost all of the
organic byproducts are removed through the various process stages (some trace
amounts remain). Finally, the soluble phenols fraction is removed during the
Phenolsolvan process. Inorganic byproducts such as ammonia, hydrogen sulfide,
and hydrogen cyanide are treated by stripping and oxidation in conventional
sour water treatment processing schemes. Ammonia is stearn stripped from the
liquor and condensed as an aqueous solution of 24.1 percent by weight ammonia.
This solution usually is stored and ultimately sold for its commercial value.
Carbon dioxide and hydrogen sulfide also may be collected from a deacidifier
column and sent through the Rectisol process to the sulfur recovery process.
78
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It might be desirable to have additional storage capacity in the effluent
water treatment system to provide hold-up in case of a process upset. There
is danger that the levels of phenol or ammonia would be excessive for the
biological activity. Another possible procedure for treatment of such a
stream would be to use a tertiary water treatment technique, which should
be available on a standby basis prior to mixing it into the normal biological
oxidation feed stream. To optimize results, the feed stream composition to
the biological oxidation units should be kept as constant as possible.
In the paragraphs that follow control technologies for specific pollutants
are discussed.
III.B.l.
Ammonia
Because no process water is released, water treatment methods necessarily
relate to purifying water to process quality. The ammonia that is treated
is residue remaining after byproduct ammonia has been removed from the gas
liquor treatment using the sour water stripper (see below). Trace quantities
of ammonia also may come from the American Petroleum Institute (API) separator
and from the sanitary sewer sewage system into the effluent water treatment
section. Approximately 100 ppm (mg/l) of ammonia come in as free ammonia
and 950 ppm come in as fixed ammonia. The ammonia is treated first in an
aeration/settling polishing unit. These units are part of the biological
treatment system. The effluent from the system normally contains less than
5 ppm ammonia measured as amines and is sent back to the cooling tower sump.
The sour water stripper used to recover ammonia from process streams should
be designed to treat certain feed impurities which could cause pollution
problems. The major factor in obtaining proper stripper operation is the
pH of the feed stream. Impurities such as Cl, oil, phenols, mercaptans,
cyanides, thiocyanates, and polysulfides can affect stripper capacity and
corrode the materials of construction as well as contaminate the products.
Oil can cause reboiler fouling and foaming in the tower. If the oil is
stripped with the H2S it could produce a black sulfur product which has a
low commercial value. Most of the other impurities are potentially corrosive
to the materials :of construction.
III.B.2
Phenols
The source of phenol in the water, like ammonia, is from the gas liquor
treatment system. The residual concentration of phenol in the water depends
on the efficiency of the Phenosolvan process. It is estimated that 500 ppm
phenol enter the effluent water treatment section (biological degradation)
and are processed through two stages of aeration and settling ponds. The
effluent water contains less than 3 ppm of phenol which then is sent to the
cooling tower sump.
III.B.3.
Other Aqueous Pollutants
Other aqueous pollutants that are treated by the biological treatment system
include BODS and suspended solids. The BOD concentration which often is
79
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2,500 ppm is reduced to 75 ppm. Suspended solids which are negligible in the
inlet stream increase to about 5 ppm. As mentioned previously, the effluent
stream from the biological treatment system (effluent water treatment) is sent
to the cooling tower sump.
Pollutants not accounted for quantitatively in the water phase include
hydrogen cyanide (HCN) and hydrogen fluoride (HF). The quantities of
hydrogen cyanide that are expected to be produced in coal gasification depend
on temperature and pressure during gasification. During the Lurgi gasifica-
tion process, some HCN is expected to be produced and can pass through the
SNG system; it also may come in contact with water. Data on coal gasification
processes indicate that much less than l% of the coal nitrogen
is converted to HCN. It appears that HCN is produced by the secondary reaction
of ammonia with carbon in the reactor. It has been shown that HCN formation
is a function cf ammonia, partial pressure, contact time, and pressure. In-
creased partial pressure of steam can suppress production of HCN. Hydrogen
cyanide, like hydrogen sulfide, may be removed in the Stretford or other sulfur
recovery processes; however, quantities of these compounds may be contained
in the water stream. If so, they might have to be treated separately because
they can be detrimental to biological activity of the effluent water treatment
system, especially if concentrations fluctuate.
Hydrogen fluoride, because of its high reactivity, is expected to react with
the calcium oxide, silica, or alumina in ash and ultimately to be disposed
of with the ash. Hydrogen fluoride that may enter the water stream can be
neutralized by basic minerals that also are present, or calcium oxide can be
added for purposes of neutralization.
Undoubtedly, coal pile runoff and coal dust will enter the wastewater stream.
Runoff from the coal pile as well as dust which is washed in water sprays
from the screening operations may be transported in the water stream and
may ultimately enter the evaporation pond. Modifications to reduce coal
pile runoff wastes include the design of storage areas which will minimize
the area subject to rainfall by diverting runoff from other areas away from
the coal pile and the covering of inactive coal storage areas.
The water stream also may contain traces of organic materials that are car-
cinogenic and which are not readily removed by biological treatment. (About
90% of the total organic carbon is removed by biological action.) These
materials could enter the environment, for example, in the form of a water
spray from cooling towers.
Other sources of aqueous pollution such as the chemicals used for regenerating
the demineralizers system often can end up in the ash quench and removal
section and ultimately be returned to the mine. The resulting slurry, however,
still may contain leachable materials. Some solid materials and solid inorganic
compounds also may enter the effluent water stream from the sulfur recovery
process through leakage. Quantities normally are small but disposal may
present problems. The applicant, therefore, should evaluate and discuss all
proposed treatment and disposal plans in the EID. At a minimum, the
applicant should demonstrate:
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o That the proposed treatment scheme is capable of eliminating or re-
ducing potential water pollution problems
o The nature and efficacy of the proposed treatment scheme
o The efficacy of the treatment scheme for specific principal pollu-
tants such as phenols, NH3, HCN, and H2S
o The quality of and sink for the principal waste steams after treat-
ment.
III.C.
POLLUTION CONTROL TECHNOLOGY: END OF PROCESS CONTROLS (EMISSIONS)
Emissions from several of the processes in the coal gasification operation
will require control. In some cases, control equipment will be needed,
whereas in others sufficient control can be achieved by careful operation
or process modification. Control of emissions from the principal sources
is discussed below.
III.C.l.
Coal Storage and Preparation
Generation of dust and coal fines from coal storage piles can be reduced
significantly by wetting. Conveyors also should be covered to contain
particulate emissions. Coal crushing and drying should be performed in
enclosed spaces at slightly negative pressure; the exhaust emissions should
be cleaned by bag filters.
III.C.2.
Gasification Processes
Although there are no major atmospheric emission streams, careful handling
of dry ash and char is necessary to prevent particulate emissions, and quench
systems for ash and char should be designed to prevent odors.
III.C.3.
Acid Gas Removal
Potential atmospheric emissions of harmful sulfur compounds can be reduced
or rendered less harmful by combustion to S02 or conversion to sulfur.
III.C.4.
Sulfur Recovery
Coal gasification plants produce a large quantity of waste gas which con-
tains sulfur compounds (primarily HZS). This waste gas must, therefore, be
treated for sulfur removal before release to the atmosphere. Both rich and
lean sulfur waste gas streams are produced in many designs and each requires
a different method of treatment.
The.Claus sulfur recovery process generally is used to remove sulfur from
the rich gas stream. Claus plant tail gas requires further treatment be-
cause sulfur recovery efficiency is only about 95%. This tail gas may be
burned to convert the H2S to S02' However, combustion may be expensive
because of auxiliary fuel requirements due to the high C02 concentration
which reduces the heating value of the gas and because the high resultant
S02 emissions may require scrubbing. Alternatively, this tail gas can be
treated for further sulfur recovery in an advanced process, such as Beavon,
Cleanair, or IFP process, in which 99.5%-99.9% of the sulfur can be removed.
This type of tail gas treatment also may be expensive.
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For this gas, liquid phase sulfur recovery may be used to remove the H2S,
Liquid phase sulfur recovery achieves almos-t complete conversion of H2S to
elemental sulfur but does not remove other reduced sulfur compounds. Thus,
the waste gas may require further treatment such as combustion to convert
the sulfur compounds to S02'
The Stretford process, which has been described earlier, is primarily a wet
process for the recovery and/or removal of sulfur and air pollutant emissions
including COS and CS2 and hydrocarbons.
III.C.s. Briquetting
Because the
briquetting
be used and
appropriate
applicant.
Lurgi process requires a relatively uniform coal particle,
of the fines may be necessary. If this is so, a bake oven may
therefore, it also must be controlled. An afterburner is an
control technique that should be considered by the permit
III.D.
POLLUTION CONTROL TECHNOLOGY: END OF PROCESS CONTROLS (SOLID WASTE
DISPOSAL)
Four
coal
major types of solid wastes requiring disposal could be generated at a
gasification facility:
o Ash from the gasifiers, evaporator residue, and fly ash from steam
boilers
o Inorganic sludge and silt from raw water treatment
o Sludge from biological treatment unit for sanitary sewage
o Refuse (e.g., paper, cartons, rags, wood scraps, etc.).
Ash is the principal solid waste that must be disposed of by a coal gasifi-
cation facility. Quantities of ash may range from 3,500 to 8,500 tons/
1012 Btu's of coal processed. The amount and nature of the material usually
discourage any disposal method other than land disposal. Because any
leachate is probably contaminated, leaching must be prevented or the
leachate must be treated by neutralization, metals precipitation, settling
and biological oxidation. The ash from many coals will solidify when mixed
with small amounts of water; this characteristic has been used to reduce
leaching problems. It has been suggested that alkaline ash be disposed of
in abandoned coal mines that have acid-leachate problems; however, normally
the ash is dewatered in the ash handling facilities and then returned to
the mine. Residues from evaporators and the inorganic sludge and silt from
raw water treatment also could be disposed of at the mine with the ash.
Sludge from a biological wastewater treatment plant can be returned to the
mine or used as a soil conditioner. Also when evaporation ponds are used,
they produce a solid waste that can contain a number of undesirable com-
ponents, primarily metals. Therefore, it is important to cover or seal
these ponds after pond operation is discontinued to prevent leaching.
Refuse should be burned in an incinerator to prevent potentially dangerous
leachates from entering ground water supplies.
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IV.
OTHER CONTROLLABLE IMPACTS
IV.A.
AESTHETICS
New source coal gasification facilities may be large and complex facilities
occupying an area of up to several hundred acres. Coal storage and handling
areas, air emission stacks, and other plant components may approach significant
heights above the ground. Particularly in rural and suburban areas, this
configuration represents a noticeable intrusion on the landscape; existing
industrial areas would be less affected. Measures to minimize the impact on
the environment must be developed during site selection and design. The
applicant should consider, as applicable, the following factors to reduce
potential aesthetic impacts:
o Existing Nature of the Area: The topography and major land uses in
the area of the candidate sites are important. Topographic conditions,
such as hills, can be used to screen the plant from view. A lack of
topographic relief will require other means of minimizing impact, such
as regrading or vegetation buffers. Analysis of major land uses may
be useful to assist in the design and visual appearance of the facility.
The design of the facility should reflect, to the extent practical,
the nature of the area in which it is to be placed. The use of artists'
conception, in the EID, preferably in color, will be most useful in
determining the visual impact and appropriate mitigation measures.
c Proximity of Sites to Parks and Other Areas Where People Congregate
for Recreation and Other Activities: The location of these areas
should be mapped and presented in the EID. Representative views of
the plant (site) from observation points should be described. The
visual effects on these recreational areas should be described in the
EIA in order to develop the appropriate mitigation measures.
o Transportation System: The visual impact of new access roads, rail-
lines, pipelines, etc., on the landscape should be considered. Loca-
tions, construction methods and materials, and maintenance should be
specified.
. Creation of Aesthetically Pleasing Areas: If planned carefully, the
development of a coal gasification complex can create aesthetically
pleasing areas. Screening the facility by vegetation may improve
the appearance of an area. Construction of a cooling lake, and the
development of recreational facilities and open space also may be an
improvement to the area. Such positive impacts should be presented
in the EID.
IV.B.
NOISE
The major sources of noise associated with a coal gasification plant are:
o Coal transportation system (railroad)
. Coal preparation facilities (crushers and screens)
. Coal boxes
. Oxygen generation facilities
. Flare values, steam values, steam releases.
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Ordinarily a coal gasification plant will not create significant ambient
noise levels during plant construction and operation.
The methodology to evaluate noise generated from a proposed coal gasification
plant would require that the applicant:
. Identify all noise-sensitive land uses and activities adjoining the
proposed site
. Measure the existing ambient noise levels of the areas adjoining the
site
o Identify existing noise sources, such as traffic, aircraft flyover,
and other industry, in the general area
o Determine whether there are any State or local noise regulations that
apply to the site
. Calculate the noise level
compare with the existing
noise regulations
o Calculate the change in community noise levels resulting from con-
struction of the g~sification facility
. Assess the noise impact of the plant's operational noise and con-
struction noise, and, if required, determine noise abatement
measures to minimize the impact (quieter equipment, noise barriers,
improved maintenance schedules, etc.)
of the gasification plant in operation and
community noise levels and the applicable
IV.C.
SOCIOECONOMIC
The introduction of a large new coal gasification facility into a community
may cause economic and social changes. Therefore, it is necessary for an
applicant to understand the types of impacts or changes that may occur so
that they can be evaluated adequately. The importance of these changes
usually depends on the nature of the area where the plant is located (e.g.,
size of existing community). Normally, however, the significance of the
changes caused by a plant of a given size will be greater in a small, rural
community than in a large, urban area. This is primarily because a small,
rural community is likely to have a nonmanufacturing economic base and a
lower per capita income, fewer social groups, a more limited socioeconomic
infrastructure, and fewer leisure pursuits than a large, urban area. There
are situations, however, in which the changes in a small community may not
be significant and, conversely, in which they may be considerable in an
urban area. For example, a small community may have had a manufacturing
(or natural resource) economic base that has declined. As a result, such
a community may have a high incidence of unemployment in a skilled labor
force and a surplus of housing. Conversely, a rapidly growing urban area
may be severely strained if a new coal gasification plant is located there.
The rate at which the changes occur (regardless of the circumstances) also
is an important determinant of the significance of the changes. The ap-
plicant should distinguish clearly between those changes occasioned by the
construction of the plant and those resulting from its operation. The
former changes could be substantial but usually are temporary; the latter
mayor may not be substantial but normally are more permanent in nature.
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During the construction phase, the impact will be greater if the project
requires large numbers of construction workers to be brought in from
outside the community than if local, unemployed workers are available.
impacts are well known and include:
o Creation of social tension
o Demand for increased housing, police and fire protection, public
utilities, medical facilities, recreational facilities, and other
public services
o Strained economic
structure becomes
The
budget in the community where existing infra-
inadequate.
Various methods of reducing the strain on the budget of the local community
during the construction phase should be explored. For example, the company
itself may build the housing and recreation facilities and provide the util-
ity services and medical facilities for its imported construction force; or
the company may prepay taxes and the community may agree to a corresponding
reduction in the property taxes paid later. Alternatively, the community
may float a bond issue, taking advantage of its tax-exempt status, and the
company may agree to reimburse the community as payments of principal and
interest become due.
During plant operation, the more extreme adverse changes of the construction
phase are likely to disappear. Longer run changes may be profound, but less
extreme, because they evolve over a longer period of time and may be both
beneficial and harmful.
The permit applicant should document fully in the EID the range of potential
impacts that are expected and demonstrate how possible harmful changes will
be handled. For example, an increased tax base generally is regarded as a
positive impact. The revenue from it usually is adequate to support the ad-
ditional infrastructure required as the operating employees and their fami-
lies move into the community. The spending and respending of the earnings
of these employees has a multiplier effect on the local economy, as do the
interindustry links created by the new plant. Socially, the community may
benefit as the increased tax base permits the provision of more diverse and
higher quality services and the variety of its interests increases with
growth in population. Contrastingly, the transformation of a small, quiet
community into a larger, busier community may be regarded as an adverse
change by some of the residents, who chose to live in the community, as well
as by those who grew up there and stayed, because of its amenities. The
applicant also should consider the economic repercussions if, for example,
the quality of the air and water declines as a result of various waste streams
from the coal gasification plant and its ancillary facilities.
In brief, the applicant's framework for analyzing the socioeconomic impacts
of constructing and operating a coal gasification plant must be comprehensive.
Most of the changes described should be measured to assess fully the potential
costs and benefits. The applicant should distinguish clearly between the
short term (construction) and long term (operation) changes, although some
changes may be common to both (e.g., the provision of infrastructure) because
the significance of the changes depends not only on their absolute magnitude
but on the rate at which they occur.
85
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The applicant
regional, and
standing with
regulations.
should develop and maintain close coordination with State,
local planning and zoning authorities to ensure full under-
all existing and/or proposed land use plans and other related
IV.D.
ENERGY SUPPLY
The impact of a coal gasification plant on local energy supplies will depend
largely on the type of gasification process proposed and the ancillary facil-
ities. If an oxygen separation unit is associated with the plant then the
energy demand 'viII increase significantly. The applicant should evaluate the
energy efficiencies of all processes considered during project planning and
then consider the alternative analysis. Also feasible design modifications
should be considered in order to reduce energy needs. There are a number of
processes that are exothermic and the applicant should evaluate the potential
for using this waste heat to satisfy various energy demands within the plant,
for example, steam for process purposes.
At a
minimum, the applicant should provide the following information:
. Total external energy demand for operation of the plant
o Total energy generated on site
o Energy demands by type
. Proposed measures to reduce energy demand and increase plant efficiency
IV.E.
IMPACT AREAS NOT SPECIFIC TO COAL GASIFICATION
The intent of the preceding sections was to provide guidance to new source
NPDES permit applicants on those impact areas that are specific to or repre-
sentative of coal gasification facilities. It is recognized that many impacts
resulting from the construction and operation of a coal gasification plant
are similar to impacts associated with many other new source facilities;
therefore, no effort has been made to discuss these types of impacts, but,
instead, to reference other more general guideline documents. For example,
general guidelines for developing a comprehensive inventory of baseline data
(preproject conditions) and a methodology for impact evaluation are contained
in Chapters 1 and 2 of the EPA document, Environmental Impact Assessment
Guidelines for Selected New Source Industries. Although broad in scope, this
document and other appropriate guidance materials should be used by the
applicant for assistance in evaluating non-industry-specific impacts.
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V.
EVALUATION OF AVAILABLE ALTERNATIVES
V.A.
SITE ALTERNATIVES
Preliminary site selection studies should take place before the EID document
is prepared. These studies should include a thorough analysis of all feasible
site locations. This identification and analyses of sites should be described
in the EIA, and the reasons for eliminating a site(s) should be specified.
Adequate information on all feasible site alternatives is a necessary consider-
ation in issuing, conditioning, or denying an NPDES permit.
Several different agencies may be able to offer assistance in evaluating
potential areas for location of a coal gasification facility.
. State, regional, county. or local zoning or planning commissions can
describe their land use programs and where variances are required.
Federal lands are under the authority of the appropriate Federal land
management agency (Bureau of Reclamation, U.S. Forest Service,
National Park Service, etc.).
. State or regional water resource agencies can provide information
relative to water appropriations and water rights.
. Air pollution control agencies can provide assistance relative to air
quality allotments and other air-related standards and regulations.
. The Soil Conservation Service and State Geological Surveys can provide
data and consultation on soil conditions and geologic characteristic3.
In the EID the applicant should display the potential site locations on map~
that show environmental conditions and other relevant site information. (A
consistent identification system for the alternative sites should be established
and retained on all graphic and verbal material.) Such may include but not
be limited to:
o Areas and sites considered by the applicant
o Major centers of population density (urban, high, medium, low density
or similar scale)
o Water bodies suitable for water use and cooling
. Railways, highways (existing and planned), and waterways suitable for
the transportation of raw materials, byproducts, and wastes
o Important topographic features (such as mountains and marshes)
o Dedicated land-use areas (parks, historic sites, wilderness areas,
testing grounds, airports, etc.)
o Other sensitive environmental areas
o Existing power generating station(s), if any, with total transport of
high Btu gas
. Industrial complexes, significant mineral deposits, and mineral
industries.
Using these graphic materials, the applicant should provide a condensed descrip-
tion of the major considerations that led to the selection of the final candi-
ate sites, including proxinU.ty to raw materials, adequacy of transportation
systems, economic analyses with tradeoffs, environmental considerations,
license or permit problems, compatibility with any existing land use planning
programs, and current attitudes of interested citizens.
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Having discussed candidate sites, the applicant also should indicate the
steps, factors, and criteria used to select the proposed site. The applicant
should present a cost-effectiveness analysis including pertinent environmental
social, and economic considerations to show why the proposed site plant
combination is preferred over all other candid~te site alternatives
proposed facility. Economic estimates should be based on an at least pre-
liminary conceptual design that considers how construction costs are affected
by site-related factors.
Quantification, although desirable, may not be possible for all factors be-
cause of lack of adequate data. Under such circumstances, qualitative and
general comparative statements, supported by documentation, may be used.
Where possible, experience derived from operation of other industrial
facilities at the same site, or at an environmentally similar site, may be
helpful in appraising the nature of expected environmental impacts.
Therefore, if the propos~d site location proves undesirable, then alternative
sites from among those originally considered should be reevaluated or new
sites should be identified and evaluated. Expansion or technological changes
at an existing plant site may be a possible alternative. Therefore. it is
critical that a permit applicant systematically identify and assess all
feasible alternative site locations as early in the planning process as
possible.
V.B.
ALTERNATIVE PROCESSES, DESIGNS, AND OPERATIONS
All feasible process alternatives should be evaluated carefully on the basis
of reliability. economy, and engineering factors.
V.B.l.
Other Coal Gasification Processes
To date, commercially proven technology for the gasification of coal has
been demonstrated by Lurgi, Koppers-Totzek, and Winkler processes. There
is, as described in section I. B., a variety of other coal gasification
processes which should be considered. Those process alternatives that
appear practical should be screened further on the basis of, at least, the
following factors:
. Land requirements, raw material, waste treatment, and storage require-
ments
e Release to air of dust, sulfur dioxide, nitrogen oxides, and other
potential pollutants, subject to Federal, State, or local limitations
o Releases to water of heat, chemicals, trace metals, and other con-
stituents subject to Federal, State, and local regulations
G Water consumption rate
~ Fuel consumption and the generation of ash with associated waste
disposal
g Reliability and energy efficiency
o Economics
o Aesthetic considerations for each alternative process.
A tabular or matrix form of display often is helpful in comparing the feasi-
ble alternatives. Alternative processes which are not feasible should be
dismissed with an objective explanation of the reasons for rejection.
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V.B.Z.
Alternative Systems Within the Process
The principal unit systems in
. Gasification
. Gas shift conversion
. Gas cooling
o Rectisol
o Phenosolvan
o Methanation
. Gas liquor separation
a gasification process (e.g., Lurgi) are:
The applicant should investigate all feasible alternative methods available
for each of these unit systems. The selected coal gasification process
should incorporate an efficient combination of component systems which have
been selected through a systematic analysis of economic, environmental, and
engineering factors. The applicant also should present the major determining
factor(s) for negative or positive decisions. Economic comparisons should
include initial capital costs and operating costs of the individual systems.
All potential environmental impacts should be documented and qualified and
the magnitude of the effects should be quantified wherever possible. Engin-
eering comparisons must include the projected length of time the alternative
systems would be operable. Estimated maintenance costs over the useful life
of each system should be included, as should an analysis of the effect of
maintenance on overall process efficiency and performance. The applicant also
should present the major determining factor(s) for negative or positive de-
cisions.
A similar analysis should be made for the ammonia recovery and sulfur con-
version systems.
All systems that are considered should be described in the EID as well as
the specific criteria used for decision-making. For each alternative, the
applicant also should present the major determining factor(s) for negative
or positive decisions.
V.C.
NO-BUILD ALTERNATIVE
In all proposals for facilities development, the applicant must consider and
evaluate the impact of not constructing the proposed new source facility.
Because this analysis is not unique to the development of a coal gasification
facility, no specific guidance is provided as part of this appendix. The
permit applicant, therefore, is referred to Chapter IV (Alternatives to the
Proposed New Source)' in the EPA document, Environmental Impact Assessment
Guidelines for Selected New Source Industries, which was published in
October 1975.
89
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VI.
REGULATIONS (OTHER THAN POLLUTION CONTROL)
The applicant should be aware that there may be a number of regulations other
than pollution control regulations that may apply to the siting and operation
of new coal gasification facilities. The applicant should consult with the
appropriate EPA responsible official regarding applicability of such regu-
lations to the proposed new source. Federal regulations that may be pertinent
to a proposed facility are:
Coastal Zone Management Act of 1972 (16 use 1451 et seq.)
The Fish and Wildlife Coordination Act of 1974 (16 USC 661-666)
The National Environmental Policy Act of 1969 (42 USC 4321 et seq.)
USDA Agriculture Conservation Service Watershed Memorandum 108 (1971)
Wild and Scenic Rivers Act of 1969 (16 USC 1274 et seq.)
The Flood Control Act of 1944
Federal-Aid Highway Act, as amended (1970)
The Wilderness Act of 1964
Endangered Species Preservation Act, as amended (1973) (16 USC 1531 et seq.)
The National Historical Preservation Act of 1966 (16 USC 470 et seq.)
Executive Order 11593
Archaeological and Historic Preservation Act of 1974 (16 USC 469 et seq.)
Procedures of the Council on Historic Preservation (1973) (39 FR 3367)
Occupational Safety and Health Act of 1970
In connection with these regulations, the applicant should place particular
emphasis on obtaining the services of a recognized archaeologist to determine
the potential for disturbance of an archaeological site, such as an early
Indian settlement or a prehistoric site. The National Register of Historic
Places also should be consulted for historic sites such as battlefields.
The applicant should consult the appropriate wildlife agency (State and
Federal) to ascertain that the natural habitat of a threatened or endangered
species will not be adversely affected.
From a health and safety standpoint, all complex industrial operations in-
volve a variety of potential hazards and to the extent that these hazards
could affect the health of plant employees, they may be characterized as
potential environmental impacts. These hazards exist in coal gasification
plants because of the very nature of the operation (e.g., processing con-
ditions which require high temperatures and pressures). All plant operators
should emphasize that no phase of operation or administration is of greater
importance than safety and accident prevention. Company policy should pro-
vide and maintain safe and healthful conditions for its employees and es-
tablish operating practices that will result in safe working conditions and
efficient operation.
The plant must be designed and operated in compliance with the standards of
the US Department of Labor, the Occupational Safety and Health Administration,
and the appropriate State statutes relative to industrial safety. The
applicant also should coordinate closely with local and/or regional planning
and zoning commissions to determine possible building or land use restrictions.
90
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98
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TECHNICAL REPORT DATA
(Please read Instmetions on the reverse before completing)
1. REPORT NO. 12 3. RECIPIENT'S ACCESSION NO.
EPA-130/6-80-00l
4. TITLE AND SUBTITLE 5. REPORT DATE
Interim Final Environmental Impact Assessment Guidelines August, 1980
For New SDurce Coal Gasification Facilities 6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S) 8. PERFORMING ORGANIZATION REPORT NO.
Robert N. Rickles, D. Keith Whitenight
9. PERFORMING ORGANIZATION NAME AND ADDRESS 10. PROGRAM ELEMENT NO.
WAPORA, Inc.
6900 Wisconsin Avenue, NW 11. CONTRACT/GRANT NO.
Washington, D.C. 20015
68-01-4157, Task 003C
12. SPONSORING AGENCY NAME AND ADDRESS 13. TYPE OF REPORT AND PERIOD COVERED
EPA, Office of Environmental Review (A-l04 Interim Final
401 M Street, S.W. 14. SPONSORING AGENCY CODE
Washington, D.C. 20460 EPA!lOO/102
15. SUPPLEMENTARY NOTES
EPA Task Officer is John Meagher, (202) 755-0790
16. ABSTRACT
This report provides guidance for evaluating the environmental impacts of proposed
new source coal gasification facilities. Because EPA has not yet issued new source
performance standards for the coal gasification industry, the guidelines are publishec
in interim final form. The guidelines are intended to assist in the identification
of potential environmental impacts, and the information requirements for evaluating
such impacts, in documents prepared under the National Environmental Policy Act.
The report includes guidance on (1) identification of potential wastewater
effluents, air emissions and solid wastes from coal gasification facilities, (2)
assessment of the impacts of such residuals on the quality of the environment,
(3) state-of-the-art technology for in-process and end-of-process control of waste
streams, (4) evaluation of alternatives, and (5) environmental regulations that
apply to the industry. In addition, the guidelines include an "overview" chapter
that gives a general description of the coal gasification industry, significant
problems associated with it, and recent trends in location, raw materials,
processes, pollution control, and the demand for industry output.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS b.IDENTIFIERS/OPEN ENDED TERMS c. COSATI Field/Group
Environmental Impact 10 A
Coal Gasification Assessment
Industrial Wastes 13 B
1B. DISTRIBUTION STATEMENT 19. SECURITY CLASS (This Report) 21. NO. OF PAGES
Unclassified 106
Release Unlimited 20. SECURITY CLASS (This page) 22. PRICE
Unclassified
EPA Form 2220-1 (9.73)
*C.5. GOVERNMENT PRINTING OFFICE: 1980-311"132/83
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