EPA-650/2-74-118
OCTOBER 1974
Environmentol Protection Technology Series
; r ; ? ??-".-* -• V
1 ••••• ••••• ••.•••••••••••••••
XvXvt'X'xVi'XvXvA'Xvi'X':':'
vKvivvivZvKvI^'K'KvX'X'X'X'X-:
-------
Issued: March 14. 1975
Page 1 of 2
ERRATA SHEET
for the
Symposium Proceedings: Environmental Aspects
of Fuel Conversion Technology
(Held in May 1974, St. Louis, Missouri)
Published in October 1974 EPA-650/2-74-118
Environmental Protection Technology Series
Please mark your proceedings volume with all changes indicated on the reverse
side of this sheet first; then proceed to the item given below.
Table No. Changes
NOTE:
Pace
73
4
Paste the replacement table below over the table 4 printed
in the proceedings volume:
Table 4. Elements of Current U.S. Regulatory Policy for
Air and Water Pollutants
Elements of Air Pollution
Control Policy
Elements of Water Pollution
Control Policy
AMBIENT AIR QUALITY STANDARDS
State and Local Standards
Nat'l Primary Standards
Nat'l Secondary Standards
Nondegradation Standards
THRESHOLD LIMIT VALUES
EMISSION STANDARDS
State and Local Standards
Nsw Source Performance Standards
RECEIVING WATER QUALITY STANDARDS
State and Local Standards
Hazardous Pollutants
U.S. PUBLIC HEALTH SERVICE
DRINKING WATER STANDARDS
EFFLUENT LIMITATIONS
State and Local Standards
New Source Performance Standards
Best Practicable Technology
Currently Available
Best Available Technology
Economically Achievable
Pretreatment Standards
Zero Discharge
Toxic Substances
-------
75
75
77
78
79
79
Table
No. Chniums
7
8
10
11
• On the line marked "Kentucky", in second column headed
by "Pollutant", spelling should be "Fluorides".
• In third column heading, change "ug/m3" to "Aig/m3".
• In the grouping marked "Pennsylvania", in the second
column headed by "Pollutant", change the line marked
"Sulfates (H2S04)" to read "Sulfates (as H2S04)" (add
the word "as").
• At end of first footnote, add' "(Rcf. 34)".
• In second and third columns, change "ug/m3" to "jug/m3"
(13 times).
• On the line marked "Ohio", in third column, change "0.1
TLm-48 hour" to "0.1 TLm-48 hour" (make "m" a
subset t|Jt)
• On the line marked "West Virginia", in third column,
change "0 1 Tlm-96 hour" to 0.1 TLm-96 hour" (make "I"
a capital L).
• In the space below the acronym "ORSANCO", add the
definition of ORSANCO1 "(Ohio River Sanitary
Commission)".
• Add an asterisk """ to end of table title.
• Add footnote under table: "* Refs. 16, 32".
• Under "Water Pollutants" section, on eighth line headed
"phenols", add an "x" in the column headed by "Iron
Making".
• Title should read: "Proposed New Source Performance
Standards for Petroleum Refining***" (add the word
"Proposed" and add three asterisks "***" after title).
• Transpose the entire second column, including its heading
and data, to the right of the third column so that left to
right the columns will be "One Day Max* Range" and "30
Day Max*'Range".
Add thud footnote:
*Ref. 20".
Title should read: "Proposed New Source Performance
Standards for Byproduct Coke Making***" (add the word
"Proposed", and add three asterisks "***" after title).
Add third footnote:
*Ref.21".
Tjblo
Pago No. Changes
80 13 • In the second column heading, following "WATER", add a
double asterisk
• Delete the footnote, "*For specific sources only", and
replace it with two footnotes'
"*Ref. 33
"**Ref.29".
81 14 • On first line marked "Illinois", in the sixth column headed
with "S02 (ppm)", move "19.5 P°67 |D/hr (P = tph wgt
rate)" down to the space below, on line marked "Indiana",
be sure to add a paicnthesis "(" in front of the "P", and
change "wst" to "wgt".
• In its place, on ihe line marked "Illinois", add "2000".
• On last line marked "West Virginia", in the fifth column.
change "21 2-50.0" to "21.2"" (i.e., ilelute "-500", and
add an asterisk """)
• Add double asterisks "**" to end of table title.
• Add a second footnote: "**Rcf. 34".
81 15 • In table title, delete the word "Proposed" and substitute
the words- "State of".
• In the second column, on the second line, change "0.15
Ib/MMBtu" to "0.16 Ib/MMBtu" (change "0.15" to
"0.16").
• In the third column, on the first line, change "0.03
Ib/MMBtu" to "0.03 gr/scf".
' In the first column, on the fourth line, delete
"Non-methane Hydrocarbons" and replace it with
"Hydrogen Sulfide".
• In the third column, on the fourth line, change "Nil" to
"10 ppm".
• In the first column, on the fifth line, change "Sulfur
(Vapor)" to "Total Sulfur".
• In the third column, on the fifth line, change "0.04
Ib/MMBtu**" to "0.008 Ib/MMBtu".
• Delete the second footnote: """Becomes 0.008 December
31. 1978".
88 17 -On the bottom line marked 'Total USA", in the fifth
column, change "4255" to "14,255"
• Remove the word "the" from the table title.
m
3J
I
m
-------
EPA-650/2-74-118
SYMPOSIUM PROCEEDINGS:
ENVIRONMENTAL ASPECTS
OF FUEL CONVERSION TECHNOLOGY
(MAY 1974, ST. LOUIS, MISSOURI)
Franklin A. Ayer (Compiler)
Research Triangle Institute
P.O. Box 12194
Research Triangle Park, North Carolina 27709
Contract No. 68-02-1325, Task No. 6
Program Element No. 1AB013
ROAP No. 21ADD & 21AFJ
Project Officer: William J . Rhodes
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
October 1974
-------
This report has been reviewed by the Environmental Protection Agency
and approved for publication. Approval does not signify that the con-
tents necessarily reflect the views and policies of the Agency, nor does
mention of trade names or commercial products constitute endorsement
or recommendation for use.
11
-------
FOREWORD
The proceedings for the symposium on "Environmental Aspects of Fuel
Conversion Technology," is the final report submitted to the Control
Systems Laboratory for the Environmental Protection Agency Contract
No. 68-02-1325. The symposium was held at the Chase-Park Plaza
Hotel, St. Louis, Missouri, on 13-15 May 1974.
The principal objective of this symposium was to review and discuss
environmentally related information of coal conversion technology.
More specifically, papers were presented that covered environmental
quality and standards, fuel contaminants, environmental aspects of
specific fuel conversion systems, fuel utilization and total
environmental assessment, and research and development needs.
Mr. T. Kelly Janes, Chief, Fuel Processing Section, Clean Fuels and
Energy Branch, Control Systems Laboratory, National Environmental
Research Center, Environmental Protection Agency, Research Triangle
Park, North Carolina, was the General Chairman of the Symposium.
Mr. William J. Rhodes, Fuel Processing Section, Clean Fuels and Energy
Branch, Control Systems Laboratory, National Environmental Research
Center, Environmental Protection Agency, Research Triangle Park,
North Carolina, was the Project Officer and Technical Coordinator of
the Symposium.
Mr. Franklin A. Ayer, Manager, Environmental Technology
Department, Center for Technology Applications, Research Triangle
Institute. Research Triangle Park, North Carolina, was the Symposium
Coordinator and Compiler of the proceedings.
in
-------
IV
-------
Table of Contents
(* indicates speakers)
PAGE
May 13. 1974
Opening Session 1
T. Kelly Janes. General Chairman
Keynote Address:
Environmental Aspects of Fuel Conversion Technology 3
John K. Burchard
Session): ENVIRONMENTAL QUALITY AND STANDARDS 5
William J. Rhodes, Session Chairman
Environmental Quality and Standards for Air 7
Jack R. Farmer
Environmental Quality and Standards for Water 11
Kenneth M. Mackenthun
Coal Conversion Technology and Solid Waste Disposal:
Time To Take Stock 15
A. Blakeman Early, Esq.
Environmental Impact Statement Requirements as Related
to Fuel Conversion Technologies 21
Sheldon Meyers
Session II: FUEL CONTAMINANTS 25
Rene' R. Bertrand, Session Chairman
Problems in the Chemistry and Structure of Coals as
Related to Pollutants from Conversion Processes 27
Peter H. Given
Trace Elements and Potential Pollutant Effects
in Fossil Fuels 35
H.J. Hall,*
G. M. Varga, and
E. M. Magee
Distribution of Trace Elements in Coal 49
R. R. Ruch,*
Harold J. Gluskoter,* and
N. F. Shimp
-------
Preliminary Chemical Analysis of Aqueous Wastes from
Coal Conversion Plants (A Recommended Approach) 55
William T. Donaldson
May 14. 1974
Session III. ENVIRONMENTAL ASPECTS OF SPECIFIC FUEL
CONVERSION SYSTEMS 67
David H. Archer, Session Chairman
Some Implications of Environmental Regulatory Activities
on Coal Conversion Processes 69
E. S. Rubin* and
F. C. McMichael
Environmental Aspects of El Paso's Burnham I Coal
Gasification Complex 91
Cecil R. Gibson,
Gene A. Mammons,* and
Don S. Cameron
Environmental Aspects of the Wesco Coal
Gasification Plant 101
Thomas E. Berty and
James M. Moe*
Analysis of Tars, Chars, Gases, and Water Found in
Effluents from the Synthane Process 107
Alfred J. Forney,*
William P. Haynes,
Stanley J. Gasior,
Glenn E. Johnson,and
Joseph P. Strakey, Jr.
Clean Environment with Koppers-Totzek Process 115
J. Frank Farnsworth,
D. Michael Mitsak,* and
J. F. Kamody
Environmental Aspects of the Bi-Gas Process 131
R.J.Grace* and
E. K.Diehl
Sulfur Emission Control with Limestone/Dolomite
in Advanced Fossil Fuel-Processing Systems 135
Dale L. Keairns,
Eoin P. O'Neill, and
David H. Archer*
VI
-------
Clean Fuels from Coal by the COED Process 147
J. A. Hamshar,*
H D. Terzian, and
L J Scott i
Environmental Aspects of the SRC Process 159
C. R Hinderhter
Environmental Aspects of Solvent Refining 165
W. B. Harrison
Environmental Factors in Coal Liquefaction
Plant Design 169
J. B. O'Hara.*
S. N. Rippee.
B. I. Loran, and
W. J. Mindheim
Colony Oil Shale Development — Parachute Creek, Colorado 181
Mark T. Atwood
May 15, 1974
Session IV: FUEL UTILIZATION AND TOTAL
ENVIRONMENTAL ASSESSMENT 195
Paul Spaite, Session Chairman
Overall Environmental Considerations of Conversion Technology 197
C. E. Jahnig,*
E. M. Magee, and
C. D. Kalfadelis
Weighing Environmental Benefits and Costs 203
E. H. Hall,
R. H. Cherry, Jr., and
G. R. Smithson, Jr.*
The Environmental Impact of Coal-based Advanced
Power Generating Systems 237
Fred L. Robson and
Albert J. Giramonti*
Environmental Considerations in the Use of Alternate
Clean Fuels in Stationary Combustion Processes 259
G. Blair Martin
Status of Flue Gas Desulfurization Technology 277
Frank T. Princiotta (paper not presented at symposium)
VII
-------
Session V: RESEARCH AND DEVELOPMENT NEEDS 307
Robert P. Hangebrauck, Session Chairman
Technology Needs for Pollution Abatement
in Fossil Fuel Conversion Processes 309
E. M. Magee* and
H. Shaw
Low BTU Gasification of Coal: Who Needs It and
How Can It Be Improved? 315
R. A. Ash worth* and
B. C. Hsieh
Environmental Aspects of Coal Liquefaction 325
P. M. Yavorsky and
Sayeed Akhtar*
Potential Byproducts Formed from Minor and
Trace Components in Coal Liquefaction Processes 331
Philips. Lowell* and
Klaus Schwitzgebel
Oil Shale and Its Potential Utilization 341
G. U. Dinneen
Oil Shale Development —Some Environmental
Considerations 353
C. Blaine Cecil
Overview of R & D Needs on Environmental Aspects
of Coal-Conversion Processes 361
A. A. Jonke* and
W. Podolski
VIII
-------
13 May 1974
Opening Session
T. Kelly Janes
General Chairman
-------
-------
(KEYNOTE ADDRESS)
ENVIRONMENTAL ASPECTS OF FUEL CONVERSION TECHNOLOGY
John K. Burchard*
Good morning, ladies and gentlemen. It is my
sincere pleasure to welcome you to our first
symposium on the environmental aspects of fuel
conversion technology. I do not believe that it is
necessary, especially with this group, to justify or
explain the importance to our Nation of establishing
a viable industry for the conversion of coal to gas and
liquid fuel. The Federal Government has recently
identified massive financial support to accelerate the
development of this technology. American industry
and universities are also undertaking a broad research
program to meet this challenge.
However, of equal importance to the overall public
health and welfare is the need to insure that these
new energy technologies are accomplished in an
environmentally sound manner. The development of
this or any technology that results in additional
damage to the environment will necessarily label us as
remiss in our responsibilities and as lacking in
technical skill. The Environmental Protection Agency
has the primary responsibility in the Federal
Government for assessment of the associated
environmental problems and for aiding their solution
through the appropriate pollution control techniques;
however, it is quite apparent from the magnitude and
complexity of the technology and problems involved,
that the environmental protection requirements will
demand a sincere cooperative effort by all those
engaged in this undertaking. The continued
investigation of pollutants causing adverse health
effects and ecological damage is mandatory in order
to provide the basis for assessing the impact of
process emissions. This information is needed for the
identification of the necessary control techniques and
the development of suitable control methods, so that
the process developers can meet their environmental
requirements in a timely and cost-effective manner.
Meetings such as this should enable those engagei
in the development of conversion process technology,
and those engaged in the development of
environmental safeguards, to exchange ideas and
•Director, Control Systems Laboratory, Environmental
Protection Agency, Research Triangle Park, North Carolina
goals, and to identify the needed research and
cooperation. Only with such cooperation can our
respective objectives be attained without a lamentable
waste of time and money.
The Control Systems Laboratory (CSL) has had,
for some time now, a vital interest in the emission of
pollutants from the use of coal. Our efforts have
included work in flue gas desulfunzation, combustion
phenomena, physical and chemical coal cleaning, and
coal conversion technology. In 1969, we initiated a
study of advanced power cycle technologies to define
how the Nation's increasing demand for electrical
energy could be met with maximum efficiencies and
minimum insult to the environment. This study
reviewed the technical attributes as well as
disadvantages of topping and bottoming cycles,
closed- and open-cycle gas turbines, and combined gas
and steam turbine systems. The combined gas and
steam turbine cycle showed potential as a very
attractive technique and led us into the area of low
Btu gasification and associated pollution problems. In
1970, the need for high temperature and pressure fuel
gas cleanup systems was identified, and work was
initiated on control techniques for sulfur-based
compounds. In 1972, CSL initiated a broad study to
assess the environmental impact of coal conversion
technology. This will be greatly expanded in the near
future.
As with any vital organization, our program has
grown and changed course over the years in response
to changing needs and priorities. Currently, our
activities include the general pursuit of control
techniques for
sulfur oxides,
nitrogen oxides,
paniculate material, and
hazardous and toxic air pollutants.
The part of our program specifically concerned with
fossil-fuel conversion processes involves support of
Fluidized-bed combustion;
Characterization of fossil fuels by types and
levels of pollutants;
Environmental assessment of such areas as coal
-------
gasification and liquefaction, advanced
power cycles, and shale oil.
Physical and chemical desulfunzation of coal;
and
General combustion research studies.
This is a broad program, and it has given us an
opportunity to gain both the process and
environmental perspectives. We initiated this
symposium because our studies have clearly
illustrated the need for increased information
exchange and cooperative efforts. We plan to sponsor
such meetings periodically as a forum for the many
organizations involved in this field.
Fuel conversion technology is quite complex even
by itself; the additional technology that will be
required for adequate pollution control adds
significantly to this complexity and could have a
major effect on cost. EPA is concerned about both
factors. Our goal is to aid in achieving the most
environmentally sound systems at the lowest possible
overall cost. It should be readily apparent that by the
time these plants become a commercial reality, the
pollution control required will be more
comprehensive and stringent than that now in
existence.
Although sulfur compounds are of major concern,
the emissions of various other trace pollutants will
also have to be controlled. The thermal treatment of
coal inevitably results in the formation of numerous
organic compounds, many of which are potentially
carcinogenic. For example, several types of
polynuclear aromatics have been identified in
emissions from coke ovens. Trace metals such as
vanadium, cadmium, and mercury are also worrisome.
The list of potential pollutants can be almost endless.
When one considers the forecasts of future coal
consumption for conversion processes, the possible
total emissions into the environment become very
significant.
The problem becomes even more obvious when it is
realized that the mam energy utilization systems for
the foreseeable future are to be developed on a high
priority basis within the next 5 to 10 years by a
massive Government-financed R&D program. Within
this time frame, it will be humanly impossible to
quantify adequately all of the pollutants of concern
and their associated health effects. Thus it will be
impossible to precisely define the pollutant control
levels required; the best safeguard is to have an active
pollution control program which will be developing
the necessary new and improved control methods
concurrently with the development of the new energy
systems. If we wait until the energy technologies are
already in place, it will be extremely difficult and
expensive to retrofit them with improved pollution
control equipment, and our country will suffer the
consequences accordingly.
This symposium is divided into four major
areas:
The rationale for environmental
standards,
Known and potential problems.
The status of present developments, and
Needed research and development.
During these sessions, the informational, as well as
•technological, gap areas should become evident. The
challenge is here and will rapidly become more
visible. It is up to all of us to accept this challenge, to
meet it, and to solve it.
In conclusion, I again welcome each of you and
hope that these next few days will be interesting and
productive.
-------
13 May 1974
Session I:
ENVIRONMENTAL QUALITY AND STANDARDS
William J. Rhodes
Session Chairman
-------
-------
ENVIRONMENTAL QUALITY AND STANDARDS FOR AIR
Jack R. Farmer*
Abstract
The key provisions of the Clean Air Act of 1970
are discussed as they affect fuel conversion processes.
Primary emphasis is placed on Section 111, standards
of performance for new stationary sources, and the
role these standards play in the national strategy for
air quality management. The current standards, the
standards development process, and plans for future
standards are also discussed.
The Environmental Protection Agency's authority
to control the discharge of pollutants into the
atmosphere is provided in the Clean Air Act, as
amended in 1970. As far as stationary sources are
concerned, the act contains several regulatory and
enforcement options which can be used to control air
pollutants. These options include (1) national
ambient air quality standards/State implementation
plans, (2) standards of performance for new
stationary sources, and (3) national emission
standards for hazardous air pollutants.
The national ambient air quality standard/State
implementation plan provisions are contained in
sections 109 and 110 of the act. These provisions
require the Administrator to set national primary and
secondary ambient air quality standards and require
the States to adopt and submit plans for achieving
such standards. Primary standards indicate those
levels of air quality which are necessary to protect
public health. Secondary standards indicate those
levels which are necessary to protect public welfare.
National standards have been issued for paniculate
matter, sulfur dioxide, nitrogen oxides, oxidants,
hydrocarbons, and carbon monoxide. After the
Administrator issues a national ambient air quality
standard. States have 9 months to develop and submit
an implementation plan which includes emission
limitations on existing sources which will provide for
the attainment of the national standards. The
Administrator must review and approve or disapprove
the State plans and promulgate substitute provisions
for disapproved plans. This review can result in a
combination of State and Federal regulatory action.
The plans must provide for the attainment of primary
'Chief of the Standards Development Branch. Emission
Standards and Engineering Division, Office of Air Quality
Planning and Standards, U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina.
standards within 3 years and secondary standards
within a reasonable time. The Administrator may
approve a 2-year extention for achieving primary
standards if necessary technology is not available.
On May 31, 1972, the Administrator approved or
disapproved all of the State implementation plans. At
that time. EPA recognized that it would not be
possible to meet all of the sulfur oxides control
requirements in these plans within the time frame
required by the act. Because of physical limitations
on our ability to clean the emissions of high-sulfur
fuels on a large scale in the time permitted by the act,
achievement of the particulars of the State plans
would require the availability of large additional
supplies of "clean" fuels—natural gas and low-sulfur
coal and oil. Unfortunately, our long-overdue concern
for air quality comes at a time when the abundance
of clean fuels in the United States is rapidly
disappearing and energy experts are becoming
worried about our ability to meet our energy needs,
even independent of environmental considerations.
Our per capita energy consumption is the highest in
the world—twice as much as that for Great Britain;
2% times as much as that for Germany; 4% times as
much as that for Japan. Our average annual energy
demand has risen from 2.2 percent for the 1955-1960
period to 5.1 percent for the 1965-1970 penod-ronly
10 years later. In 1972, petroleum demand alone
grew by 7.2 percent. The significance of this is starkly
outlined when we reflect on the fact that a 4-percent
growth rate doubles demand every 17 years, and a
7-percent growth rate doubles demand every 10
years.
In the fall of 1972, EPA determined that the
implementation plans would jeopardize the
production of more than 100 million tons of U.S.
coal. By delaying or modifying regulations more
stringent than those needed to meet primary ambient
standards, this coal could be utilized. Accordingly,
for the past year EPA has been working with the
States to delay imposing those regulations which are
designed to protect against property damage and are
stricter than those necessary for attaining health
standards. This policy permits more coal to be burned
and frees clean coal and scarce stack gas cleaning
equipment to be used in areas where they are needed
to meet the more important health standards.
Obviously, developing processes which will convert
high-sulfur or "dirty" fuels into low-sulfur or "clean"
-------
fuels will help in attaining the national ambient
standards. As the shortage of clean fuels like natural
gas worsens, there will be an increased demand for
more plants to produce clean fuels from dirty fuels.
Section 111 of the act directs the Administrator to
issue emission standards for new or modified sources
which may contribute significantly to air pollution
causing or contributing to the endangerment of
public health or welfare. The emission standards must
reflect the best degree of control (taking cost into
consideration) which EPA feels has been adequately
demonstrated. As an overriding consideration, no new
plant, even if it meets the new source performance
standards, can be built if it will cause a violation of a
national ambient standard. To date, new source
performance standards have been issued for 12 source
categories. These include fossil-fuel-fired steam
generators, Portland cement plants, incinerators.
nitric acid plants, sulfuric acid plants, asphalt
concrete plants, petroleum refineries, storage vessels
for petroleum liquids, secondary lead smelters,
secondary brass and bronze ingot production plants.
iron and steel plants, and sewage sludge incinerators.
Section 111 also authorizes the Administrator to
issue standards of performance for sources of
pollutants which have not been covered by a national
ambient standard or a hazardous air pollutant
standard. These pollutants are referred to as
"designated pollutants." This standard of
performance requires the States to submit a plan to
EPA with enforceable emission regulations applicable
to existing sources of the type covered by the
standard of performance. An example of this is
sulfuric acid mist from sulfuric acid plants. The
national ambient standard covers sulfur dioxide but
not sulfuric acid mist. States have not yet submitted
their plans for sulfuric acid mist from sulfuric acid
plants because EPA has not issued regulations or
guidelines specifying the requirements for such plans.
Draft regulations have been prepared and are
currently being reviewed within the Agency. These
regulations will be ready for proposal in the Federal
Register in the very near future.
The final important section of the act which deals
with stationary sources is section 112, which directs
the Administrator to issue national emission
standards for hazardous air pollutants. A hazardous
air pollutant will cause an increase in mortality or an
increase in the serious irreversible, or incapacitating
reversible, illness. These pollutants are considered to
be a more serious threat to public health than
pollutants covered by national ambient standards.
The hazardous pollutant emission standards must
provide an ample margin of safety to protect public
health. The act does not require the consideration of
cost or availability of control technology in
determining the allowable emissions for hazardous
pollutants. These emission standards are effective
upon proposal for new sources and within 90 days
after promulgation for existing sources. Waivers of
compliance may be granted to existing sources for up
to 2 years. Hazardous pollutant standards were issued
for asbestos, beryllium, and mercury on April 6,
1973.
It seems obvious from examining the provisions of
the act that Congress established a dichotomous
approach whereby emissions from existing stationary
sources are controlled to an acceptable level by the
State implementation plans and the emissions from
new stationary sources are to be stringently
controlled by new source performance standards to
prevent new air pollution problems.
EPA has developed a national strategy for air
quality management utilizing the implementation
plans and new source performance standards
provisions of the act. The strategy is designed to
result in an optimum regulatory effort. Hazardous
pollutants are considered a special case and will be
handled whenever data become available that indicate
a specific pollutant is hazardous.
As indicated earlier, new source performance
standards have been issued for only 12 source
categories. An accelerated program for new source
performance standards is being planned which will
result in more standards in a shorter time period.
There are several objectives which the new source
performance standards program will achieve.
Emphasis will be placed on the following areas: (1)
nitrogen oxides, (2) hydrocarbons (oxidants), (3)
sources reviewed in accordance with significant
deterioration regulations, (4) emerging industrial
processes, (5) augmentation of the air quality
management approach, and (6) designated pollutants.
(1) Nitrogen Oxides.
Currently, stationary and mobile sources each
contribute about 50 percent of the Nation's nitrogen
oxides emissions. The mobile source control program
recently proposed to Congress will cause a reduction
in total nitrogen oxides emissions from automobiles
for the next 20 years, despite growth. There is no
corresponding mandatory program for stationary
sources, and ambient nitrogen dioxide standards
cannot be maintained in most cities with only
automobile control. By 1985, the proposed
automobile standards will reduce nitrogen oxides
emissions so that stationary sources will contribute
-------
70 to 80 percent of the nitrogen oxides emissions.
This and other information indicate the need and cost
effectiveness of an intensive control program for
stationary sources of nitrogen oxides.
Since many control procedures for nitrogen oxides
involve basic burner designs, they are applicable only
to new sources. Such an intensive new source
performance standard program for all important
nitrogen oxides sources is assumed in EPA's request
to Congress to delay implementation of the 1976
automobile standard of 0.4 gram per mile. To
implement it will require increased research and
development on control technology and a change in
the Clean Air Act to allow equipment standards as
well as the emission standards now allowed by section
111. Such a program is of first priority in the new
source performance standards program, although
standard setting and peak work loads will not yet
occur for several years.
(2) Hydrocarbons foxidants).
The hydrocarbon/oxidant relationship is very
complex. Current understandings include:
(a) Air quality standards will be very difficult to
achieve in most large cities;
(b) Nonurban oxidant concentrations far exceed
the national ambient standard throughout the
summer in many parts of the country;
(c) These concentrations are above natural
background levels and may be related to
atmospheric loading of hydrocarbons over large
areas;
(d) Stationary sources currently contribute 12
million tons of hydrocarbons annually (over 40
percent of emissions nationwide), and under
existing control programs this will increase to 14
million tons in 1985 (over 70 percent of the
total).
A recent analysis by EPA shows that the national
ambient standard for oxidants will not be maintained
in many urban areas without increased control of
stationary sources of hydrocarbons. Also, the
standard in nonurban areas will not be attained solely
by control of automobiles nor by transportation
control plans at selected sites. In many areas, it is
becoming obvious that maximum control of all
stationary sources of hydrocarbons is the best way to
complement the automobile standards in handling
oxidant problems. A near-term objective of the new
source performance standards program is to set
standards for all source categories where control is
achieved by conservation measures, i.e., controlling
evaporation and discouraging solvent usage or
substituting for it. Decisions on standards for sources
requiring control by afterburners will be delayed until
the extent of the need can be better determined.
Such a program is analogous to the automobile
control program and is a necessary complement to it.
(3) Prevention of Significant Deterioration.
All regulations and concepts being considered to
prevent significant deterioration of air quality rely on
the inclusion of applying available control technology
on major new sources to minimize deterioration. New
source performance standards provide a formal,
publicly developed, specific definition of available
technology for these large sources and will be a key
factor in the implementation of regulations.
Standards will be promulgated as soon as possible for
all sources listed for review in whatever significant
deterioration regulations are finally promulgated.
(4) Emerging Industrial Processes.
The emergence of new industrial processes, such as
coal gasification, use of oil shale, and gas turbines for
power generation, present control problems that
demand early study and documentation. State
agencies often do not possess the capability to reach
decisions on control in such cases. Emerging
industrial processes therefore present a class of source
categories for which new source performance
standards may play a unique role and are a continuing
necessity. The early use of new source performance
standards for such processes avoids future problems
in terms of nonuniform State/local regulations and
provides early direction to the industry.
(5) Augmentation of the Air Quality Management
Approach.
The major regulatory thrust of the Clean Air Act is
a program of air quality management. Theoretically,
the benefits of air quality management are great.
Under this concept, control is required only when
needed and only to the extent needed. Basically, the
air quality management approach is required for the
attainment and maintenance of the national ambient
air quality standards. For several reasons, this
approach is tenuous for particulate matter and
oxidants. The air quality standard for part icu late
matter cannot yet consider size of particles nor
chemical composition; all sources are not well known
(e.g., fugitive, reentrainment, aerosols formed in the
atmosphere from gases); and background levels are a
problem. Poor understanding of the
hydrocarbon/oxidant relationship, the present
inability to attain source receptor modeling, and
natural background levels are current problems for
oxidant strategies. Although implementation plans
based on current knowledge must be pursued under
the act, mastery of air pollution caused by paniculate
-------
matter and oxidants may be a longer term affair and
may eventually depend simply on widespread
application of good source control. In this regard,
new source performance standards operate like
automobile standards. They are the least costly ways
of applying source controls over the long term. They
allow considerations of economic impact at the time
the standards are set, they minimize the possibility of
continually changing emission limitations, and they
provide information on control needs at the time that
industry makes decisions on expansion. Future new
source performance standards for sources of
participate matter will emphasize control of fine
particulates, toxic metals, and fugitive pollutant
sources.
(6) Designated Pollutants.
For some pollutants that are emitted from only a
few types of sources or u t are a problem in only a
few sections of the country, the full program of
setting a national ambient air quality standard and
requiring States to submit implementation plans is
not warranted. New source performance standards
and the regulation of existing sources by States
through the mechanism of section 111 (d) will provide
a complete national strategy for these pollutants.
After analysis of the options, EPA has determined
that control of fluorides is needed and that it should
be handled under section 111; therefore, new source
performance standards will be proposed in the very
near future for most significant fluoride sources.
An EPA program for setting new source
performance standards on fuel conversion processes is
well underway. The present emphasis is on regulating
sulfur emissions; plans are not yet firm for developing
standards for hydrocarbons, nitrogen oxides,
particulate matter, or hazardous pollutants. Booz,
Allen, & Hamilton is under contract to identify the
technology 'that could be applied to remove and
recover sulfur compounds from gases produced in
fuel conversion facilities. This investigation will also
assess the emission reduction and the associated costs
that will result from applying this technology. The
completion of the contract is scheduled for
November 1974. Battelle Columbus Laboratories is
also under contract to identify and assess alternative
control strategies that could be applied to regulate
sulfur emissions from fuel conversion plants and to
determine the potential emissions from the
installation of fuel conversion facilities. This contract
is scheduled to be completed in July 1974.
Plans have been made to propose new source
performance standards for plants which convert coal
to substitute natural gas by March 1975 and for
plants that convert coal to low-Btu gas for use as an
industrial fuel by September 1975. Projects are being
initiated to study processes for converting oil shale
and tar sands to gas and for liquefying coal; however,
a schedule has not yet been developed for proposing
such standards.
10
-------
ENVIRONMENTAL QUALITY AND STANDARDS FOR WATER
Kenneth M. Mackenthun *
Abstract
The Federal Water Pollution Control Act
Amendments of 1972, P.L. 92-500, provide a
framework of comprehensive and interrelated laws
and actions for the protection, preservation, and
enhancement of the water environment The national
goal as expressed in this comprehensive legislative
package is that, wherever attainable, by 1983 water
quality should provide for the protection and
propagation of fish, sfiellfish, and wildlife, and for
recreation in and on the water. Furthermore, the
national policy is that the discharge of toxic
pollutants in toxic amounts be prohibited. Water
quality criteria provide tiie baseline of the protection
pyramid for the aquatic environment. Water quality
criteria are levels of particular constituents in water
that, when not exceeded, will insure successful
propagation and continuation of aquatic life
significant for the preservation of the integrity of the
aquatic resource. From such criteria, ambient quality
standards may be developed as an enforcement tool
in water resource preservation. Likewise, effluent
limitations or standards for toxic materials and for
other pollutants are included as provisions of P L.
92-500 to insure that the receiving waterway is
protected against violation of the criteria necessary
for its continued survival. In addition to a foundation
of good laws, regulations, and enforcement
capabilities, society needs yet another goaf. There is a
need for an environmental ethic that reflects the
ecological conscience and conviction of individual
and corporate responsibilities and that would help
water, land, and air in its natural self renewal. The
solution to environmental problems facing society
today is the heart of survival itself
Contemporary man is beset with many complex
water-associated environmental problems, each of
which seems of such urgency that solutions must be
found. Society has long witnessed the results of envi-
ronmental neglect. We have seen environmental
problems grow in magnitude, seemingly feeding upon
themselves, as in uncontrolled cancer
•Director, Water Quality Criteria Staff, Environmental
Protection Agency. Washington, O C. 20460
Man's continuing struggle to reach a viable com-
patibility with his environment has attained a signifi-
cant and accelerating degree of concern in recent
times. The term "ecology," which initially was used
to denote the relationship of an organism with its
environment, has now been broadened in popular
usage to include nearly any and all environmentally
related problems. Formerly, such words as "ecology"
and "eutrophication" were used by a scientific few
only, now they are commonplace dinner-table words
As citizens, we are concerned about the accelerating
degradation of our environment as well as about clean
water, clean air, and the lasting quality and quantity
of our resource base. As a society, we are confronted
with mountains of solid wastes, some of which spill
into our waterways, mountains of sewage sludge that
must reach an ultimate disposal site; the discharge,
spill, or dumping of toxic or hazardous materials; the
quality and quantity of the Nation's streams, rivers,
estuaries, and wetlands; as well as the maintenance
and the renewabihty of the vast oceanic resource,
which is the ultimate receptor of many of the
Nation's waste products.
Environmental controls for abating environmental
insults can be obtained in an appropriate and in an
adequate fashion. Such controls can be achieved
through a combination of. (1) strong legislative and
governmental units to propose, enact or promulgate,
and enforce laws and regulations, (2) citizens' con-
cern and consciousness, and their desire to improve
the environment and leave it a better place in which
to live, although by so doing, it may result in changed
life styles, (3) the identification, investigation,
research, and demonstration of environmental pollu-
tion and its treatment or control; and (4) the applica-
tion of the best in technology to recycle, reduce in
quantity, and treat to an adequate degree the waste-
waters arising from municipal, industrial, agricultural,
and other activities.
Generally, society has enacted laws adequate to
provide controls for major pollutants. Such laws had
their genesis in the early 1900's; by the 1930's and
the 1940's, good pollution laws began to appear as
State statutes. Federal laws, likewise, have been
getting more stringent throughout time.
On January 1, 1970, the National Environmental
Policy Act, Public Law 91-190, was signed into law.
11
-------
This act directed all Federal agencies to consider the
environmental consequences of any proposed action
and decisionmakmg. Specifically, it required a
detailed statement of the environmental impact or
assessment of each proposed action significantly
affecting the quality of the human environment. Such
a statement must address any adverse environmental
effects which cannot be avoided should the proposed
action be implemented, alternatives to the proposed
action, and any irreversible or irretrievable
commitments of resources that would be involved in
the proposed action. At the time of its enactment, it
was hailed as one of the most significant Federal laws
relating to the protection of environmental quality
That appraisal has not dimmed appreciably today.
The ocean-dumping bill was another significant
piece of Federal water pollution control legislation.
This law, the Marine Protection, Research, and Sanc-
tuaries Act of 1972, Public Law 92-532, was enacted
October 23, 1972. The act prohibited the dumping of
any radiological, chemical- or biological-warfare
agents or any high-level radioactive wastes into the
ocean. It established an EPA permit system for the
control and dumping of other materials into desig-
nated ocean dump sites. Permits that are issued for
ocean dumping are based on criteria that take into
account the effects of such dumping on fisheries
resources, plankton, shellfish, wildlife, shorelines, and
beaches. The act provided that the Corps of Engineers
would permit the dumping of dredged spoils pursuant
to criteria developed by the Environmental Protec-
tion Agency for the protection of the oceanic
resource.
The Federal Water Pollution Control Act Amend-
ments of 1972, Public Law 92-500, were enacted into
law on October 18, 1972. This very comprehensive
water pollution control legislation established a
nationwide system of permits, aimed at controlling
the discharge of pollutants from all point sources into
the Nation's waters. Industrial point-source waste dis-
charges must be provided with the best practicable
control technology currently available by July 1,
1977, and the best available technology economically
achievable by July 1, 1983. Domestic sewage must
receive secondary treatment by July 1. 1977, with a
higher degree of waste recovery at a future date. The
granting of Federal funds to support States and
communities in sewage treatment plant construction
was accelerated by the act. Other highlights of the act
addressed nonpomt source wastes, the discharge of
toxic materials, water quality criteria and standards,
effluent limitations, pretreatment standards for indus-
tries entering municipal sewage treatment plants, and
the restoration of eutrophic lakes.
A century ago, the famous French physiologist,
Claude Bernard, wrote, "True science teaches us to
doubt and, in ignorance, to refrain." For many
environmental issues, the crisis stage has been
reached, and we have lost the alternative that would
permit us to refrain from taking an action. Society
must proceed steadfastly, with reasoned and
considered judgment, and with wisdom to solve its
environmental problems. Decisions must be based
upon the state-of-the-art of contemporary knowledge.
Ignorance, in the context of the quote, must be
associated only with the broadest of definitions. It
has been said that science at best is not wisdom; it is
knowledge Wisdom is knowledge tempered with
good judgment. Good judgment is fostered by wide
experience dealing with the knowledge of science
and, in the case of water quality, with a broad
association with water pollution problems.
The act provided a number of separate points of
attack to control, preserve, and enhance water
quality. Significant among these are provisions for
developing water quality criteria, the institution of
water quality standards, the development and
enforcement of effluent restrictions for toxic
materials, and effluent limitations for industrial waste
categories. Quality criteria are the baseline in the
pyramid of actions for the management and control
of pollution within the aquatic environment. Water
quality criteria are scientific facts developed from
experimental or in situ observations that depict
organism responses to a defined stimulus or material
under identifiable or regulated environmental
conditions. Such criteria are based upon the
state-of-the-art in analytical capability, and in
interpretive judgment at any given time. From such
an assemblage of criteria, which represent
experimental or in situ facts under given
environmental conditions, a recommended criterion
may be formulated for a specific element or material
that is designed to include a sufficient degree of
safety, to protect the aquatic environment, or to
provide for particular uses of the water A
recommended criterion specifies a concentration level
of the element or material that can be tolerated by
essential aquatic life, and that will permit a
continuation of life for those species.
The act required EPA to publish revised
recommendations for water quality criteria by
October 1973. The prime sources for these
recommendations included the 1968 Report of the
National Technical Advisory Committee to the
Secretary of the Interior and a revised and updated
12
-------
version of this report to EPA prepared under contract
by The National Academy of Sciences. Comments
currently are being received on the proposed water
quality criteria. Effort is progressing toward the
development of this document into a form suitable
for final publication. The goal in this endeavor is to
arrive at the most adequate criteria levels under our
current state of knowledge for the protection of the
aquatic resource. The act states that criteria for water
quality must accurately reflect the latest scientific
knowledge of the kind and extent of all identifiable
effects on health and welfare, including, but not
limited to, plankton, fish, shellfish, wildlife, plant
life, shorelines, beaches, esthetics, and recreation
which may be expected from the presence of
pollutants in any body of water, including
groundwater. Properly prepared, water quality
criteria define the limits of quality that will provide
for a continuation of life in water acceptable to
society and for those particular uses which man has
associated with water since Biblical times.
Prior to the 1972 Amendments, the Federal Water
Pollution Control Act required States to adopt, for
Federal approval, and to enforce water quality stan-
dards for interstate waters. Each of these standards
consisted of a designated use or uses for the water
body, quality criteria, and schedules of implemen-
tation for sources discharging pollutants into the
water whose achievement would result in meeting the
designated criteria. The 1972 Amendments mandate
an expansion of the Federal/State water quality stan-
dards system to make them applicable to all navigable
waters, including mtrastate waters. The act further
provides that the States shall review applicable water
quality standards at least once every 3 years and, as
appropriate, modify and revise their content The
principal bases for the water quality standards are
quality criteria.
The act provides that designated toxic materials be
considered as a special category and that effluent
limitations for such toxicants shall be developed that
take into account the toxicity of the pollutant, its
persistence, degradabihty. the usual or potential
presence of affected organisms in receiving waters,
the importance of such affected organisms, and the
nature and extent of the effect of the toxic pollutant
on such organisms. Again, quality criteria provided
the baseline of data from which effluent limitations
were developed for the toxic materials.
A discharge of heat is a pollutant under the pro-
visions of the act and is subject, to applicable effluent
guidelines and to water quality standards. A special
section of the act contains provisions unique to ther-
mal discharges that (1) permit thermal control
requirements to be modified if the discharger can
demonstrate that such requirements are excessively
stringent for the protection of aquatic life, (2) require
that effluent limitations minimize the potential
damage of cooling-water intake structures, and (3)
provide assurances that the pollution source will not
be required to make multiple modifications respect-
ing its thermal components within a short time
period.
The act provides for .the definition of effluent limi-
tations placed upon industrial categories of point-
source wastes that provide the best practicable con-
trol technology currently available for 1977 imple-
mentation and the best available control technology
economically feasible for 1983 implementation. In
addition to the ongoing effort within the Agency to
define and promulgate these technologic levels for
particular industrial categories, the act provides for an
Advisory Committee consisting of nine scientists and
engineers qualified by education, training, and experi-
ence to provide, assess, and evaluate scientific and
technical information on effluent standards and limi-
tations. The Committee is to transmit such informa-
tion to the Administrator of the EPA for his evalua-
tion in connection with the development and promul-
gation of industrial effluent limitations and toxic
materials standards.
Secondary treatment is a mandated uniform stan-
dard for the control of municipal sewage. Pretreat-
ment standards for new and existing industrial
sources have been written to protect the operations
of the treatment works into which such industries
discharge, as well as to prevent the discharge of pollu-
tants that may be inadequately treated in the munici-
pal treatment plant. Such pretreatment standards pro-
hibit influents into municipal works which could
cause fire, explosion, process upsets, or other opera-
tional damages.
The control of discharges into navigable waters is
through the issuance of a permit whose terms will be
based on effluent guidelines, toxic effluent standards
for certain classes of sources, and water quality
standards. The effluent guidelines provide the
base-level for permit limitations These will be revised
where necessary to meet applicable toxic materials
standards and water quality standards. The significant
portion of the water quality standards, from the
standpoint of permit issuance, is the body of water
quality criteria that define quality for life in water.
The act provides for the development of criteria to
control the dumping of dredge spoils into navigable
waters, as well as to control the discharge of wastes
13
-------
into estuaries and the near-shore areas of the ocean.
Provisions are made for the enforcement of standards
to insure that the discharge of human body wastes
from vessels receives adequate treatment. The
discharge of wastes from Federal facilities is
addressed in stringent language, and special provision
is made for an attack on problems associated with the
Nation's lakes, particularly problems of an eutrophic
nature.
Laws and regulations provide a framework and a
focus for national concern. They do not necessarily
provide the ultimate in environmental protection. In
addition to a foundation of good laws, we must
develop meaningful citizens' environmental concern
and consciousness in all age groups. We must develop
and practice a meaningful environmental ethic, both
as individuals and as a community. As Aldo Leopold
wrote over a quarter of a century ago, "An ethic,
ecologically, is a limitation on freedom of action in
the struggle for existence..." Leopold knew of what
he wrote He was a renowned professor of wildlife
management at the University of Wisconsin, and he
knew the land and the plants and animals that resided
thereon. He said that an environmental ethic must
reflect the existence of an ecological conscience and a
conviction of individual and corporate responsibilities
for the capability of the water, land, and air
environments for self-renewal. Such an ethic must
embody ethical and esthetical qualities in addition to
the essential economic and technologic
considerations. The integrity, quality of life, stability,
and beauty of the biotic community and the
environment that supports it must be preserved. As
Leopold said many years ago, "A decision is wrong
when it tends not to foster these principles "
Today, as never before, society is in need of an
environmental ethic on the part of the residents on
this planet Earth. The solution to environmental
problems that confronts us as a group is the heart of
survival itself. The sages of yesterday were aware of
this fact. Today's man on the street is convinced of
its truth.
14
-------
COAL CONVERSION TECHNOLOGY AND SOLID
WASTE DISPOSAL: TIME TO TAKE STOCK
A. Blakeman Early, Esq.*
Abstract
The growth of demand of energy is rising at an
alarming rate. As coal conversion technologies are
developed and applied to meet this growth,
significant disposal problems caused by a diminishing
number of disposal sites and greater environmental
requirements must be confronted. The technologies
which generate the wastes which are the feast harmful
and are in the smallest volumes deserve attention.
When conversion technologies are applied
commercially, adequate disposal for solid wastes
generated many years in the future must be secured
as soon as possible.
This symposium on "Environmental Aspects of
Fuel Conversion Technology" is reflective of the
revolutionary change in perception which has taken
place over the past several years in our Nation's views
on the uses and abuses of science and technology.
One might designate Earth Day 1970 as the date
when, as a nation, we discovered that we must
confront and solve some important questions in our
headlong drive toward progress and random growth in
technology, industrialization, urbanization, and
population. How can we adjust our sense of priorities
to insure that we fulfill our energy, transportation,
housing, recreation, and personal consumer needs,
without intensifying resource depletion,
environmental, and public health problems that we
did not anticipate and that we do not want' Some
people, the young in particular, are so shocked by the
mounting number of problems that they seem willing
to reject the benefits of technology in order to solve
the byproduct problems, which heretofore had been
viewed as being outside the total structure of our
complex industrial society.
Even though subsequent celebrations of Earth Day
have by no means reached the peak of fervor that
characterized the first one, that occasion marked the
beginning of what may be called a worldwide
environmental revolution.
I use the word "revolution" because the movement
so seriously challenges so many powerful cultural
values deriving from the original industrial revolution.
* Legal Assistant to the Office of Solid Waste Management
Programs, Environmental Protection Agency, Washington,
D.C.
In this country, it has already yielded, among other
things, important new legislation at all levels of
government, major changes in the attitudes, and, to a
significant but lesser extent, changes in the practices
and activities of government, industry, and
individuals. The U.S. Environmental Protection
Agency is itself a product of the new wave of
environmental awareness which crested as this decade
began.
I hope I have not given the impression that
everything has gone smoothly and that everyone has
fallen into step to march toward a new world in
which we use technology and science more wisely
than we have in the past, without complaint and
without disruption. To the contrary, there has been a
lot of complaint and considerable disruption; but on
the whole, the changes in institutions and attitudes
that have come about in our society since 1970, in
both the private and public sectors, are a remarkable
testimony to the validity of the new environmental
awareness that first surfaced in that year.
The current energy shortage, which of course has
repercussions throughout the world, has given great
encouragement to many who apparently are unwilling
to face the fact that the future, when man will have
the capacity to destroy the world in one great bang or
slightly more slowly through continued
environmental mismanagement, is now.
Our per capita energy consumption is the highest in
the world—twice that of Great Britian, two and a half
times that of Germany, and four and a half times that
of Japan. Our average annual increase in energy
demand has risen from 2.2 percent level for the
1955-60 period to 5.1 percent level for the 1965-70
period—only years later. In 1972, petroleum demand
alone grew by 7.2 percent. The significance of this is
starkly outlined when we reflect on the fact that a
4-percent growth rate doubles demand every 17
years, and a 7-percent growth rate doubles demand
every 10 years.
Even official energy consumption projections to
the year 2000, based on a 3.5 percent average annual
growth rate, yield the following implications for the
year 2000: a trebling of energy requirements, a
doubling of per capita use, and an increase to 900
nuclear reactors from the 39 now operating.
Oil imports could increase to twice our entire
15
-------
domestic output today. Imports would approximate
25 million barrels per day—five times the current
levels—and oil spills could proportionately increase.
Given such import levels, the effects on our Nation's
foreign policy could be devastating. All of these
conditions can be expected by the turn of this
century if energy consumption grows at only
two-thirds of the average annual rate of the last
decade.
These projections, based on Department of Interior
figures, make it quite clear that the silver lining in the
energy cloud may indeed be the unpleasant shock
which will wake us to some of the important realities
of our time. Thus, the importance of developing coal
conversion technologies has been brought to the
forefront by rising demand for energy and then
reemphasized by the Arab oil embargo, which
demonstrated that this Nation could not remain
dependent on oil imports to meet the demand.
The importance of developing other
energy-producing technologies has been likewise
emphasized. The Office of Solid Waste Management
Programs, in which I serve, has initiated a number of
demonstration projects designed to recover significant
amounts of energy from mixed municipal waste, as
well as to recover important materials.
About 125 million tons (1971) of solid waste are
generated each year from homes and commercial
establishments (offices, stores) across the country.
About 70 to 80 percent of this is combustible and
can be converted into energy through modern
technology.
Some of this technology is being demonstrated by
EPA. EPA's demonstration project in St. Louis.
Missouri, converts solid waste into a low sulfur fuel
that can be used as a supplement to coal in power
plant boilers. Every ton of solid waste can be
converted into 900 kilowatts of electricity.
Two other EPA-supported projects, one in
Baltimore and one in San Diego, will convert solid
waste into a combustible gas or oil using a pyrolysis
process. Operations begin in late 1974 or 1975.
If energy recovery were practiced in all SMSA's in
the United States, about 800 trillion Btu's would be
recovered annually. This corresponds to the energy in
about 4,000,000 barrels of oil per day. By
comparison, this is equal to 5% percent of the fuel
requirements of all electric utilities, 12 percent of the
coal used by electric utilities, and about 1 percent of
all the energy consumed in the United States in 1970.
In the area of solid waste collection and disposal,
our efforts also encourage a significant savings in fuel
by providing information and technical assistance to
cities for the purpose of enhancing productivity and
efficiency in the collection and disposal of solid
waste.
The future for coal conversion technologies appears
to be a bright and active one because coal is the one
energy resource which is abundant in domestic
reserves and because much of the coal contains too
much sulfur and other pollutants to be burned
directly without causing unacceptable levels of air
pollution unless.more efficient and less costly
post-combustion cleanup processes are developed.
Whether the pollutants are removed before this
valuable resource is burned for its Btu value or
afterwards, they must be disposed of in an
environmentally sound manner.
EPA is concerned about the environmental impact
from the land disposal of mounting volumes of air
and water pollution control residuals. These volumes
are not insignificant. Air and water pollution control
residues could rise from the 28 million tons generated
in 1971 to 170 million tons in 1985 (ref. 1). The
hazardous wastes attributable to these residues could
rise from 11,000 tons in 1971 to at least 51,000 tons
in 1985, not including radioactive wastes (ref. 2). The
vast majority of these residues will be generated by
processes designed to control paniculate and sulfur
oxide emissions. Control of nitrogen oxide emissions
is unlikely to create significant amounts of solid
residues, even though relatively large amounts of
these pollutants are discharged following combustion,
since the reduction of excess nitrogen oxides duirng
combustion or low-temperature combustion are the
techniques most likely to be used. Neither process
results in the creation of solid waste residues (ref. 3).
Most coal conversion processes are in the early
stages of development such that the volume and
nature of residues that will be generated cannot be
predicted with much accuracy. It is assumed for
purposes of this discussion that the nature and
volumes of these residues will approximate those of
conventional coal burning processes. Indeed, several
coal conversion processes will be using conventional
scrubber systems to clean flue gases as well as the
product gas prior to distribution. Consequently, a
look at land disposal problems associated with
conventional coal burning processes is likely to
provide a useful indication of potential land disposal
problems to be faced by coal conversion processes.
At present, wet lime/limestone scrubbing systems
constitute the great majority of full-size power plant
desulfunzation processes. These systems are efficient
and require relatively low capital and operating costs.
Also, they have a longer history of development.
16
-------
Variations of the process involve the use of either
lime or limestone as the reactant which is carried into
contact with the flue gas in an aqueous liquor. This
liquor is either totally recycled (termed a cyclic
operation) or totally disposed of (termed a noncyclic
operation) to a reservoir. The noncyclic operation can
pose some obvious water pollution problems caused
by leaching to surface and ground waters.
Consequently, it is believed that the large majority of
systems will use a cyclic operation. Nevertheless, the
solid in the liquor must be settled out before it can be
reused, and this sludge must be disposed of on the
land. These sludges contain calcium hydroxide,
calcium carbonate, calcium sulfate, and calcium
sulfite. Where efficient paniculate removal is not
performed upstream of the scrubber, such sludges can
contain large quantities of coal ash. These liquors, in
equilibrium with sludge materials, typically have
dissolved solid contents of approximately 3,000 to
15,000 ppm (ref. 4). The two major methods of
disposal are dewatering the sludge and trucking it
offsite for landfilling, or pumping the sludge into a
pond designed for permanent retention. Sulfur
residues are produced at approximately a 50 percent
greater dry weight amount than the fly ash normally
produced by a conventional coal burning utility. This
means that the sludge and ash throwaway
requirement will be about 2.5 times the normal coal
ash disposal tonnage. Therefore, large storage
capacities are going to be necessary for disposal of
these sludges. For instance, a 1,000 MWe unit over a
20-year lifetime will require about 1.6 square miles of
land for disposal, assuming a wet sludge containing 50
percent solids was ponded to a height of 10 feet (ref.
5).
It is estimated that conventional coal burning
processes will generate 51 million tons of ash by
1975, 56 million tons by 1980, and possibly 72
million tons by 1985. Therefore, it is well that those
developing coal conversion processes share some
concern for the land disposal implications of these
volumes.
These volumes will be escalating at a time when
capacity for landfilling solid waste is declining
nationwide. It must be noted that many coal
conversion processes will be competing with
conventional coal burning processes as well as with
other generators of solid waste for the available
landfill capacity. Last year in a survey of cities having
populations greater than 10.000 conducted by the
National League of Cities and the U.S. Conference of
Mayors, 46.5 percent of the respondents indicated
that current solid waste disposal capacity would be
exhausted in from 1 to 5 years (ref. 6).
My use of the term "capacity" is intended to mean
capacity at disposal sites that are both located and
operated in an environmentally sound manner. Flood
plains, steep grades, areas above high water tables.
and areas of special environmental significance are
just a few of the locations where disposal sites should
not be located. The basics of sound disposal site
location and operation are described by EPA in its
"Proposed Guidelines for Thermal Processing and
Land Disposal of Solid Wastes" published in the
Federal Register (April 27, 1973, p. 10544). These
guidelines are expected to be promulgated in final
form in the near future. Although they are
recommendatory with regard to the public, section
211 of the Solid Waste Disposal Act, as amended,
make them mandatory for Federal agencies and
facilities.
In the future, disposal sites are not only going to be
difficult to find, but their location and operation will
be required to be conducted with greater care. For
those users of lime/limestone scrubbing systems, this
can prove to be a serious problem. Although there are
no enforceable Federal disposal standards at this
time, and State standards vary significantly, it is clear
that holding ponds for scrubbing liquors and
reservoirs for the long-term disposal of sludges which
have not been dewatered must be carefully
engineered and located, only after careful geologic
and hydrologic examination of the site, in order to
minimize the potential for leaching of pollutants to
ground or surface waters. Moreover, initial ponding
efforts indicate that the sulfate sludges have poor
steeling characteristics which make it unlikely that
the disposal site can be reclaimed for subsequent use.
In this case, the disposer may be required to provide
for monitoring and permanent care of the site to
guard against future environmental harm.
Even when the sludges are successfully dewatered
(problems have been experienced with mechanical
dewatering in this regard), disposal by means of a
sanitary landfill does not mean that such residues can
then be forgotten. Preliminary EPA research has
shown that a test sanitary landfill cell, 149 feet long
by 30 feet wide packed with 8 feet of mixed
municipal waste with a moisture content of 27.16
percent, generated 38,647 gallons of leachate over 22
months during which time 84.1 inches of rain fell
(ref. 9). Attention must be given by disposers to the
17
-------
containment and/or treatment of such leachate
generated by sanitary landfills used for residuals
disposal.
EPA's concern for adequate capacity is shared by
the Congress. The multitude of bills introduced over
the past year concerned with solid waste disposal
indicates that Congress is not satisfied with the
progress the States have made without the
stimulation of Federal regulation. The existing Solid
Waste Disposal Act, as amended, provides only for
Federal research, demonstrations, training, and
technical assistance in solid waste disposal as well as
for resource recovery. I would like to review briefly
some of the salient features of three bills that are
currently pending before the Congress and that
appear to have the most significant support.
The Resource Conservation and Recycling
Incentives Act, S. 2753, introduced by
Senator Philip A. Hart on November 28, 1973
The Administrator is required to issue Federal
standards for the regulation of unsafe waste
management practices which may include minimum
performance standards with respect to the methods,
techniques, and practices of waste management as
well as criteria for the location, design, construction,
and operation of waste treatment and disposal sites
and facilities. The Administrator shall also establish
standards for State waste management programs
which will require State permits for generators of
hazardous waste and operators of waste treatment or
disposal sites or facilities of such a nature or character
as to pose a significant risk to human health or the
environment. Permit holders must comply with
Federal/State requirements concerning information
recording and reporting, transportation, storage,
treatment, and transportation of wastes. If a State
fails to submit an adequate program, fails to properly
make such revisions, or fails to enforce its program as
the Administrator may require, the Administrator
shall issue regulations establishing an interim program
for such States.
Standards shall be established only after
considering all factors relevant to the protection of
human health and the environment,
including: contamination of ground or surface
waters, potential hazards to transportation modes or
facilities, risks associated with the decomposition of
waste, and risks of surface and subsurface fires at
disposal sites.
The Comprehensive Waste Management and
Resource Recovery Act, H.R. 13176,
introduced by Congressman Paul G. Rogers
on February 28, 1974
States must submit plans for the establishment and
operation of a waste management which must include
a permit system for operating a waste management
facility or dsposal site, the issuance and removal of
which is conditioned upon compliance with standards
for the location, design, construction, operation,
maintenance, and abandonment of such facility or
site. States must also establish a system for bringing
existing and abandoned open dumps into compliance
with such standards. As is stated in S. 2753. if the
State fails to submit, revise, or enforce such a plan,
the Administrator shall promulgate such regulations
as he deems appropriate.
The Administrator shall promulgate Federal
standards of performance for new sources of certain
waste generation categories that may contribute
significantly to the Nation's waste management
problems and the endangerment of the public health
or the environment. Such standards shall reflect the
degree of limitation achievable through the
application of the best system of reducing or
eliminating the amount of toxicity of any wastes
generated that has been adequately demonstrated. A
new source is defined as any facility that generates
wastes, the construction or modification of which is
commenced after the publication of regulations
prescribing a standard of performance. The
Administrator may delegate the primary
responsibility for enforcing such standards to any
State which submits an acceptable plan for
implementing them.
The Administrator would be required to establish
Federal standards and procedures for the storage.
treatment, and disposal of hazardous wastes which
would be enforceable by means of a Federal permit
system. The operation of the permit system may be
delegated to any State which meets such minimum
requirements that the Administrator may establish.
The Energy and Resource Recovery Act
of 1973, S. 3271, introduced by Senator
Pete V. Dominici, March 29, 1973
The Administrator would be required to
promulgate Federal standards for the collection,
handling, disposal, and recovery of all hazardous and
18
-------
other solid waste which may, if improperly disposed
of, cause air or water pollution or other
environmental damage. Each State may, but is not
required to, submit a plan for enforcing these
standards within such State for approval by the
Administrator. Upon approval, such States will be
authorized to enforce such standards within the
State.
Clearly, a pattern emerges from the foregoing
description. At least some members of Congress are
convinced that EPA should be empowered to issue
standards to insure that solid waste is disposed of in
an environmentally sound manner. These standards
would be adopted, with necessary modifications, and
enforced by the States. Although it is not possible to
predict what requirements EPA might consider
promulgating beyond those found in the Proposed
Guidelines, suffice it to say that such requirements
will serve to reduce the amount of land available for
use as disposal sites.
Even though Federal legislation will not be
forthcoming until some time in the future, the States
have not been idle in addressing solid waste disposal
problems. Although the comprehensiveness and
effectiveness of some State solid waste laws and
regulations vary widely, 45 States have such laws, and
29 States have some form of permit system for solid
waste disposal sites. Some of these regulations are
vague, but they take a significant meaning when
interpreted on a case-by-case basis by State
authorities. For instance, rule 314(e) of the Illinois
Solid Waste Regulations dealing with landfills merely
requires "adequate measures to monitor and control
leachate." Commonwealth Edison has found, to its
chagrin, that such "measures" can be interpreted to
be fairly rigorous.
In December 1971, Commonwealth Edison
retrofitted one of its cyclone boilers, which generates
177 MW, with a limestone wet scrubber system; it is
located in Will County, Illinois. The scrubber
produces approximately 19 tons of sludge per hour
when operating at full load capacity. Even though
Commonwealth Edison has spent nearly $2 million to
find a sludge treatment method which will satisfy
State authorities and which will allow the sludge to
be disposed of off site, it has experienced great
difficulty in locating a site which would be acceptable
to the State. The sludge is comprised of
approximately 30 percent solids, 50 percent of which
is calcium sulfite. The sulfites must be chemically
stabilized or they will reabsorb moisture after being
dried. State authorities feel that any site which has a
permeable underlying soil or rock condition would be
subject to sulfite ground seepage. The company has
installed a thickening process which utilizes a 65-foot
diameter thickener rather than utilizing the existing
sludge pond. After processing, the sludge generated
has a 40-percent solids content. Recently, the
company has been experimenting with vacuum
filtration and centrifugation as an additional method
of concentrating the sludge to a 55-percent solids
content. The sludge will then be solidified through a
chemical fixation process, thus involving the addition
of varying amounts of lime and fly ash to the sludge
(ref. 10). Commonwealth Edison has located an
abandoned quarry as a possible disposal site which
would have to be lined with an impermeable material.
It has an estimated capacity of about 1,000,000 cubic
yards. However, at the current rate of residue
production, the sludge and fly ash alone from the
four boilers will fill this site in less than 5% years, not
including the disposal of the scrubber sludge. Based
on this evidence, the company convincingly claims
that wet scrubber waste will put intolerable pressure
on the availability of acceptable disposal sites. In
addition, Commonwealth Edison claims that annual
sludge treatment costs will approximate $1,335.000
or $4.91/ton. while hauling and disposal costs will
approximate $3.36/ton. This would add about 2 mills
per kilowatt hour to the current cost of power from
this unit, or 13 percent (ref. II).
Other processes are being developed which are
considered to have the potential to desulfurize flue or
product gases on a full-scale commercial basis, and to
have relatively less significant disposal problems.
Indeed, the three processes of magnesium oxide
scrubbing, catalytic oxidation, and wet solium-base
scrubbing have the potential for producing large
quantities of sulfuric acid which could be sold
commercially, if market conditions were ripe. Wet
sodium-base scrubbing may also lend itself to the
application of technology to reduce the S02 to
elemental sulfur which could either be sold or
disposed of with fewer concerns for potential
environmental degradation. In this regard, the coal
conversion technologies that produce elemental sulfur
will have a distinct advantage over other processes
(ref. 12).
The foregoing discussion illustrates some of the
potential problems coal conversion technologies may
face concerning waste disposal on land. It may be
that by the time these processes are in operation
commercially, many of the disposal problems will be
solved. It does seem advisable, however, that those
involved in the development of these processes should
provide for the wastes which will be produced and
19
-------
should further develop and utilize technologies which
will generate these wastes in a form that will enable
their disposal on the land in the least volume and in
the safest manner possible. Those people involved in
the commercial application of coal conversion
technologies are advised to devote attention to
obtaining disposal capacity well in advance of need.
REFERENCES
1. Draft report entitled "Forecasts of the Effects of
Air and Water Pollution Controls on Solid Waste
Generation," Contract No. 68-03-0244 prepared
by Ralph Stone and Co. for Office of Research
and Monitoring, Environmental Protection
Agency, February 1974, at p. XX-1.
2. See ref. 1, p. XIX-55, Table XIX-12.
3. H. L. Falkenberry, A. V. Slack, and R. E.
Gantrell, "Control of Fossil-Fuel Power Plant
Stack Gas Effluents" in Proceedings, American
Power Conference. Vol. XXXIV. Chicago, III.,
1971. pp. 471-483.
4. Final Report of the Sulfur Oxide Control
Technology Assessment Panel in "Projected
Utilization of Stack Gas Cleaning Systems by
Steam-Electric Plants," April 1973, at p. 52.
5. See ref. 4, p.54.
6. C. E. Brackett, "Production and Utilization of
Ash in the U.S.,"Paper No. A-1 presented before
the Third International Ash Utilization
Symposium. Pittsburgh, Pa., March 13-14. 1973.
7. See ref. 1, p. XVI-17. Table XVI-10.
3. "Cities and the Nation's Disposal Crisis," A
Report of the National League of Mayors Solid
Waste Management Task Force, March 1973, at
p. 18.
9. Study conducted under the auspices of the
Office of Research and Monitoring,
Environmental Protection Agency, April 1973.
10. "Will County Unit 1 Limestone Wet Scrubber
Waste Sludge Disposal." by P. C. Gifford,
presented at The Problem Beyond Pollutant
Removal Conference sponsored by Electrical
World. Chicago, III., October 30-31, 1973.
11. Letter from Mr. J. P. McCluskey,
Commonwealth Edision to Mr. John Quarles,
Chairman, SO2 Control Technology Hearing
Panel, dated November 16, 1973.
12. See ref. 4, p. 13.
20
-------
ENVIRONMENTAL IMPACT STATEMENT REQUIREMENTS
AS RELATED TO FUEL CONVERSION TECHNOLOGIES
Sheldon Meyers*
Good morning. I cannot tell you how delighted I
was when I learned that a governmental organization
was going to sponsor a symposium on the
environmental aspects of fuel conversion technology.
It is, of course, quite proper that the Government
organization that is sponsoring the symposium is the
Control Systems Laboratory of the Environmental
Protection Agency.
What with the recent crisis in the supply of energy,
I was somewhat concerned that all the stops would be
pulled out in favor of unrestrained development of
new energy sources. When one is waiting in line for
gasoline for an hour or so, I do not think that there is
any particular sense of urgency related to protecting
the environment. But then again, crisis situations have
never been conducive to rational decisionmaking.
The question of interest resolves itself quite simply
as to whether or not those officials, public or private,
who are responsible for making decisions respecting
new fuel conversion technologies should factor
environmental considerations into the decisionmaking
formula.
From my perspective, there can be no responsible
position other than that which is in favor of
considering environmental values. But let me make it
absolutely clear, I am not advocating that decisions
respecting fuel conversion technologies be made after
considering only environmental factors, but that the
environment be considered along with the traditional
factors, such as technology and economics, before
such decisions are made.
It is particularly important to assess the
environmental impact of major programs such as coal
gasification and oil shale production in the aggregate,
as well as on a plant-by-plant basis.
I mentioned earlier the decisions to be made by
both public and private officials. Let me speak first of
the simpler case-the public sector.
Public Sector
The public sector is simpler, of course, because of
the National Environmental Policy Act of 1969-a law
•Director, Office of Federal Activities. Environmental
Protection Agency, Washington, D.C. 2046O.
which is binding on all Federal agencies who take
major actions significantly affecting the environment,
requiring them to prepare environmental impact
statements.
The National Environmental Policy Act of 1969
(NEPA)
Let me briefly discuss the genesis of the
environmental impact statement (EIS). It is a creature
of section 102(2)(c) of the National Environmental
Policy Act of 1969 (NEPA). This section states, in
part, that all agencies of the Federal Government
shall:
Include in every recommendation or report on
proposals for legislation and other major Federal
actions significantly affecting the quality of the
human environment, a detailed statement by the
responsible official on:
1. The environmental impact of the proposed
action;
2. Any adverse environmental effects which
cannot be avoided, should the proposal be
implemented;
3. Alternatives to the proposed action;
4. The relationship between local short-term
uses of man's environment and the
maintenance and enhancement of long-term
productivity; and
5. Any irreversible and irretrievable
commitments of resources which would be
involved in the proposed action, should it be
implemented.
Section 102(2)(c) also requires the responsible
Federal official, prior to making the detailed
statement, to consult with and to obtain the
comments of any Federal agency which has
jurisdiction by law or special expertise with respect to
any environmental impact involved. Copies of the
statements and comments thereon shall be made
available to the president, to the Council on
Environmental Quality (CEQ), and to the public. This
section along with implementing guidelines published
by CEQ in the Federal Register describe the content
and mechanics of what we now call environmental
impact statements.
Some additional points concerning the NEPA-f irst,
21
-------
the intent of the Congress in enacting the legislation.
Section 101(2) of the act clearly annunciates such
intent as follows:
The Congress, recognizing the profound impact
of man's activity on the interrelations of all
components of the natural
environment. . . declares that it is the continuing
policy of the Federal Government... to use all
practiceable means and measures ... to create
and maintain conditions under which man and
nature can exist in productive harmony, and to
fulfill the social, economic, and other
requirements of present and future generations
of Americans.
Second, the intent of the Administration in
concurring with the legislation. The President, in
signing the NEPA on January 1, 1970. declared that
the 70's
absolutely must be the years when America pays
its debt to the past by reclaiming the purity of
its air. its water, and our living environment. It is
literally now or never.
We see then, that the executive and legislative
branches of Government shared a unanimity of
purpose with regard to environmental protection.
What of the judicial branch? Subsequent events have
shown the courts to be vigorous proponents of the
environment by virtue of their decisions related to
the NEPA.
Third and most important, there is no provision in
the act for any Federal agency to veto the projects of
any other Federal agency. Those projects which thus
far have been enjoined by the courts for failure to
comply with NEPA were the result of procedural
difficiencies in the EIS rather than from postulated
environmental damage associated with the project.
So much for background. Has the preparation of
several thousands EIS's, since the enactment of the
NEPA, had a beneficial effect on the environment?
Or has the preparation of EIS's been an exercise in
bureaucratic paperwork serving only to needlessly
delay critical projects?
Environmental Impact Statements
As with many things, the effectiveness of EIS's has
been variable. In many instances, preparation of the
EIS for a particular project has had absolutely no
effect on the project. In some cases, projects have
been delayed, in others alterations were made which
were environmentally beneficial, and there are
examples of projects which have been cancelled.
There have been a number of court decisions, such
as Calvert Cliffs, Gillham Dam, and Kalur which have
drastically affected the internal operations of a
number of Federal agencies. There is no doubt that
the preparation of an EIS for a project which has
been underway for sometime can adversely affect the
schedule of completion, assuming that it is not
cancelled entirely. There are Federal agencies
involved in such projects-the completion of which
will have a critical impact on both the economy and
our well-being.
I concede that there is a problem with projects that
are in various stages of completion. However, I am
confident that solutions can be developed which will
accommodate these acknowledged near-term
problems. It is the longer-term use of EIS's that will
ultimately contribute to determining the kind of
environment in which we all live. The EIS can be used
in a project's formulative stages in much the same
manner as is technical and economic information.
Thus, it is in the planning stages of a project that the
EIS will prove its ultimate usefulness as a mechanism
for protecting the environment.
F/S and Fuel Conversion Technology
Since the National Environmental Policy Act and
its impact statement requirements are binding only
on the Federal establishment, then only those
programs with some sort of Federal involvement will
be affected. The Federal involvement goes beyond
Federal funding; it also affects:
1. use of Federal lands,
2. requirement of a Federal permit or license.
Thus, such projects as nuclear power plants, costing
on the order of $500 million of private utility capital,
require an EIS because the AEC must license the
construction and operation of such plants. Also, the
oil shale leases in Colorado and the drilling for oil in
the Outer Continental Shelf, which are being
developed completely with private capital, require an
EIS because of the permits issued by the Department
of the Interior.
A properly prepared EIS will provide a wealth of
information to management that would otherwise not
be available, thus giving it the opportunity to analyze
a number of options and to weigh the economic
benefit against environmental cost for each of these
options, before making a decision. In the past,
decisions were made on major projects which turned
out to be environmental disasters, in part, due to the
lack of pertinent information. It has been my
experience that, given the necessary information,
responsible Federal managers will decide in favor of
22
-------
the least environmentally damaging option even
though it may be a higher cost option.
Private Sector
What of the private sector, where the manager has
no legally binding mandate to factor the
environmental amenities into the decisionmakmg
process? Let us also assume that there is no Federal
involvement, to wif
1. The program involves only private lands,
2. No Federal permits or license required,
3. No Federal funds involved,
4. The program is exclusively within the
boundaries of a particular State and does
not cross Federal lands.
Under these circumstances, no EIS will be required.
But does that mean that a comprehensive
environmental analysis should not be done? I submit
to you that the answer should be no-that is to say
that the responsible private official should not make
his decision on technical and economic considerations
only but should also analyze the environmental
effects of the proposed project and its alternatives
prior to making his decision. I am, of course,
proposing an analysis similar to that required of the
Federal establishment pursuant to the NEPA. If after
completing the environmental analysis, the private
sector manager decides that the program should
proceed, even in the face of environmental damage,
then, at least, it will have been a conscious decision.
Such analyses, for example, are done by the world
bank prior to making major loans, even though they
are not obliged to do so by law.
How then should those of you involved in new fuel
conversion technologies view the added factor of
environmental analysis in the decisionmaking
process? Is it something of benefit deserving the
application of valuable monetary and personnel
resources, or, on the other hand, is it an obstacle that
must be overcome or avoided completely? I trust that
an intelligent review of all the pertinent issues will
bring you to the same conclusion which I have
reached; that is. the environmental analysis is clearly
desirable and moreover in the national interest,
particularly if we feel any responsibility at all for the
future well-being of the citizens of this country.
23
-------
-------
13 May 1974
Session 11:
FUEL CONTAMINANTS
Rene" R. Bert rand
Session Chairman
25
-------
-------
PROBLEMS IN THE CHEMISTRY AND STRUCTURE OF COALS AS
RELATED TO POLLUTANTS FROM CONVERSION PROCESSES
P. H. Given*
Abstract
In the present state of knowledge, one can only
make predictions of the probable pollution problems
that will arise in coal conversion processes. The
predictions must be based on (a) details of individual
conversion processes, including ancillary operations,
(b) knowledge of the organic and inorganic
constituents of coals, and (c) geochemistry of the
different major coal-producing areas of the country.
The principal types of minerals in coals are clays,
quartz, carbonates, pyrite, and sometimes feldspars.
Potentially polluting trace or minor elements may be
associated with any of these or with the organic
matter; the fate of these elements in conversion
processes will depend on the nature of the association
of each element as well as on its chemical properties,
but available data on trace elements in coals do not
include information on the type of association.
Existing knowledge of the chemistry, geochemistry,
petrography, and mineralogy of coals will be reviewed
in relation to conversion technology in such a way as
to facilitate predictions of potential pollution
problems.
In all coal conversion processes, the sulfur content
of the product is much less than that of the coal.
Therefore, sulfur emission is not a problem when the
product fuel is burnt. It is difficult to see how any
gaseous fuel produced from coal could contain
significant quantities of any environmentally
hazardous material. Liquid fuels might contain small
quantities of undesirable trace elements; whether or
not this is likely to be generally true has not been
determined yet.
The matter of most concern is whether or not the
conversion processes themselves are likely to give rise
to toxic emissions of sulfur or trace elements. The
answer to this question obviously depends partly on
the nature of the process, and it will have to be
determined by establishing mass balances between the
input of toxic elements in the coal feed and output in
the various product and byproduct streams. It will
also have to be determined whether toxic elements in
'Professor of Fuel Science, Materials Science Department,
Pennsylvania State University, University Park, Pennsylvania.
any solid wastes are easily leached out by waters or
are tightly locked into the chemical structures. The
other important factors governing the potential
hazard of conversion processes are the characteristics
of the coal used as feed stock. It is with this factor
that this paper is chiefly concerned.
Coals are derived from partly decayed plant
material that accumulates in a peat swamp. The
material includes woody parts of trees (stem,
branches, roots), leaves, spores and pollen (often only
the waxy outer covering of these three), some
charcoal-like substance from wood charred in forest
fires, and some ill-defined amorphous material. These
various types of substances are still recognizable after
coalification. Grains of sand and clay minerals are
transported in by ground waters, and mixed with the
organic material; also, pyrite may be formed in situ as
a result of microbiological processes, particularly
when the water saturating the peat is saline.
All peats, soils, river waters, etc., contain some very
ill-defined substances known as humic acids. These
contain a variety of oxygen-containing functional
groups (carboxylic acid -COOH, phenolic -OH,
carbonyl C=O), which can fix cations by ion
exchange with the acid groups but can also very
strongly complex a variety of cations by dictation
with adjacent functional groups in the structure. Of
course, the plants growing in a peat swamp, like all
other organisms, need a variety of trace elements for
health growth; the peat must have a mechanism for
concentrating or trapping the elements needed and
for making them available to the plants and
micro-organisms growing in the peat. Humic acids, or
parts of their structures, survive in chemically
recognizable forms in lignites and subbitummous
coals.
Although components of peats have a large
potentiality for trapping many elements, the actual
concentrations are highly variable and in fact quite
low in some parts of a swamp. Suppose, for example,
that the peat swamp is in a basin surrounded by hills.
Rocks in the hills are eroded by natural processes,
and the trace elements released (together with
chemically altered mineral grains) are washed by ram
and streams down into the basin. Trace elements will
tend to be trapped in the margins of the swamp, and
the center will then obtain only low concentrations.
27
-------
Table 1. Approximate values of some coal properties in different rank ranges
1 C (m1n. matter free)
t 0
1 0 as COOH
% 0 as OH
Aromatic C atoms
X of total C
Avg. no. benzene rings/
layer
Volatile matter, *
Reflectance, X
(vitrtnlte)
Dens i ty
Lignite
65-72
30
13-10
15-10
50
1-2
40-50
0.2-0.3
Subbltu-
minous
72-76
18
5-2
12-10
65
»
35-50
0.3-0.4
High vol. bituminous
C 5 JT~
76-78
13
0
9
?
35-45
0.5
78-80
10
0
?
?
2-3
?
0.6
80-87
10-4
0
7-3
75
31-40
0.6-1.0
Medium
Volatile
89
3-4
0
1-2
80-85
31-20
1.4
Low
Volatile
90
3
0
0-1
85-90
5?
20-10
1.8
Anthra-
cite
93
2
0
0
90-95
>25?
<10
4
Increases
If coal formation is going to occur, sooner or later
the peat gets buried under a load of other material as
the area subsides. Geological processes may permit it
to be buried as deep as 7,000 metres (20,000 feet),
though this may take tens of millions of years to
happen. At this depth, the temperature may be
200°C and the pressure may be 1,500 kg/cm2. If
burial is less deep, temperature and pressure will of
course be lower. It is a geological fact that when deep
subsidence occurs in an area, sooner or later the
process is reversed, and sediments come back nearer
the surface {and mountains arise in what was once a
low-lying basin). The time of exposure of a peat
stratum to elevated temperatures and pressures is
therefore limited.
In practice, in many of the major coal basins, the
right conditions for forming a peat swamp have
recurred many times (20-50?) during the whole
subsidence episode. Therefore, we may end up with a
large number of superimposed coal seams, separated
by varying thicknesses or inorganic rocks. The deeper
the seam, the higher is the temperature-pressure
regime it has experienced, and the longer the time it
has been exposed to these conditions. It is exposure
to elevated temperature (chiefly) for some millions of
years that brings about the conversion of plant debris
(peat) into coal. The more severe is the
temperature-time history, the greater the degree of
alteration of the organic material. In the situation
considered above, where there are many
superimposed coal seams, there will be a progressive
change in a variety of chemical, physical, and
technological properties as we examine sequentially
the series of seams from top to bottom (or vice
versa).
It is the extent of alteration of the organic material,
associated with a progressive shift in properties, that
is described by the term "rank"; high rank coals have
been extensively altered. Rank is, therefore, a
more-or-less continuous variable. For industrial users
of coal, a continuous variable is too complicated, and
classification systems are used in which the whole
spectrum is divided into about 10 ranges. A coal is
classified by being assigned to one of these ranges.
Knowledge of the rank of a coal on the A.S.T.M.
system (strictly speaking, the rank range; each
A.S.T.M. class covers a range of rank) provides
guidance chiefly as to (a) the ability (or lack of it) to
form metallurical coke, and (b) the heating value.
Table 1 summarizes very approximately the values
of a number of important chemical and physical
properties for the major A.S.T.M. rank classes of
coals. No figures are given for carbonyl oxygen
because no reliable method for measuring it has been
established, and rigorous proof even of qualitative
identification is lacking. However, it is probable that
some is present, and the decrease with increasing rank
is rather slow, so that is may be the principal
functional group in anthracites. At any rate, it is the
various oxygen functional groups that can hold
cations by ion exchange or chelation. and their total
concentration decreases markedly with increasing
rank. Therefore, organically held cations must be
progressively released from a coal as its degree of
metamorphism (i.e., the extent of geological
alteration) increases; if released in this way, the
cation may be incorporated into a mineral, but in
many cases will be removed altogether in solution in
ground waters.
It will also be noticed that the aromatic character
of coal structure, in two distinct senses, increases
with metamorphism. Much of the nonaromatic
carbon appears to be present in hydroaromatic rings.
It should be noted that the contents of sulfur.
nitrogen, and mineral matter, and the nature of the
mineral matter, do not vary in any systematic manner
with rank. The form of combination of organic sulfur
and nitrogen is not known, but it is presumed to be
28
-------
PROVINCE
STATES
ACE
ASTMRANK
Subbll.
HVC
HVB
HVA
MV
LV
A
Ponna., Ohio,
Vo., W. Vo..
E. Kentucky,
Alabama, Tenr*.
Carboniferous*
(300m. years)
y
Interior
(o) East Coal Region:
Indiana, Illinois.
W. Kentucky '
(b) Wast Cool Region:
Okla., Missouri,
Kansas, Arkansas
Carboniferous
77
North Croat Plains
N. and S. Dakota,
Montana. N. E.
Wyoming
mostly early Tertiary
(100-SOm. yoars,
PI
tiJ
Rocky
Mountain
Many distinct basins
of different analogical
history in S. W. Wya.,
Colorado. Utah, Ne«
Monica, Arisana
Mostly Cr
some earl
(130-aOn..
1
"I
eievsl
s— —
._'_
H;
ertiory
Pacific
Washington,
Oregon,
California
Tertiary
(60- 15m.
yaars)
— .
— *
Cult
Parts ef Arkansas.
Tanas, Laulslaaa.
Mississippi,
W. Alabama
Tertiary
(70-JOrr, year.)
ED
Alaska
Alaska
Crotacaaws and
early Tertiary
(100-SOm. y.ors)
n
wi
E3
Principal Deposits
.'I Miner or Sporadic Occurrences
Figure 1. Distribution of coals in the United States.
-------
largely or entirely in heterocyclic aromatic rings. The
significance of reflectance will be dealt with later.
Coking behavior cannot be tolerated in some
gasification processes, particularly in fluidized bed
reactors. These processes must, therefore: be
restricted to low rank coals, or bituminous coals must
be pretreated to prevent coking; the only practicable
pretreatment available at present is mild oxidation, an
undesirable expedient because of the unavoidable loss
of reactivity and calorific value associated with it.
Moreover, part of the sulfur is released as SO2.
The thermal decomposition of coals sets in at
350-400 C, and a complex mixture of aromatic
hydrocarbons and heterocycles, phenols, water,
ammonia and hydrogen sulfide is released at these
and at higher temperatures. This condenses on
cooling to two liquid phases, an organic and an
aqueous phase. Since phenols are partly soluble in
water, the aqueous phase contains some of these
substances. The phenomena occur to some extent in
coal gasification; with some processes, emission of
phenol-containing waters is something that needs
control. The oxidative pretreatment of bituminous
coals to prevent caking is likely to have the same
problem.
The coals of the United States occur in a number of
distinct regions or provinces, each province having a
different geological history. For this reason, it is
useful to consider the coals of a province as a group,
rather than to base the discussion on a geologically
arbitrary division by State. Figure 1 summarizes the
principal facts about these provinces, including the
range of rank found in each. All of the coals of the
Interior province and many of those in the
Appalachian province were laid down in saline water
conditions, while those in the other provinces were
formed in fresh water conditions. The significance of
this is that saline waters contain relatively high
concentrations of sulfate ion, which is reduced by
bacterial action to H2S, with the result that much
sulfur is fixed in both pyritic and organic forms in
coals formed under marine influence. In addition, the
trace elements trapped in the coals will reflect, in
some sense, the complex distribution present in ocean
water. The large reserves of coals in the North Great
Plains and Rocky Mountain provinces contain
relatively less sulfur, often less than 1 percent. It is
worth noting that when the total sulfur content is
above about 1 percent, roughly equal amounts of
sulfur are present in pyritic and organic forms in a
majority of coals. On the other hand, in coals of low
total sulfur content, most of the sulfur (70-95
percent) is present in organic form.
Quantitatively, the most important minerals in the
majority of coals are clays (kaolinite, illite, chlorite,
montmonllonite, mixed layer montmonllonite-illites,
and sometimes muscovite). Feldspars are present in
some western coals. In addition quartz, pyrite, and
carbonate minerals (calcite dolomite, siderite, and
ankerite) are common. Some secondary
mineralization may occur in cleats, veins, and cracks
after the peat has been buried and coal formation
started; thus, some pyrite, carbonate minerals, and
possibly some quartz may be emplaced after burial.
Apart from this, the minerals originally deposited
with the peat suffer little alteration during
coalification.
As yet there- is little to show, in terms of
comprehensive analyses, as to whether the suites of
minerals found in the coals of the various provinces
are characteristic of or individual for each province.
However, one can infer some answer to the question
from the geological circumstances. Thus, the low rank
coals of the North Great Plains province have never
been deeply buried, and the over-burden on top of
the seams is often an unconsolidated sediment of
clays and sand. It is impossible to avoid mining some
of the roof material along with the coal, and the
unconsolidated sediment may yield a slow-settling
mud during attempts to remove it in a preparation
plant, particularly if, as is often the case, it contains
mixed layer clay minerals. Some of this material may
form part of the input to conversion processes.
The coals of the Rocky Mountain Province were
laid down as the mountains were arising. Much of the
rock forming the mountains is granite, and so the
trace elements and chemically altered minerals
released by the erosion of granite constituted the
main inorganic input to the coals forming in basins
among the foothills of the mountain range. Moreover,
since the coals formed in a large number of relatively
small basins, the distribution of minerals and trace
elements in each is likely to be relatively uniform.
In the Appalachian and Interior provinces, the coal
basins were flood plains of very large area. There were
mountains along the margin of the basin, and others
some way to the north of it, but they were not of the
massive and granitic character of the Rockies. Some
of the mineral grains were transported in water for
considerable distances, and so coarser particles would
have dropped out on the way. Therefore, the mineral
input to the peat swamps would have had a different
character from the input to the Rocky Mountain
coals, and it would be more variable in different parts
of the basins.
A number of publications in the literature (refs.
30
-------
1-18) give information on trace elements and minerals
in coals. Valuable though the data are, they provide
little insight into several important issues.
Much more study needs to be made of the relation
of the distribution of inorganic constituents in coals
to the geology of the basins in which the coals occur,
and to the geochemical principles involved. Empirical
correlations of the concentrations of some trace
elements with others need to be made, and. once
found, a geochemical explanation may emerge. Thus,
the author has noted that the concentrations of zinc
and lead tend to be relatively high in areas where high
pyrite contents are common; the solubility products
of the sulfides of these metals are particularly low. At
any rate, any generalizations that can be made about
the distribution of trace elements and minerals in a
seam or in the coals of a basin will reduce the
problems of assessing potential environmental
hazards.
Alpern and Morel (ref. 6) studied the lateral
variation of trace element distributions in a number
of coal seams in France, in the hope of using the
distributions as fingerprints in identifying the
stratigraphy of seams. However, they were forced to
conclude that this was not a valid approach for the
seams studied, because the lateral variations were
quite large. This is not unexpected in view of the
remarks made above about the trapping of trace
elements in peat swamps. It conveys the warning that
single values for the concentrations of trace elements
in coal seams may be far from representative.
When the opening of a new mine is being
considered, it is common practice in the coke-making
industry to take a series of drill cores on a grid
pattern in order to assess the coking properties of the
coal and their lateral variation. This localizes that part
of the areal extent of the seam that should be mined.
It will be prudent to make similar surveys when
selecting sites for coal conversion plants, and then the
opportunity could be taken to assess the lateral
variation of key trace element concentrations. In
some seams at least, the variations may be less than
indicated by the results of Alpern and Morel.
Another aspect of the distribution of trace
elements in coals is the nature of their associations.
Trace elements could be held in coals in one or more
of the following ways (subject, in some cases, to the
ionic charge and radius being suitable):
1. incorporated in the structure of clay
minerals or interstitially,
2. in the clays by ion exchange with acidic OH
groups,
3. by isomorphous substitution in carbonates
or pyrite,
4. as a minor mineral (e.g., sphalerite. ZnS,
detected in some Illinois coals),
5. as a carboxylate salt in lignites and in
subbituminous coals,
6. as a chelated organometallic complex in a
coal of any rank, although as already noted
the extent of such complex ing will decrease
with increasing rank.
There is very little evidence to show the extent to
which any trace element is held in each of these
forms. Yet the product stream into which any trace
element will go, the chemical form it will be in, and
the ease with which it may be leached from the solid
waste must surely depend at least partly on its
association in the original coal.
These aspects of the fate of trace elements will also
depend of course on the nature of the conversion
process. Thus in catalytic liquefaction processes clays,
quartz and carbonates will be little changed at the
temperatures used (about 400°C), nor will their
association with trace elements be much altered. It
has been shown recently in the author's laboratory
that pyrite is reduced under liquefaction conditions
to the nonstoichiometric mineral pyrrhotlte. Fei-xS,
where x = 0-0.2. Other sulfides present, if any, might
be reduced to the metal (e.g., Pb and Zn), but there is
no evidence. Elements held by the organic matter in
carboxylate or chelated form will be released,
possibly in highly reactive form.
It is already known that titanium, which is a minor
rather than a trace element in many coals, tends to
accumulate on the surfaces of liquefaction catalysts
and to deactivate them. Other elements, including
boron, may accumulate in a similar way, and it seems
likely, for kinetic reasons, that they were originally
present in soluble organometallic form rather than in
mineral form. Some potentially toxic elements could
be scavenged in this way and tightly held on spent
catalyst.
Gasification, whether to low or high Btu gas, is
carried out at much higher temperatures
(900-I,000°C), and profound alterations of all mineral
species in coals are to be expected. All carbonates,
clay minerals, and pyrite will decompose and the
products of decomposition will react with each other
in producing new crystal phases; this will be
particularly so in the few processes in which slagging
occurs. Where oxidative pretreatment is practiced
with bituminous coals, sulfides will be converted to
oxides, or possibly to sulfates. Organically held
elements will be released in various forms. Several
elements will be partially or completely vaporized
31
-------
(e.g., Se, Te, F, Hg, Ga, Ge). In these complex
circumstances, predictions of the fate of trace
elements cannot be made, and careful experimental
study is needed. The information on the behavior of
coal minerals in combustion processes, assembled in
the excellent review by Watt (ref. 1), should provide
some useful guidance to the behavior of inorganic
material in gasification processes.
It was noted at the beginning of this paper that
debris of the various organs of trees can be
distinguished not only in peats but also after
coalification. Furthermore, various processes in peats
generate new materials that do not occur as such in
living plants, and these materials also may be
distinguishable in coals. The various kinds of bodies
found in coals are termed "macerals". The most
abundant maceral in most coals is vitrinite, which
represents woody material that has been somewhat
altered biochemically and then coal if fed. It is vitrinite
that is responsible for the coking behavior of
bituminous coals. Also, vitrinite shows a more
consistent trend of properties with rank. This is why
reflectance is a valuable parameter characterizing the
rank of coals; using microscopic techniques, the mean
reflectance of the vitrinitic maceral in sample can be
measured without interference from other macerals.
To measure any other property of the vitrinite, a
physical separation from other macerals would have
to be carried out first. In addition, the differing
reflectances of the macerals are used in making a
petrographic analysis of a coal sample.
In all, ten macerals are distinguished in coals. Of
these, the quantitatively most important, apart from
vitrinite, are sporinite (from the waxy coating of
spores and pollen), fusinite (a kind of charcoal,
thought to have been generated in forest fires), and
micrinite (of unknown origin, highly aromatic and
inert in the coking process). The few studies made so
far (refs. 17,18) indicate that different suites of
minerals tend to be associated with the different
macerals in any one coal. The various macerals
contain different concentrations of functional groups
(refs. 20-22), and these may well have different
spatial distributions in the organic structures. The
ability to chelate trace elements or otherwise to form
oranometallic complexes will therefore be different
for the different macerals.
The various organic and mineral phases in coals
have different hardnesses and specific gravities. In the
process known as coal preparation, coals are crushed,
sized, and subjected to float-and-sink separations. By
no means all coal is subjected to preparation before
use; when it is subjected to preparation, the objective
is primarily to reduce the pyrite content, though the
contents of other minerals are reduced at the same
time. How effective the process is will depend upon,
among other things, the particle size distribution of
the minerals and the mineral-maceral associations.
Provided the characteristics of the coal are well
understood, the preparation process could be so
planned as to maximize the efficiency of mineral
matter removal. But in addition, some degree of
management of feedstock composition can be
achieved with regard to the organic components also.
Since these differ in their susceptibility to conversion
processes, sophisticated use of preparation procedures
may well be a desirable prelude to feeding coals to
conversion plants.
The important point for present purposes is that
any preparation of the coal before use will reduce the
concentrations of some or all of the trace elements in
the feedstock. There is a possibility, which should be
checked by experiment, that some of the more toxic
elements (e.g., Pb, Cd) are present as sulfides and
closely associated with pyrite. Pyrite is the mineral of
highest specific gravity in coals, so that it tends to be
removed preferentially in preparation processes. On
the hypothesis above, some toxic elements would be
preferentially removed with the pyrite.
In conclusion, some general points about the
utilization of the products of coal conversion
processes should be made. It is perhaps not widely
appreciated that the presence of mineral matter in the
coal fired to a utility power station represents a
considerable cost to the utility. Ash accumulates on
steam and superheater tubes, leading to poorer heat
transfer, to corrosion, and to periodical shutdowns
for removal. Electrostatic precipitators for removal of
fly ash are expensive in capital and operating costs;
stack gas cleaning will also be expensive, if a
satisfactory process is proved. Quite apart from
environmental considerations, therefore, the utility
industry has a substantial economic motive in desiring
clean fuels.
For various technical reasons the industry is
increasingly turning to gas turbines for intermediate
and peak load generation. These must have extremely
clean fuels to avoid damage to the turbine blades. The
low energy efficiency of the production of high -Btu
gas from coal argues against using it for power
generation; if any gas from coal is used, it will be
low-Btu gas. A liquid fuel from coal would be most
desirable, because oil can be stockpiled for
intermittent use, and the conversion process needs
less water.
Centrifugation of the oil from catalytic liquefaction
32
-------
is easy and reduces the content of inorganic material
to about 0.1 percent. This is adequate for using the
oil as a substitute for a petroleum product or natural
gas in package boilers in industry and for industrial
process heating. This kind of use accounts for
somewhat more fuel consumption in the United
States than electricity generation. For firing in gas
turbines, the oil will have to be filtered to reduce
ash-forming constitutents to around 0.01 percent.
and certain elements (e.g., Na, K, V) must be below 1
ppm. This is less easy, but can probably be done. If it
is done, then there is no need to worry about toxic
emissions when the fuel is burnt.
The four principal conclusions of this paper are:
1. From the environmental point of view, it
is the conversion processes themselves that require
consideration, rather than subsequent use of the fuels
produced.
2. The conversion processes require study in
some detail, to determine what is present in all of the
product and byproduct streams and what are the
possibilities of undesirable elements escaping when
waste products are disposed of.
3. The inorganic constituents in coals need
much more detailed and sophisticated study than
they have received in the past.
4. The effect of coal preparation processes
on the contents of toxic elements needs to be
determined.
REFERENCES
1. J. D. Watt, 'The Physical and Chemical Behavior
of the Mineral Matter in Coal Under the
Conditions Met in Combustion Plant: Part I. The
Occurrence. Origin. Identity. Distribution and
Estimation of the Mineral Species in British
Coals; Part II, Thermal Decomposition and
Interaction of Minerals in Coal Under Conditions
Met in Combustion Plant." Special Report,
British Coal Utilisation Res. Assoc., 1968.
2. J. B. Nelson. 'The Mineral Matter of Coals."
Monthly Bull., British Coal Utilisation Res.
Assoc,Mo\. 17(1953), p. 41.
3. J. V. O'Gorman, and P. L. Walker, "Studies of
Mineral Matter and Trace Elements in North
American Coals." Research and Development
Report No. 61, Interim Report No. 2, to Office
of Coal Research, U.S. Department of the
Interior, 1971.
4. R. R. Ruch, H. J. Gluskoter, and N. F. Shimp,
"Occurrence and Distribution of Potentially
Volatile Trace Elements in Coal," Environmental
Notes, No. 61. Illinois State Geological Survey,
1973.
5. E. M. Magee, H. J. Hall, and G. M. Varga,
"Potential Pollutants in Fossil Fuels." Report
EPA-R2-73-249 to Environmental Protection
Agency, 1973.
6. S. Alpern and P. Morel, "Examen, Dansle Cadre
du Bassin Houiller Lorrain, des Possibility's
Stratigraphiques de la Gdchimie," Ann. Soc.
Geologique du Nord. Vol. 88 (1968), p. 185.
7. D. J. Swame. "Inorganic Constituents in
Australian Coals," Mitteilungen der
Naturforschenden Gesellschaft in Bern. Vol. 24
(1967), p. 49.
8. A. Szalay and Marie Szila'gyi, "Accumulation of
Microelements in Peat Humic Acids and Coal,"
Advances in Organic Geochemistry 1968, eds. P.
A. Schenk and I. Havenaar. Pergamon Press,
1969, p. 567.
9. P. Zubovic, "Physico-Chemical Properties of
Certain Minor Elements as Controlling Factors in
Their Distribution in Coal," m Coal Science,
Advances in Chemistry Series, No. 55, American
Chemical Society, 1966, p. 221.
10. P. Zubovic, "Minor Element Distribution m Coal
Samples of the Interior Coal Province," in Coal
Science, Advances in Chemistry Series, No. 55,
American Chemical Society, 1966, p. 232.
11. D. J. Von Lehmden, R. H. Jungers, and R. E.
Lee, "Evaluation of Analytical Techniques for
the Determination of Trace Elements in Coal,"
Abstracts With Programs, 1972 Annual Meetings,
Geol. Soc. Amer., Vol. 4. No. 7, p. 698.
12. J. R. Jones and E. N. Pollock, 'The
Determination of Trace Elements in Coal,"
Abstracts With Programs, 1972 Annual Meetings,
Geol. Soc. Amer., Vol. 4. No. 7, p. 556.
13. H. D. Schultz and D. A. Nelson, "Molecular
Structural Characterization of Toxic Elements m
Coal Dust by ESC A and NOR." Abstracts With
Programs, 1972 Annual Meeting, Geol. Soc.
Amer., Vol. 4, No. 7, p. 657.
14. D. J. Swaine, 'Trace Elements in Australian
Coals," Abstracts With Programs, 1972 Annual
Meeting, Geol. Soc. Amer., Vol. 4, No. 7. p. 682.
15. V. E. Swanson and J. D. Vine, "Composition of
Coal, Southwestern United States," Abstracts
With Programs, 1972 Annual Meeting, Geol. Soc.
Amer., 4 (7), p. 683.
16. B. Lakatos. J. Meisal, G. Mady, P. Vinkley, and S.
Sipos, "Physical and Chemical Properties of Peat
Humic Acids and Their Metal Complexes,"
33
-------
Fourth International Peat Congress, Otaniemi,
Finland, Vol.4 0972), p. 341.
17. R. R. Dutcher, E. White, and W. Spackman, "Ash
Distribution in Coal Components - Use of the
Electron Probe," Proceedings 22nd Iron-making
Conference, Iron and Steel Division, AIME, Vol.
22(1963), p. 463.
18. Michelle Smyth, "Association of Minerals with
Macerals and Microlithotypes in Some Australian
Coals," Tech. Communication 48, Division of
Coal Research, Commonwealth Scientific and
Industrial Research Organization, Chatswood,
N.S.W., Australia, 1966.
19. S. Troutman, G. G. Johnson, Jr., E. W. White,
and J. Lebiedzik, "Automated Quantitative SEM
Characterization of Complex Paniculate
Samples," American Laboratory, Vol. 6 (1974),
p. 31.
20. D. W. Van Krevelen, Coal. Elsevier Publishing
Co., 1961.
21. P. H. Given, M. E. Peover, and W. F. Wyss,
"Chemical Properties of Coal Macerals I -
Exinites." Fuel. London, Vol. 39 (1960). p. 323.
22. P. H. Given, M. E. Peover, and W. F. Wyss,
"Chemical Properties of Coal Macerals II - Inert
Components and a Further Examination of
Exinites." Fuel. London, Vol. 44 (1965), p. 425.
BIBLIOGRAPHY
Useful general accounts of the chemistry,
petrography, and geochemistry of coals will be found
in:
D. W. van Krevelen, Coal, Elsevier, 1961.
W. Francis, Coal (2nd ed.), Arnold, chapters 11 and
12, 1961.
Coal Science, Advances in Chemistry Series, No.
55, American Chemical Society, 1966.
D. G. Murchison and T. W. Westoll (eds.). Coal and
Coal-Bearing Strata. Oliver and Boyd, 1968.
34
-------
TRACE ELEMENTS AND POTENTIAL POLLUTANT EFFECTS
IN FOSSIL FUELS*
H. J. Hall, G. M. Varga, and E. M. Mageet
Abstract
Coal, petroleum, and shale oil are minerals whose
impurities are commonly the same as the beds in
which they are found. Relationships between
impurity content and geographical location are well
known for sulfur, but much less so for other
elements. They are known in petroleum production
only for sulfur, nitrogen, nickel, and vanadium. The
characteristic salt water inclusions produced with
crude oils are removed before further use, and they
are not considered (like the minerals in coal) as a part
of the product.
The amounts of trace elements found in coal are,
for the most part, close to their average crustal
abundance, and are not toxic at this level. Certain
elements may be concentrated in coals at the top,
bottom, or edges of a bed or basin (Ge, Be, Ga, B).
Others may be enriched in samples close to mineral
ore deposits (Mo, Sn, Zn, Pb, Hg, U). The potential
danger from toxic elements such as Hg in coal has
often been overstated by "averaging" results from
mineral specimens collected in the search for ores.
These conclusions are based on a compendium of the
literature values for each element, by using the ranges
and averages for each coal-producing region, after
excluding atypical samples.
The volatile elements which are commonly
considered most hazardous include F, As, Se. Cd, Pb,
and Hg, on which the analytical data available have
been spotty and unreliable. Improved methods for
these analyses, which are now being developed, must
be applied to both old and new samples.
Geographical relationships of fuel source to quality
have been useful in the selection of coals or crude oils
for sulfur, ash content, and for many other
properties. Any fuel specification limits supply and
raises cost, and the addition of new specifications on
trace elements could have important economic effects
'This is a report of information obtained in a critical
survey and analysis of the literature on trace elements as
potential pollutants in fossil fuel conversion/treatment
processes, under EPA Contract No. 68-02-0629. For details
and bibliography, see contract report EPA R2-73-249,
PB-225,039, June, 1973.
tThe authors are with the Government Research
Laboratory of Exxon Research and Engineering Company,
Linden, New Jersey.
on cost and OR availability. This paper examines some
of the major variables in the amounts of trace
elements in fossil fuels, and the extent to which
geographical correlations may apply.
The literature is full of data on trace elements in
coal or oil. but they are hard to use. Fuels are subject
to all of the usual problems in sampling, and they
have special ones of their own. Analyses for zinc in
oil are useless if the sample is taken in a soldered can,
and any unusual analysis for iron in coal is suspect.
These problems of sample handling are typical, not
rare. The problem continues from the field into the
laboratory. There are classic examples of misleading
results on mercury in coals where the whole
laboratory was contaminated, and there remains the
more recent discovery that laboratories in a
downtown urban environment cannot get a good
analysis for trace amounts of lead. The problem is not
so serious in ordinary analyses down to about 0.1 to
0.01 percent, but the very words "trace element"
refer to a situation where trace amounts of
contamination are troublesome. A large number of
elements in coal are present in trace amounts of
about 1-1000 ppm. Cooperative tests in the round
robin series conducted by the National Bureau of
Standards have shown poor agreement between
laboratories in the analyses of coals in the range of
1-50 ppm, and any analysis within this range requires
rigorous calibration procedures, if the results are to
be believed.
A more troublesome problem in the evaluation of
literature data, because it is frequently ignored, is the
basis for selection of the original sample. It is obvious
that contamination is a problem for sodium chloride
in crude oil, depending on how much salt water is left
in the sample, or for adventitious clay minerals left in
a coal. What is not so obvious is the effect that
proximity to a zinc or tin deposit has on the amount
of zinc or tin there is in coal.
Almost half of the coal produced is consumed as
mined, without preliminary processing. The same is
not true for petroleum, which is almost never burned
as total crude. In both cases, any initial processing by
cleaning or by fractionation usually produces a waste
or bottoms fraction which is enriched m undesirable
components, and this waste commonly creates
pollution problems under present methods of
handling or disposal. There problems are known and
35
-------
are fairly well defined for sulfur, but there is no
comparable body of data for the pollution potentials
due to other elements. A larger body of data is
available for trace elements in coal. For both coal and
petroleum, however, the level of trace elements
present is so low that methods of sample selection
and sample handling, prior to analysis, can and do
present major complications in the interpretation of
results.
Coal is a mineral resource, and most of the
literature on coal analysis reflects its use as a guide to
other minerals. In the first studies of uranium in coal,
for example, the typical coal containing less than 10
ppm of the element was dismissed as of no interest,
and data were reported for only the atypical
exceptions. In later studies, a screening procedure was
applied to select for trace metal analysis those
samples which gave the highest percentage on ash of
germanium, which was needed for electronics. This
approach was explored during the 1950's and 60's in
comprehensive reviews for a few elements such as
uranium, beryllium, germanium, and gallium in the
United States, and for mercury in the USSR.
Concentrations of interest, from this point of view,
cut off at about 10 ppm on ash or 1 ppm on coal, and
few of the older analyses go below this level. An
effort is made in this study to reduce this bias toward
unusual specimens, and to draw correlations based on
corrected data.
Evaluation of Data
Continuing field surveys of U.S. coals have been
made by three major government laboratories, using
the best methods available to them. These surveys
were made for three different purposes, and they
differ more in the method of sampling than in the
procedures for analysis. The rest of the literature on
trace elements in coal is concerned almost entirely
with new methods of analysis, tested or
intercompared on a single sample or a few known
samples. Except for missing data on single elements,
these have relatively little to contribute to an overall
review. The three basic sets of data and samples are
(1) Surveys of commercial coals - U.S. Bureau of
Mines (USBM) (delivered samples),
(2) Mineral source surveys — U.S. Geological Survey
(USGS) (column samples).
(3) Specific element studies — Atomic Energy
Commission (AEC) (TVA/Oak Ridge; USGS,
specimens).
The USGS data, reported by Zubovic and
Stadnichenko, are found to come closest to the
purposes of the present program: to determine the
composition of typical U.S. coals by regions, and the
extent to which the selection of coals by geographic
location can be expected to affect their composition
in trace elements. The USBM has selected samples to
cover current commercial production, and most of its
data are reported on the basis of ash. The number of
samples selected in the most comprehensive survey by
the USBM in 1969 is shown by States and regions in
figure 1, with superimposed numbers showing total
production figures the same year for each region, in
thousands of tons per day. This choice of samples is
based on production rather than reserves and no
distinction is made between cleaned and raw coals,
which can make a significant difference in trace
metals content.
The analyses made in these field surveys did not
regularly include data on mercury, cadmium, arsenic,
selenium, or fluorine. These are all volatile elements
and are considered hazardous. They are not readily
detected by emission spectroscopy, and better
methods for their analysis were required.
Trace elements are usually defined as those
elements that are present in the earth's crust to the
extent of 0.1 percent (1,000 ppm) or less. Nearly all
trace elements show an enrichment in coal ash
relative to their crustal abundance. The USBM data
on coal ash are summarized on this basis in figure 2.
Boron picked up by plants from the underlying soil is
enriched on the total coal basis (syngenetic), and
germanium is equally enriched in some coals by
exchange reactions during coalification (epigenetic).
Manganese is low even on the ash basis. However, for
most trace elements in coal, crustal abundance comes
between the amount in coal and the amount in ash.
Potent/a/ Pollutants
Public concern over minor or trace elements in coal
as a potential source of air pollution was limited
almost entirely to sulfur until recent years, after
1966. Data from USBM on sulfur in U.S. coals by
States are shown in figure 3. These data show strong
differences by geographical area, and they were
discussed in detail in Congress when drafting the
Clean Air Act of 1967. The initial concern and the
first official actions were directed toward smoke
control, to limit the production of soot, fly ash, and
sulfurous emissions. The production of fly ash or
cinders is linked with total ash content and
composition, but it is scarcely affected by which
trace elements are present in the ash.
36
-------
LEGEND
Anthracite (anthracite
and semtanthracite)
Low-volatile bituminous
Medium- volatile and
high-volatile bituminous
Subbi luminous
t!:;!i:!;-l Lignite
t-247 Samples
Scale.miles
Figure 1. Map Showing Number of Samples From Each State.
oior
06-
"
o?-;
§
1
i
E23 Eoirem Provinct
GZ2 Interior Provtnc*
CD WMItrn stotn
•• Cnntol <*undonct
1
1
Co Cr
Go
Ll Mn Mo Mi
Sn
In It
Figure 2. Average Trace Element Content in Ash of Coal From Three
Areas Compared With Crustal Abundance.
37
-------
West Virginia..
Pennsylvania. . .
Kentucky..,..
Illinoi*.......
Ohio
Virginia
Indiana
Alabama
Tennessee
Other States. _
.^vr;x^///x'////,^;/r|^^^^^^^^^^^^^^^^^
^JHjjJjf]jf^jJ^^^jjljj^^^^
''.'.- ;.•••".'".•• Vj ^$^SS§§?$i&^
' /{ ^- ^
-------
unreliable. The second category includes trace
elements analyzed in extensive field reviews and
reported on a coat basis by Peter Zubovic and
coworkers at the USGS. These were selected for its
studies of the chemistry and geology of coals, and
determined by a standard procedure for emission
spectroscopy. Titanium, present regularly in amounts
greater than 0.1 percent was not considered as a trace
element in this review. The third category includes
elements for which data are available only on an ash
basis, from USBM studies of commercial coals.
Methods of Correlation
Two factors have hampered efforts to draw useful
correlations between the location of coals and their
content of specific trace elements: the tendency to
use averaged data and the fact that the basis of
sampling for analysis has shifted during the course of
major field surveys. The problem is particularly
serious when, in the same program, samples are
intermixed which are "of interest" for opposite
reasons: because they are typical on the one hand, or
because they are exceptional on the other. The
analyst in this case finds no basis to discard a high
result which he finds analytically correct, even
though it greatly affects his average. This problem
was recognized by the Geological Survey, for
example, in the analyses reported for zinc in Illinois
and elsewhere. This can be significant for pollution
controls, since the expected analysis for delivered
coals might be reduced to the mode by excluding a
few samples which are easy to identify. The fact that
such extremes do or do not exist and the producing
areas in which they are found may be of definite
interest in considering these trace elements as
potential pollutants.
The unusual data should somehow be put into
perspective so they can be used and not discarded,
since the analyses involved are not in question. The
literature was reviewed with these problems in mind.
Three concepts are proposed as working tools to
make the most out of the present literature, with a
minimum of recalculations:
(1) A "variance" ratio is given for each element,
which is the ratio of the highest to lowest average of
analyses for areas or basins within the region. It is
applied here to groups of about three States, as a
measure of the extent to which selection of coal
source can he expected to make a difference in the
concentration of a given element. As shown in table
2, this variance is low for most elements, on the order
of 2 to 3. It is 8 for sulfur and 4 or above for only 7
of the 18 elements for which sufficient data are
available to report.
(2) Ranges for the USGS analysis of the coal
beds within each region are selected which include 90
percent or more of the values reported, for columnar
samples, up to a cutoff point above which higher
values appear to be exceptional. The problem is that a
sample cut from the mine face near the edge of a bed
has a variable amount of bone, shale, or other
minerals depending on how the sample is chosen. A
columnar sample is defined here as one for which at
least 75 percent of the total depth of the coal bed
was included in the sample analyzed. This makes a
significant difference in section A (1961) and B
(1964) of the four-part USGS survey. At that time,
the highest values reported were frequently not
samples of straight coal but blocks where a major part
of the sample was rejected as minerals before analysis.
The 90+percent range is taken from the data for beds
within the region, after casting out these
nonrepresentative values.
(3) The next step involves inspection to find an
envelope within which all or at least 90 percent of the
individual analyses represent a continuous
distribution of values. The highest values reported
were then considered individually, first to see that
they represent a columnar sample at least 75 percent
analyzed, and then to determine the interval between
this value and all lower values within the envelope.
This inspection characterized many instances where a
few columnar samples, up to about 5 percent, had
extreme values at least 25 to 100 percent or more
above the rest of the 90+percent envelope. The
significance of the extremes can then be examined
separately, both in terms of their frequency and their
magnitude as compared to average values or the top
of the 90+percent range. Where there are no
extremes, the 90+percent envelope includes all
samples. Detailed data on this are summarized in
figures 4.1 to 4.7.
When the elements are listed in the order of
variance and magnitude of extremes, in table 2,
several useful correlations appear. The elements with
high variance whose extremes are no more than twice
the top of their 90+percent range are sulfur,
germanium, boron, beryllium, and gallium. Except
for sulfur, which is both strongly organic and
inorganic, these are all at the top of the USGS list of
organic affinity. This means that on coal cleaning
they tend to be associated with the coal fraction, and
not with the waste. They are also elements in which
coal is greatly enriched, to the extent that it is
39
-------
1.0
0.1
x
<
0
ft 0.01
Ui
Q.
t-
X
0.001
Onnni
100
10
_i
o
u
g
z
0
-j 1.0
2
DE
Q.
OS
0.1
n m
JL
...
.
U-
.
r
l
•
8
*
A
A
.
W
)e
;v\
e
•
-W
u
M
F
'
Ht
-J
1
[
I
P
ifiS*
i
r*1
A
f
5
-i-
(
>e
•\n
1
0
0
-0-
u
0
0
TT
f).
^
1
...
'
IE
^
0
„
0
I
E
A
..
A
-
1
F
...
P
Hr
Pb
W
b
H
vV
w
w
N
W
—Figure 4.1 -
Figure 4a. TRACE ELEMENTS IN U.S. COALS
40
-------
l.Or
Cr
Co
Ni
Figure 4.3:
o.i
z
1^
UJ
u 0.
PC
UJ
Q-
O.OOlt
I—
—
— J
A
£
1 1-1
J fh
UE
A
yySR
u,
rri
LH-
A IVV
-*
*•
<
>w
L
L.
T
1
N
It
r~r
i
A
|i
^
S
L-,
w
r—
4-
3=
" iTL
Sw
•^
W
• J
|
i
0.0001^-
Cr Co
Ni
Cu
Figure 4.4 2
100:
o
10:
4*-
A" 1¥11
u-
•u
4-
- T—
i
1.0;
u
IW
O.l1-
Figure 4b. TRACE ELEMENTS IN U.S. COALS
41
-------
Zn
Ga
Ge
La
l.U
0.1
t/J
<
0
t-
S 0.01
Ul
Q.
u
y
5
0.001
n nnni
-1—
A
—
|r
1
-i
w
_
•w
A
IE
W
N
A--
it
\A
W
iff
^
A
if
€4W
I
N
^^^
A
lr
IL
ii
w
N
rr~Li
A^im
n
^
^H
w
Figurp 4.5
1000
100
_l
<
z
0
_i
-J 10
oe
w
a.
in
2
1.0
.1
.
^L
•n
...
. - .
•
Ik
Z
- -
...
L=^
•
1£
n
n
*
_
iT
iii
— 1
»
A
-
•
IE
ia
f.
A
W
— |
•
H
~
Ml
A
--
_
•
F
Ge
:;.
uU,
...
•
ird
•
A
N
IIw
—
•
II-
flo
t
IAW
IV
— 1
•
N
•PI
*
A
IF
Y
&
-S-
~^
n?
i
— i
•
t<
•
T
•~
•
IE
L
A
•^
-A
~
*
IY
a
f-
— ^
•
U
- Figure
r-^
~-
_H | 1 —
i,
N
- w
4/5 -
.b -
Figure 4c. TRACE ELEMENTS IN U.S. COALS
42
-------
Ba Yb Bl
0.0001
Figure 4d. TRACE ELEMENTS IN U.S. COALS
recognized for most of them as a significant mineral
source.
The other elements which show a variance above 4
are zinc, molybdenum, and tin. For these, the
extremes reported are from 5 to 20 times the top of
the 90+percent range. Zinc and tin are at the bottom
of the organic affinity list, and for them the
occurrence of coals of high metal content is taken as
a direct indication that ore beds are nearby. The
variance of (3) reported for tin is placed in
parenthesis because it represents a recalculation of
the USGS data for one area in the Appalachian
region. This is given a false low average of 0.1 in the
original report by including a value of zero for 15 of
the 17 samples analyzed for the region, in which the
element was not detected. The USBM data in this
area indicate no such differences between the tin
content of coals in this area and in other parts of the
region, so this value was ignored in calculating the
variance.
Variance relates to geography, and extremes relate
to mineral enrichment. Molybdenum is another case
where variance alone might be misleading. Here the
average for the southern Appalachian area, Alabama,
is raised from 3.9 to 5.8 by a single extreme value of
42 for one bed out of the 20 included. Without this
one extreme, the variance reported would be under 3.
The value appears valid but marginal (74 percent of
bed analyzed), and the fact that it is so high may
correlate directly with the AEC observation that Mo
is the only element whose occurrence in coal in high
amounts they could link with the occurrence of high
amounts of uranium.
Mercury and lead, for which no data are reported in
the USGS field survey, have a variance of about 2 to
3, using other data. The ratio of extremes to average
values for these two elements can be given any high
value desired (up to 50-100) depending on how close
one chooses to come to an ore bed in selecting the
coal. None of the remaining elements which show a
variance of 3 or less has a ratio of extremes to the top
of the 90+percent range higher than 2, except
vanadium at 3. This vanadium ratio directs attention
to one mine in Kentucky, which has a high Ni and V
content.
The correlation concepts of variance and extremes
were developed element by element for the 5 major
producing regions: Appalachian (A), Interior-Eastern
(IE), Interior-Western (IW), Western (W), and
Northern Plains (N). The data summarized in table 3
are presented in figures 4.1 to 4.7 as bar charts for
each element, by regions, following the listing of
43
-------
elements in table 1. In some cases where the
Southwest Energy Study appears to give a broader
data base than the W ranges, based on more samples,
SW data have been reported instead of W. The USBM
data for ppm on ash are shown at the top, and the
USGS data on a coal basis are at the bottom.
Thousandths of a percent on ash correspond to ppm
on coal, if the coal contains 10 percent of ash. This is
a reasonable average approximation, and it fills in
many holes in the data without a laborious
recalculation, which would still not give directly
comparable results.
The bar graphs shown for coal are the 90+percent
ranges, the dashed lines (—) are the extremes listed,
and the regional average (°) is for the total region as
given by USGS. This average is usually near the
middle of the bar. but it moves toward the top of the
bar or may exceed it when there are many extremes,
as for copper or zinc. Ranges which start below the
limit of detection are shown by a broken bar line
below 0.1 ppm. Shorter dashed lines (--) represent
values outside the 90+percent range which were
included in the USGS average, but are excluded here
because they were for beds less than 75 percent
analyzed. High specimen sample values for mercury
reported in the literature are indicated by an o, and A
shows the high values for weathered samples, not
included in the averages.
The bar graphs for most elements, thus adjusted, lie
within the range of 1 to 50 ppm, and most are close
to 5-10 ppm on coal. The only elements significantly
higher than this are boron and fluorine, in the range
from 10 to 200 ppm. Beryllium is lower in all regions
by an order of magnitude, at about 0.1 to 5 ppm, and
Hg by two corders of magnitude, at about 0.01 to 0.5
ppm on coal.
Mercury: A verages and Extremes
The literature bias toward samples of mineral
interest must be discounted heavily in certain cases. A
specific example is mercury, which has received major
attention in the past 2 years as a hazardous air
pollutant. Concerted efforts have been made to
supply missing data on its analysis in fossil fuels. Part
of this concern is based on the widely quoted
statement that the amount of mercury released to the
environment by the burning of coal is comparable to
that emitted as waste from all industrial processes.
This statement is taken from a 1971 article in which
11 of 36 specimens analyzed contained over 1 ppm of
Hg on coal, but 8 of the 11 were samples from the
same three counties. The author of this article states
Table 2. Variances and extremes
in areas3
Variance Organic
between affin- Extreme
Element areasb ityc ratiod
Sulfur
Germanium
Boron
Beryl 1 i urn
Gallium
Molybdenum
Tin
Zinc
Lead
Mercury
Vanadium
Nickel
Chromium
Cobalt
Yttrium
Copper
Lanthanum
8
>10
6
5
4
4
>(3)
>5
3
3
2
3
2
2
3
2
3
1
3
2
3
6
8
10
3
4
4
5
5
7
9
2
2
2
2
5
5
20
>10
>10
3
2
2 (3je
2 (5)
2 (10)
2 (3)
2 (10)
aFrom USGS bulletin 1117, ex-
cept for S, Pb, and Hg.
Approximate ratio between
averages for highest and lowest
areas, as published (see PB-225 039,
table XI).
GNumbers assigned to USGS order
of affinity: Ge>Be>(Ga,Ti,B,V)
>(Ni,Cr)>(Co,Y)>Mo>Cu>Sn>La>Zn
Approximate ratio between ex-
treme and top of the range of 90+
percent envelope, for columnar beds
analyzed.
Discounted extremes in paren-
theses show exaggerated effect of
two weathered coals from Arkansas
with 41.7 and 47.3 percent ash, not
included in area averages.
44
-------
that, 'The analyses were performed on a relatively
small number of samples that are not representative,"
but this qualification has been completely lost in
subsequent references. He finds that his method of
analysis is confirmed by agreement between his
average of 0.19 ppm for coals from Illinois (5
samples) and the average value of 0.18 ppm reported
by the Illinois State Geological Survey (53 samples).
He then recognized that his sampling of 36 U.S. coals
gives an average which is too high (3.3 ppm), but
apparently gives his extreme values equal weight with
the samples determined elsewhere and chooses a
"conservative estimate" of 1 ppm as typical of all
coal produced. On this basis, he calculates 3,000 tons
of mercury per year are released by coal combustion,
worldwide, and finds this quantity comparable to the
10,000 tons per year consumed industrially, most of
which is eventually discarded to waste. Thus, this is
the origin of the statement so widely quoted. The
more representative basis of 0.18 ppm as typical for
coals would give 540 tons of mercury from
combustion stacks as against 10,000, which is less
than "comparable" by an order of magnitude.
Comprehensive studies of U.S. coals during 1971
and 1972 have failed to find a single commercial
supply which runs as high as 1 ppm. The newer
methods of analysis have a limit of detection of about
0.01 ppm. This is approximately the same by neutron
activation and by ftameless atomic absorption, using a
double gold amalgamation procedure to remove
interferences without loss of mercury. Data which
permit a good survey of geographical distribution by
producing region are presented in table 3, and a
proper U.S. average might be close to 0.15 ppm.
The reason for this confusion lies not in the first
author's method of analysis, which is reliable, but in
the selection of samples which are essentially museum
specimens, and in allowing them to be included in a
result reported as "average." The present study fully
confirms on a smaller scale the general observation
that the mercury content in most coals is quite low,
less than 0.2 ppm, and that occasional extremes as
high as 1 ppm are limited to a few specific locations.
Even where these extremes occur, the average Hg
content for the mine is usually far below the extreme,
and is not necessarily much different from the
average for other coals.
Problems in Toxicity
The problem of identifying what is toxic is, in
many cases, an open question. Biological evolution is
a rigorous adaptation of the organism to its
environment, and a large number of trace elements
are essential to life as we know it. The base value for
toxicity is not zero, but close to "crustal abundance,"
and too little of these elements is as toxic as too
much. It should be recognized, however, that this is
as true for common foods as it is for trace elements.
The body cannot tolerate sodium chloride or water at
10 times its normal intake. The question of toxicity is
tied closely to actual amounts, and the tolerance
range between food and poison is not wide. Diet
deficiencies due to overuse of the soil are well known
for many elements, and the addition of coal ash to
the environment may be beneficial to plants or to
people whose food and living space have been
deprived of contact with virgin soil.
A useful overview of trace elements in rocks, soils,
plants, and humans and the known facts of their
toxicity has been assembled by Lisk. His averages are
shown in table 4 together with ranges for ppm in coal
taken from the present review. This comparison
makes even more striking the number of trace
elements in coal which show about the same
concentration, in the range of 1 to 50 ppm. The
amounts of different trace elements in coal are
apparently more uniform than they are in rocks or
soil. The human body is relatively more rich in lead,
mercury, and cadmium than in coal, and the same
applies to barium, strontium, and lanthanum.
Coalification is a geologic averaging process, and the
human body has different selection principles, which
depend at least partly on atomic weight. Enrichment
in plants follows still a different set of principles. For
reasons which are not clear, plants seem to selectively
reject (enrichment below 0.03) two groups of
elements having adjacent atomic numbers: scandium.
titanium, vanadium, chromium (21 to 24), antimony,
and tellurium (51, 52). Elements which plants do
select include cadmium, lead, silicon, selenium, and
lithium.
Elements which are considered toxic have a
tendency toward biologic methylation. This is true
for arsenic, mercury, and selenium. This is partly a
matter of valence state. The difference between
calomel and corrosive sublimate is well known, and
toxicity depends heavily on chemical form for
beryllium or fluorine. Many toxic elements form
stable chelates: vanadium5*, zirconium4*, mercury,
thallium, and lead.
Toxicity involves many metabolic interactions.
Arsenic, for example, may be an essential element at
soil levels, up to 40 ppm. It counteracts certain diet
deficiencies and the effects of excess selenium.
45
-------
Table 3. Geographical distribution of mercury
1971-72 results; PPM on coal
Analysis by
Neutron Flameless
activation N.A. + AA -AA
Region State (Illinois)3 (N.B.S.)b (USGS-SW)c
A Pennsylvania 0.16,0.28 0.15
Ohio 0.10.0.13, 0.14,0.28,
0.15 0.49
West Virginia - 0.07,0.18
E. Kentucky -
IE Illinois 0.04,0.49,
0.60,1.15
Indiana - 0.08
IW Missouri - 0.19
N Montana 0.06 0.07,0.09
W Utah 0.04
Colorado 0.02,0.02 0.05
Wyoming
Arizona 0.02 0.06
Nevada
New Mexico
0.03-0.08
0.03-0.06
0.03-0.06
0.04-0.08
0.04-0.05
0.05-0.29
Total
No. of
Average Samples
0.20(2. Od)
0.21
0.12(6.6d)
(0.25d)
0.18(0.19d)
0.08(0.31d)
0.19
0.07, (33. Od)
0.05
0.04(0.22d)
0.05(18.
0.05
0.05
0.15
6")
3
6
2
53
15
3
6
6
7
37
Illinois State Geological Survey, bulletin EGN-43, 1971.
National Bureau of Standards, 1972.
°Southwest Energy Study, appendix J, (draft), Jan. 1972.
Values from Joensuu (1971) shown for comparison, including litho-
types; extremes show no relationship to more representative average
sampl es.
Table 4. Trace elements in soils, plants, and animalsa
As
Ba
Be
Cd
Cr
Ga
Ge
Pb
Hg
Ni
Se
Sr
V
a
demic
Rocksb
(ppm)
1-3
50-580
1-6
0.03-0.3
35-100
12-19
0.8-5.4
7-20
0.03-0.4
2-75
0.05-0.6
20-375
20-135
Donald J. Li
Press, 1972)
Soil
(ppm)
6
500
6
0.06
100
30
1
10
0.3
40
0.2
300
100
Ratio
plants/soil
0.03
0.11
0.03
5.3
0.01
0.04
0.25
2.3
0.05
0.05
1.0
0.09
0.008
Human body
(rug total )
7.9
22
0.04
50
1.7
120
13
10
13
320
48
sk, Advances in Agronomy, Vol. 24,
. Data
on coals from
Coals (ppm
1.50 0
X
x(+)
X
X
X
X
X
x(+)
X
pp. 267-324
range)
.2-10
X
?
X
x(-)
(Aca-
present report.
Average values for igneous rocks, shales, and sandstones.
46
-------
Selenium is essential to plant and animal life. It is
specific to some plants, rarely deficient in man. and
protects against excess cadmium or mercury. On the
other hand, with selenium there is only a narrow
range between deficiency and toxicity. Chromium is
essential for glucose metabolism, copper is essential
to enzymes, and cobalt and molybdenum are essential
in blood. Even barium and strontium may be
essential, as shown by a British survey which found
uniformly high amounts in the tissues of partridge
taken in areas where the hunting was good.
Further correlations of this type are still to be
made, and the question of what is toxic to humans is
not the same as for other organisms.
Conclusions
1. Overall, geography is an important factor in
distribution for only a few trace elements in coals.
Many elements are present at about 1 to 100 ppm in
all regions, and vary by a factor of 3 or less in the
averages for different basins or areas. The usual
amount of some 20 trace elements measured is about
5 to 10 ppm. B and F are higher, at about 50 to 200
ppm; Hg is lower, about 0.01 to 0.5 ppm.
2. The volatile hazardous elements show the
most need for more data. Some or all of these may be
related to mineral deposits nearby (Be, F, As, Se, Cd,
Hg, Pb). The hazard of Hg in power plant emissions,
in particular, has been grossly exaggerated.
3. Most elements in coal are very close to their
crustal abundance, and are not considered toxic at
this level. The question of toxicity must be evaluated
in relation to actual amounts.
4. The few elements which tend to be
concentrated in coals (S, Ge. Be, B, Ga) are associated
primarily with the organic portion of the coal. They
also show the largest variance in average
concentrations between different producing areas,
e.g., for germanium, which is high in Illinois.
5. The amount of some trace elements is
commonly highest in the top and in the bottom few
inches of a bed, and at the edges of a coal basin (Ge,
Be, Ga, and B at bottom only). These variations are
frequently greater than the differences between the
averages for different beds. Other elements (Cu, Ni.
Co) shown no such correlation.
6. Anomalous amounts of specific elements
may be found in beds contiguous to mineral ore
bodies of the same element. This is regularly the case
for coals having a mercury, lead, zinc, or uranium
content higher than the usual range, and may be
equally true for other elements including copper, tin,
and arsenic.
7. The elements present in the largest amount,
as minor components of the coal rather than as traces
only, are the common constituents of surface
waters: silica, alumina, iron, sulfur, phosphorus,
sodium, potassium, calcium, and magnesium. These
are present throughout the coal but they are often
enriched in the top layer, where they have apparently
been leached out of enclosing sediments.
8. The selection of a completely
"nonpolluting" coal is not possible, in the general
case. For a given amount of ash, coals which are low
in any one group of elements must be
correspondingly high in others. The definition of
nonpolluting depends directly on the decision as to
which elements are of concern and which are not.
47
-------
48
-------
DISTRIBUTION OF TRACE ELEMENTS IN COAL
R. R. Ruch, H. J. Gluskoter, and N. F. Shimp*
Abstract
Complete analyses of 101 coals, mostly from
Illinois and a few from eastern and western U.S. coal
fields, have been made in the laboratories of the
Illinois State Geological Survey. Specific gravity sepa-
rations up to 2.89 were made on four representative
coals, and subsequent analyses were performed on the
33 float-sink fractions resulting from the separations.
Trace elements determined were Sb, As, Be, B, Br,
Cd, Cr, Co, Cu, F, Ga, Ge, Pb, Mn, Mo, Ni, Hg, P, Se,
Sh, V, Zn, and Zr. Major and minor elements
Ca, Cl, Fe, Mg, K, Na, Si, S, and 77.
The analytical techniques employed were neutron
activation, optical emission, atomic absorption. X-ray
fluorescence, and ion-selective electrode. Accuracy
and precision were maximized by interlaboratory and
intralaboratory comparisons. High-temperature ash
(~ 500°C). low-temperature ash « 150°C), and
whole coal samples were analyzed in this investi-
gation. Trace element volatilities were determined for
each sample type, and further analyses were done on
the samples which best retained the element to be
determined.
Concentrations of some trace and minor elements
varied widely according to areal and stratigraphic dis-
tribution of the samples. Significant statistical corre-
lations of a number of elements (e.g., Zn and Cd;Si,
77, Al, and K; Ca and Mn; and Co, Ni, As, Cu, and Pb)
are readily attributable to the mineral phases present.
Association of some elements with inorganic
mineral fractions in the coals is further demonstrated
by their concentrations in the heavier specific gravity
fractions of the float-sink samples. Washability
studies indicate the potential effective removal of
several trace elements (including Zn, Cd, and Pb)
from raw coals by conventional specific gravity
methods. Other elements (including B, Be, and Ge)
are not removed by these methods because a large
portion of each is in organic combination.
The presence in coals of Zn and Cd in the mineral
sphalerite, of Pb in galena, of P and F in apatite, and
Ni and Cu in the iron su/fides has been demonstrated
by scanning electron microscopy and energy dis-
persive X-ray analyses.
•The authors are with the Illinois State Geological Survey,
Urbane, Illinois61801.
This study demonstrated the various problems of a
relatively complete coal analysis, including sampling,
sample preparation, adaptation of specific analytical
procedures, and interpretation of the statistical treat-
ment of the data.
INTRODUCTION
It has only recently become apparent that a
thorough knowledge of trace elements in coal is
necessary. Some trace elements in coal such as
arsenic, beryllium, cadmium, mercury, and lead are
known to be toxic to plant and animal life at low
concentrations. The problem potentially extends
beyond volatilization to the long-term storage of fly
ash and bottom ash. In addition, some elements may
act as catalysts or may retard catalysis in proposed
coal-conversion processes. Hence, accurate and
reliable data must be developed concerning the abso-
lute amounts of these elements in coal, their distribu-
tion and modes of occurrence, and their volatility
during combustion.
Several recent review articles deal with the subject
of the chemical nature of coal, including trace and
minor elements (refs. 1-4); however, most analyses
prior to 1970 were done on high-termperature ash
and do not reliably indicate the total amount of
volatile trace elements in whole coal, e.g., Hg, Br, F,
etc. This study concentrates not only on determining
trace elements in whole coal but also on determining
their volatility when the coals are plasma-ashed at low
temperatures « 150°C) and when conventionally
ashed at high temperatures (up to 700°C). A series of
prepared coals was also analyzed to determine which
elements might be reduced by specific gravity clean-
ing techniques.
This short report is a much abridged condensation
of a manuscript currently being prepared for publica-
tion by the Illinois State Geological Survey as an
Environmental Geology Note (EGN). The research
reported upon here and in the forthcoming EGN was
supported, in part, under Contract No. 68-02-0246
and Grant No. R-800059 from the U.S. Environ-
mental Protection Agency, Demonstration Projects
Branch, Control Systems Laboratory, Research Tri-
angle Park, North Carolina. An interim report on this
project has also been published (ref. 5).
49
-------
Experimental
Complete detailed information about sampling,
sample preparation, chemical analysis, and data treat-
ment is presented in other reports (ref. 5, and in the
final report, in preparation). Only a brief summary is
possible here.
Three face-channel samples were collected from
each mine tested, combined into a composite sample,
crushed to pass a 1/8-inch screen, riffled, and
comminuted to minus 20 mesh, minus 100 mesh, or
finer, depending upon the analytical technique to be
used. It was found, through X-ray fluorescence
studies, that minus 200 mesh is optimum for accepta-
ble precision.
Samples of whole coal, low-temperature ash (LTA,
< 150°C, derived from radio-frequency, oxygen-
plasma ashing of whole coal), and high-temperature
ash (HTA, ~ 500°C in a muffle furnace) were all used
for chemical analysis, and the results were compared.
Volatility studies were conducted to ascertain which
elements might be lost, wholly or in part, under the
different ashing conditions employed. A summary of
these results is shown in table 1.
The volatility results dictate that Hg, Br, Sb, and F
must be determined on whole coal, whereas Ga, Se,
As, Zn, Ni, Co, Be, Cu, Pb, V, Mn, and Cr can all be
determined on the low-temperature ash. High-
temperature ash is suitable for analyses of Zn, Ni, Cr,
Cu, Pb, B, Cd, Mn. Cr, Be, Ge, and Sn. Indications are
that Mo and possibly V are partially volatilized at
500°C.
Analytical techniques employed were neutron acti-
vation analysis (NAA). atomic absorption (AA), opti-
cal emission-direct reading (OE-DR), optical
emission-photographic (OE-P), X-ray fluorescence
(X-RF), and ion-selective electrode (ISE).
Where possible, extensive cross-checking was con-
ducted. This included interlaboratory and intra-
laboratory comparisons, including participation in a
roundrobin program on coal analysis cosponsored by
the EPA and the NBS. Accuracy and precision were
emphasized over speed and were used as the criteria
for choice of technique. Table 2 summarizes the
various techniques chosen and the types of samples
used for analyzing the various elements.
In general, individual precision for each element is
15 percent or less, with sensitivities of about 1 to 10
ppm on the whole coal basis.
DISCUSSION
Complete chemical analyses of 101 whole coal
samples and of 32 laboratory-prepared samples
obtained by specific gravity separation of four coals
have been made in the laboratories of the Illinois
State Geological Survey. Of the 101 whole coal
samples, 82 were from the Illinois Basin (Illinois,
Indiana, and western Kentucky). The additional 19
samples were from other areas of the United States.
Table 1. Summary of trace element volatility losses in
pretreatment ashing of coal
Low-temperature ash
Retained (> 95%)
Lost
High-temperature ash
Retained*
Lost
Ga
Se
As
Zn
Ni
Co
Be
Cu
Pb
V
Mn
Cr
Cd
Hg (up to 90%)
Br (100%)
Sb (up to 50%)
F (untested)
Zn
Ni
Co
Cu
Pb
B
Cd
Mn
Cr
Be
Ge
Sn
Mo (33%)
V (up to
25%)
*No significant losses observed in coal ash from 300° to 700°C or no
significant differences observed between results from whole coal to low-
temperature ash and high-temperature ash (~ 450°C).
50
-------
Table 2. Analytical procedure
recommended
Element
Hg.Mn.Na
Sb,Se,As,
Ga
Fe,Ti,Al,
Si.K.Ca,
S,Cl,Mg,
Br,P
Be,Ge,Co,
Cr
Cd.Zn
Pb.Cu
Ni
F
Zr
V
Mo,* Sn,B
Sampl e
Whole coal
LTA
Whole coal
HTA
LTA
LTA
HTA
HTA
LTA
Whole coal
Whole coal
HTA
Whole coal
HTA*
HTA
Procedure
N'AA,
X-RF
OE-DR,OE-P
AA
AA
OE-DR
OE-DR, OE-P
AA
X-RF
ISE
OE-P
,LTA X-RF
OE-DR, OE-P
OE-DR
*Low result is possible because of
volatilization.
The 4 coals which were prepared in the laboratory
(washed) were also from the Illinois Basin. Trace
elements determined were antimony, arsenic, beryl-
lium, boron, bromine, cadmium, chromium, cobalt,
copper, fluorine, gallium, germanium, lead, manga-
nese, mercury, molybdenum, nickel, phosphorus,
selenium, tin, vanadium, zinc, and zirconium. In
addition, the following major and minor elements
were also determined: aluminum, calcium, chlorine,
iron, magnesium, potassium, silicon, sodium, sulfur,
and titanium. Standard coal analyses-i.e., proximate,
ultimate, heating value, varieties of sulfur, and ash--
also reported.
As the first steps in the statistical analyses of the
more than 6,000 analytical values generated, the
arithmetic means, standard deviations, ranges, and
linear correlation coefficients were calculated for the
trace and major elements, for the high- and low-
temperature ashes, and for the proximate and ulti-
mate coal analyses for the 101 coals tested (table 3).
On the basis of these statistical calculations and
histograms of the element distributions, the elements
can be grouped with those of similar type. In the first
group of elements, each displays a relatively normal
distribution of analytical values and has small stan-
dard deviations and ranges. Included in this group are
Al, Fe, F. Ga, Be. Br, B, Cr, Cu. K, Ni, Si. Ti, Se, and
V. In the second group of elements, each has a
skewed pattern of analytical values with large stan-
dard deviations and ranges. This group includes Cd,
Zn, P, As, Sb, Pb, Sn, Cl. Ge, and Hg. The first group
of elements includes many with organic affinities.
Some of these elements are thought to be syngenetic.
and therefore inherited from an early period of coal
swamp formation. The second group includes
elements commonly found in coal, and in sedi-
mentary rocks in general, as carbonates and sulfides.
These minerals are often emplaced in coal by epi-
genetic mineralization.
Correlation coefficients for the various parameters
determined for the coals from the Illinois Basin and
for the entire 101 coals demonstrate the following
geochemical associations:
1. The highest value for the correlation coefficients
determined is that between Zn and Cd (r = 0.93).
Both zinc and cadmium are present in coals in the
mineral sphalerite, and probably only in that form.
2. The "Chalcophile" elements are those elements
commonly found in nature as sulfides; they include
As, Co, Cu, Ni, Pb, and Sb, which are all positively
correlated with each other in the coals analyzed.
3. The lithophile elements, those commonly occur-
ing in nature as silicates, include K, Ti, Al, and Si.
which also have mutual positive correlations in the
data reported. These elements are found in coals pri-
marily as clay minerals (aluminosilicates).
4. There is a positive correlation of 0.63 between
Mn and Ca in the coals analyzed, and Mn does not
correlate as well with any other parameter. Mn is
present in small amounts and most likely is in solid
solution with Ca in calcite (CaCO3).
5. Sodium and Cl have a positive correlation of
0.53 in the coals studied.
Several additional geochemical relationships have
been suggested by the chemical analytical data, such
as:
I. The concentrations of As, Cu, Pb, Si, and Al are
lower in the younger coals of the Illinois Basin than
in the older coals.
2. The correlation between Na and Cl increases
51
-------
TABLE 3. Mean Analytical Values for All 101 Coals
Constituent
As
B
Be
Br
Cd
Co
Cr
Cu
P
Oa
Ge
Kg
Hn
Ho
Nl
P
Pb
Sb
Se
Sn
V
Zn
Zr
Al
Ca
Cl
Fe
K
KB
Ha
Si
Ti
Org. S
Pyr. S
Sul. S
Tot. S
SXRP
ADL
Hols.
Vol.
Fix. C
Ash
Btu
C
B
N
0
HTA
LTA
Mean
It. 02 ppm
102.?! ppa
1.61 ppm
15. 42 ppm
2.52 ppm
9.57 Ppm
13.75 PP=>
1^.16 ppm
60.94 ppm
3.12 ppm
6.59 Ppm
0.20 ppm
l»9. 40 ppm
7.54 FP"
21.07 Fpm
71.10 ppm
34.78 PP«
1.26 ppm
2.08 ppm
4.79 PPm
32.71 PPB
272.29 ppa
72.46 ppm
1.25 %
0.77*
0.14 *
1.92*
0.16*
0.05*
0.05*
2.U9*
0.07*
1.41*
1.76*
0.10*
3.27*
2.91*
7-70*
9-05*
39.70 *
48.82 *
11.44 *
12.748.91
70.28 *
4.95*
1.30*
8.68*
11.41 *
15.28*
Standard Deviation
17.70
54.65
0.82
5.92
7.60
7.26
7.26
8.12
20.99
1.06
6.71
0.20
40.15
5.96
12.35
72.81
43.69
1.32
1.10
6.15
12.03
694.23
57.78
0.45
0.55
0.14
0.79
0.06
0.04
0.04
0.80
0.02
0.65
0.86
0.19
1.35
1.24
3.47
5-05
4.27
4.95
2.89
464.50
3.87
0.31
0.22
2.44
2.95
4.04
Minimum
0.50
5.00
0.20
4.00
0.10
1.00
4.00
5.00
25.00
1.10
1.00
0.02
6.00
1.00
3.00
5.00
4.00
0.20
0.45
1.00
11.00
6.00
8.00
0.43
0.05
0.01
0.34
0.02
0.01
0.00
0.58
0.02
0.31
0.06
0.01
0.42
0.54
1.40
0.01
18.90
34.60
2.20
11.562.00
55.23
4.03
0.78
4.15
3.28
3.82
HaxlcuD
93.00
224.00
4.00
52.00
65.00
43.00
54.00
61.00
143.00
7.50
43.00
1.60
181.00
30.00
80.00
400.00
218.00
8.90
7-70
51.00
78.00
5.350.00
133.00
3.04
2.67
0.54
4.32
0.43
0.25
0.20
6.09
0.15
3.09
3.78
1.06
6.47
5.40
16.70
20.70
52-70
65.40
25.80
14.362.00
80.14
5-79
1.84
16.03
25.85
31.70
Abbreviations other than standard chemical symbols: organic sulfur (Org. S), pyrmc
sulfur (Pyr. S). sulfate sulfur (Sul. S). total sulfur (Tot. S), sulfur by X-ray
fluorescence (SCRF). air-dry loss (ADL). moisture (Mois.), volatile matter (Vol.),
fixed carbon (Fix. C), high-temperature ash (HTA). low-temperature ash (LTA).
52
-------
from the older to the younger coals in the Illinois
Basin.
3. The B concentration in the coals of the Illinois
Basin also increases from the older to the younger
coals. This suggests that the Basin was becoming more
marine (increasing in salinity) during the period of
time between deposition of the older and younger
coals.
Further interpretations of some of the relationships
which have been noted and further elucidation of the
geological parameters that have influenced the
chemical characteristics of the coals should result
from continuing analyses of the data. These analyses
will include areal mapping of concentrations of
elements and also the mapping of distributions of the
elements within a single coal seam.
The average concentration of an element in the
earth's crust is its clarke value. The mean value for
each trace element was compared with the clarke for
that element. Only three elements were enriched by
at least one order of magnitude (present in an amount
greater than 10 times the clarke}, and three were
depleted by at least one order of magnitude (present
in an amount less than one-tenth the clarke). Because
of the large number of variables used in calculating
various clarke values, differences of less than one
order of magnitude were not considered significant.
The three elements enriched in coals are Cd, Se, and
B. Boron is concentrated only in the coals of the
Illinois Basin and probably represents a relatively high
salinity of the waters in the coal swamp or of the
waters which flooded the coal swamp. The only three
elements found to be depleted in coals are Mn, F. and
P.
An analysis of the data from the laboratory-
prepared (washed) coals has allowed the grouping of
the determined elements on the basis of their ten-
dency to be concentrated with the cleanest coal or
with the mineral matter. Those elements which are
most closely associated with the clean coal are those
with the highest "organic afmity" and include Ge, Be,
and B. At the other end of the scale are those
elements combined primarily in the mineral matter.
This group has the least organic affinity and includes
Hg, Zr, Zn, Cd, As, Pb, Mn, and Mo. The remaining
elements, which are apparently associated to varying
degrees with both the organic and inorganic fractions
of the coal, can be divided into two groups: those
which are more nearly allied with the elements with
organic affinities (P, Ga, Ti, Sb, and V) and those that
generally are more closely associated with the inor-
ganic fraction (Co, Ni, Cr, Se, and Cu).
Many minerals, including aluminosilicates, carbo-
nates, and su If ides, have been reported from coals,
and the mode of occurrence of the elements that
compose those minerals is evident. However, concen-.
trations of several additional elements were noted in
some of the coals studied, and the possibility that
these too may be in discrete mineral phases was inves-
tigated.
Sphalerite (ZnS) has been identified as the host
phase for both Zn and Cd in a number of coals,
including all those which were found to contain rela-
tively high concentrations of Zn (greater than 500
ppm). The phosphate mineral apatite, more precisely
a carbonate fluorapatite, was identified in the low-
temperature ashes of both the coal sample which was
found to contain the largest concentration of
phosphorus and the coal sample which contained the
largest concentration of fluorine.
A separate phase, identified as galena (PbS), has
been confirmed in the low-temperature ash of a
sample high in Pb. Both Ni and Cu have been identi-
fied in intimate association (probably in solid solu-
tion) with pyrite (FeS2) in several samples.
REFERENCES
I. G. 0. Nicholls, 'The Geochemistry of Coal-
Bearing Strata," Coal and Coal-Bearing Strata, D.
G. Murchison and T. S. Westoll (eds.), Oliver and
Boyd Publishers, Edinburgh and London, I968,
pp. 269-307.
2. J. D. Watt, "The Physical and Chemical Behavior
of the Mineral Matter in Coal Under the Con-
ditions Met in Combustion Plant; Part 1, The
Occurrence, Origin, Identity, Distribution, and
Estimation of the Mineral Species in British
Coals," British Coal Utilization Research Asso-
ciation, Leatherhead, Surrey, England, 1968, 121
p.
3. R. F. Abernethy, M. I. Peterson, and F. H.
Gibson, "Spectrochemical Analyses of Coal Ash
for Trace Elements," U.S. Bureau of Mines
Report of Investigations No. 7281,1968, 30 p.
4. E. M. Magee, H. J. Hall, and G. M. Varga, Jr.,
"Potential Pollutants in Fossil Fuels," U.S. EPA
Report R2-73-249, 1973, 151 p.
5. R. R. Ruch. H. J. Gluskoter, and N. F. Shimp,
"Occurrence and Distribution of Potentially
Volatile Trace Elements in Coal: An Interim
Report," Illinois State Geological Survey Envi-
ronmental Geology Note No. 61, 1973, 43 p.
53
-------
54
-------
PRELIMINARY CHEMICAL ANALYSIS OF
AQUEOUS WASTES FROM COAL CONVERSION PLANTS
(A RECOMMENDED APPROACH)
William T. Donaldson*
Abstract
Limited data on aqueous wastes from coal
conversion plants indicate the need for using those
analytical techniques that have proven to be useful
with other types of effluents. Solvent extraction-gas
chromatography-mass spectrometry, with
computerized data analysis, is recommended for
characterization of organic constituents.
Multielement techniques, such as spark source mass
spectrometry or X-ray fluorescence, are
recommended for elemental analyses. Such an
approach, when applied to the characterization of
wastes from petrochemical plants and Kraft pulp
mills, showed the composition of the effluents to be
significantly different from that predicted from a
knowledge of raw material and manufactured
products.
INTRODUCTION
A recent Bureau of Mines Technical Progress
Report (ref. 1) states that extensive research is
needed to characterize water effluents from the
Synthane process (coal to gas) and to determine
appropriate treatment processes. A large number of
elements and organic compounds are contained in the
wastewater, and the process uses a large volume of
water—about 3/4 ton of water for each ton of coal
processed, according to a spokesman for the Bureau
of Mines. Although the proposed effluent guidelines
published by the Environmental Protection Agency
do not specify criteria for many elements and organic
compounds, the guidelines may be more demanding
in the future. Therefore, a comprehensive knowledge
of effluent water composition is essential.
Even if environmental considerations were not
critical, economic considerations will probably
dictate that effluent water be recycled to increase
efficiency. A knowledge of the water's composition,
and how it changes as it is used and reused, can
provide valuable insight into the changes that take
place within coal conversion processes.
*W. T. Donaldson is with the Environmental Protection
Agency, Southeast Environmental Research Laboratory,
Athens, Georgia.
During the past few years, the qualitative organic
analysis and multielement analysis of industrial
aqueous effluents have been studied at EPA's
Southeast Environmental Research Laboratory
(SERL) (refs. 2, 3). Although the more traditional
Chemical analyses, such as those listed in EPA's 11
Methods for Chemical Analysis of Water and Wastes
(ref. 4) must be used to obtain specific
measurements, we believe that the orgnic qualitative
and multielement methods applied at SERL will be
applicable to the comprehensive characterization of
coal conversion plant aqueous wastes.
ORGANIC ANALYSIS
Gas chromatography-mass spectrometry (GC-MS) is
the best single technique for identifying moderately
volatile organic compounds. To make the required
investment in a mass spectrometer economically
feasible, a large number of samples must be analyzed
per unit time. The resulting extensive data reduction
and analysis must therefore be accomplished by
computers. At SERL a gas chromatograph is
interfaced to a Fjnnigan model 1015 quadrupole mass
spectrometer with a System Industries dedicated data
system. A second computer is used for data analysis
by comparing the mass spectra obtained from sample
compounds with spectra of 8,000 identified
compounds in the computer library.
A typical procedure for identifying organic
compounds in wastewater involves extraction with a
nonpolar solvent such as chloroform or hexane.
Extracts are concentrated by evaporation to about a
thousandth of their original volume, and then 1 to 10
microhters of the concentrate is injected into the
GC-MS. The computer directs the mass spectrometer
to scan the GC effluent every 3 seconds and stores
the total ion current data ( a signal related to
quantity of material in each GC peak) and
corresponding mass spectra on magnetic tape. At the
end of the GC-MS run, the computer retrieves the ion
current information and plots it as a reconstructed
gas chromatogram (RGC). A typical RGC is shown in
the upper trace of figure 1. The numbers on the
abscissa correspond to the mass spectra stored on
tape, and the ordinate reflects the total ion monitor
response.
After examining the RGC, the analyst can request
55
-------
Computer-Reconstructed Gas Chromatogram [RGC]
Petrochemical Company 'A1
0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 340 360 380
SPECTRUM NUMBER
Real Time Ion Current Summation [ICS]
Figure 1
-------
Mass Spectrum 287 Minus 284
B Petrochemical Company 'A'
R
R.
SB CD 70
FILEt AGO
SPtt NO! i»7
IMhtiHOLU tl I
EXPAND br I •,
KIN ll
M-*>T tonliUTl T
WCD riLi i *cu
i»"fc NOI :••
'..'•- 1*:
i»vi -Ibjil'i r
tUU,
MX £
(•"•"PIT"'" I I' |""l"'| I | |MM.M
SB 160 110 128 130 1« ISO 10 170 10 190 209 210 Z2B 230 ?»
287
200 220 240 260 280 300 320 340 360 380
Spectrum Number of RGC
Figure 2
-------
the computer to plot any mass spectrum by spectrum
number. The spectrum numbered 287 is shown in
figure 2. Contributions from impurities which were
not separated by the gas chromatograph were
eliminated from this spectrum by the computer by
subtracting spectrum 284 taken in the GC "valley."
Spectrum 287 contains quite a few discernible peaks,
which have dimensions of both mass (mass to charge
ratio) and amplitude (expressed in percentage of the
amplitude for the largest peak). With this
information, a computer should be able to select
those spectra from its library that are most similar to
that of the unknown compound.
The printout of the computer search for spectrum
287 is shown in figure 3. The first paragraph presents
the digital representation of the unknown
compound's spectrum in terms of the relative
amplitude for each discernible mass. The following
paragraphs list the compounds whose spectra in the
computer library are most similar to that of the
unknown compound. The last line of each of these
paragraphs provides a similarity index (SI), which aids
the analyst in selecting the most probable
identification. Compounds are listed in order of their
similarity indices. Note that the similarity indices for
two fluorene spectra are significantly higher than that
of the compound with the next highest similarity
index.
Thirty-seven compounds were identified by the
computer in this sample (table 1). However, the
computer identification cannot be accepted as an
absolute confirmation of identity. After the
computer "suggests" the identity for a compound,
the analyst must confirm it. He does this by first
examining the spectrum to see if its fragmentation
pattern is reasonable for the suggested compound. He
also compares GC retention times for the unknown
and suggested compounds. Finally, he can obtain
other types of spectra for the compound, if it is
present in high enough concentration. Chemical
lonization mass spectra are usually significantly
different from conventional (electron impact
ionization) spectra. Infrared (IR) spectra are highly
definitive, and recent advances in Fourier transform
GC-IR techniques have brought its sensitivity to
within one or two orders of magnitude of that of
GC-MC (ref. 5).
If specific compounds or classes of compounds are
of particular interest, specialized techniques of data
reduction may be used to detect these materials in
complex mixtures in which they may not be
detectable by conventional analysis. The most
Spectral Match of 287 Minus 284
FN= 287s; i;»
TT= PETR0CHEMICAL C0MPANY "A" ;X
38,3;39,12741,3;42,3;44,8;45, 22; 46, 1 ; 50,5;5 I,5; 57;%
55, 3; 56, i; 57,2; 58,3; 59,4; 60, I,* 61,3; 62, 7; 63, 13; 56; X
65, 1,'69, 10;70,4;71, l;72,2;73,14;74, 5; 75, 4; 76, 2; 57; X
81,5; 82,20,* 83, 1 3;84, 4;85, 3,* 86, 5; 87, 9; 88, 3; 89, 4; 57; X
98,2;99,i;110, i;112,i;113,3; 115,5; 117,i; 118,i; 138,i;64;x
139, 10; 146, i; 149, i; 163, 12; 164, 10; 165,82; 166, 100,* 167,6; 181,2;74;t
END
0PT10NS? N
DATA F0R T0P 0F GC PEAK7Y
15 HITS
PRINT SIM. INDEX7Y
•FLU0RFNF TRC61 2,2X-DITHIENYL API 1537
FILE KEY= 7667 FILE KEY= 6685
51=0.4999 51=0.2335
FLU0P.ENE MSC3523
FILE KEY= 10137
51=0.4044
2,3\-DITKIENYL API 1538
FILE KEY= 6686
51=0.2156
4-KETHYLBENZ0COCINN0L1NE MSC2041
FILE KEY= 8659
51=0.2686
igure 3
58
-------
common such technique is the generation of a limited
mass reconstructed gas chromatogram (LMRGC). For
example, in figure 4, the RGC shows peaks for
compounds whose spectra contain significant
numbers of any ion fragments of mass-to-charge
ratios 35 to 250. Above the RGC is the LMRGC in
which the computer was instructed to respond only
to those spectra that contain a compound fragment
with mass-to-charge ratio 149. This fragment is highly
characteristic of phthalate esters. The LMRGC
indicates that the sample may contain two phthalates.
The GC-MS technique is highly sensitive, acceptable
spectra can be obtained for most compounds present
in water at concentrations above 0.1 pg/liter by the
conventional mode of operation. Unfortunately, not
all compounds are amenable to solvent extraction,
and some that are extracted cannot be
chromatographed. Other techniques are being
investigated for analysis of polar and nonvolatile
compounds, but these techniques are not sufficiently
developed for broad application.
MULTIELEMENT ANALYSIS
As more consideration is given to the
environmental impact of low concentrations of
chemical elements, a large number of the 92 naturally
occurring elements are recognized as being pollutants
in certain systems. It is impossible to predict with
confidence which of these elements may be present in
industrial waste effluents. Analyzing for each element
separately is extremely time consuming and costly.
Therefore a simultaneous, multielement analytical
technique is needed.
At SERL we are evaluation the spark source mass
spectrometer's use in combined
qualitative-quantitative analysis of water.
Theoretically all chemical, nongaseous elements in
any matrix can be identified and measured with the
spark source mass spectrometer, provided organic
materials in the sample have been reduced to their
elemental components (other than carbon, hydrogen,
and oxygen).
The electrical detection system of the AEI MS-702
mass spectrometer is interfaced with a DEC PDP-8/E
computer. The computer program converts the
electronic signal from the detector into a typed listing
of all elements present and their concentrations in
micrograms per liter.
In machine computation of data, the reliability of
the mathematical constants in the computer must be
considered. Before we could rely on the computer's
data interpretation, we had to determine whether the
Table 1
Compounds Identified in Wastewater
of Petrochemical Company
RGC Spoctru.-
(froa Figure
£
1)
Compound Nane
2
4
10
16
29
36
47
£5
70
75
86
89
109
121
129
140
145
156
160
168
177
193
202
206
210
221
233
233
244
249
2S6
265
278
287
292
296
356
la-xylene*
p-xylene*
1,5-cyclooctadiene
o-xylene*
Isopropyloenzene (cuniene)
styrene*
o-e thy1to1uene
o-nethylstyrene*
diacetone alco.iol
indan*
2-butoxyeti:anol
B-r-c thy 1 s ty r ene
indene*
dincthylfuran isoner
n-pentadecar.e
l-nethylindere*
3—methylindone
acetop.ienone
n-hcxadecane
o-torpineol
naphthalene*
a-raetnylaenzyl alcohol
2-nothylaaphthalene•
benzyl alccnol
1-nethylnap.-. thalene*
ethylnaphtialene isoncr
2.6-du7ethylnaphthalene*
phenol*
methyl ethyl naphthalene loom
crosol iso—or
acenapht.ier.e
acenap-tfc.nalene
raethyIbiphenyl isonier
fluorene
phthalate diestcr
3•3—diphenyIpropanol
phthalate diester
•Identification was confirmed with a standard.
sensitivity coefficients (the terms that relate
electronic signal to numbers of atoms or elemental
weights) were applicable over a wide range of
elemental ratios. Two solutions were prepared
containing 16 elements in equal concentrations in one
solution and 18 different elements in equal
concentrations in the other solution. The solutions
were diluted and mixed into two samples, one
solution containing 100 parts of the 16 elements in
group I to 1 part of the 18 elements in group II. and
one solution containing 100 parts of elements in
group II to 1 part of elements in group I. The ratio of
concentrations of group I elements to those of group
II elements therefore differed by a factor of 10,000
between the two solutions.
When the two samples were analyzed by the spark
source mass spectrometer, using the sensitivity
coefficients established for solutions containing single
elements, no serious matrix effects were indicated.
The data are displayed in figures 5 and 6. Each point
represents the average of 9 determinations.
Figure 7 represents the computer printout for one
of the analyses performed on sample No. 1. Note that
for confirmation the computer considers
59
-------
ICO
80
Ul
20-
0
LMRGC m/e!49
o
356
292
20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 340 360 380
SPECTRUM NUMBER
100
RGC
j=60-
40
20 H
29
0
20 40 60 80 100 120 140 160 180 200 220 240 260 280* 300 320 3^0 350 380
SPECTRUM NUMBER
Figure 4
-------
50O
450
400
350
30O
25O
ZOO
ISO
IOO
SO
25
SAMPLE *2
GROUP I
KEY
High Values
Average
Low value*
-— Actual Cone (ppb)
Ce Cs Te Sn In Ma Rb Se Ge
Co
Al B
SAMPLE *2
GROUP H
40
35
3.0
2 5
2.0
1 5
1 0
OS
0
-
KEY
<
_
r— High Values
• Average
— Low Valuei
•• "' "fc mui wonc ippoj
-
• •_ .... • •
<
••
1
1 1 1
•y +2 -
Til
_i — i i
• •• • i
<
»
• •»»(
»
f-
• ••.
••
1 1 1 1 1
i
mi
I ^
<
•" ••
1 1
<
i
<
i
<
1 — M
Li"1""1
*
>
<
— i — i — i — iiit
La Pd Rh Ru Sc
Figure 5
61
-------
SAMPLE *l
GROUP I
55
50
45
40
35
30
25
20
1 5
10
OS
0
-
_
*
-
-
-
-
l
! T
1
2
1
l
™
1 |
l
' l
• IB
i
» '
•J
+
to
I
2
+ 2
1 (
, A
1
III!
+ 2
1
2
KEY
I
|
J
l
12 I
I.
1 1 1
High vgluec
•iveroge
""" c ue*
Actual Cone (ppb)
2
(
•
( 1
. . .. T
' T
1 1 1 1
Ce Cs Te Sn In Rb Se Ge V Ti Co K P Al B Be
SAMPLE *l
GROUP IE
500
450
400
35O
300
250
2OO
ISO
100
50
25
^
-J---:
-
Au P
+
i
i
t 1
2
i i
rb i
••
- — '
m E
L J
r H
I(
...
0 Oy 1
i
i
rb <
KE
I
1
<
1
!d Eu !
Y
l '
High Voluei
Average
LOM Values
Actual Cone ( pp
T
™3;"'J"_
Id Pr La
i)
1 T
....L...
j — i —
>d Rh f
+;
, «
l — i
lu j
Figure 6
62
-------
Modified Interpretation of +1 and +2 Ion Data
JULY
SEVENTEEN
CONCEN + + ?
TRATIONS ++*?
CONFI RM
ISOTOPES
CHECK COMPLEX
OVERLAP IONS
197
195
191
189
182
175
172
85
167
165
163
159
158
153
147
143
141
140
139
138
66
128
118
115
111
105
SI
50
95
89
43
GOLD
PLATINUM
I RI DI UM
OSMIUM
TUNGSTEN
LUTECI UM
YTTERBI UM
THULIUM
ERBIUM
HOLMIUM
DYSPROSIUM
TERB1 UM
GADOLINIUM
EUROPI UM
SAMARI UM
NEODYMIUM
PRASEODYME
CERIUM
LANTHANUM
BARIUM
CESIUM
TELLURI UM
TIN
INDIUM
CADMIUM
PALLADI UM
RHODIUM
RUTHENIUM
MOLYBDENUM
YTTR1 UH
RUBI DI UM
88.75
858.88
2.88
8.15
7.29
.52
146.82
87.23
136.39
102.67
230.85
186.73
222.27
104.12
116.74
152.42
96.06
2.04
67.01
.31
.49
2.61
1.89
2.32
3.80
101.65
52.31
77.83
1.41
STANDARD
.66
28 MANGANESE
25
24
23
20
18
16
14
12
19
VANADIUM
TITANIUM
SCANDIUM
CALCIUM
20 POTASSIUM
CHLORINE
PHOSPHORUS
ALUMINIUM
SODIUM
FLUORINE
16 OXYGEN
14 NITROGEN
11 BORON
9 BERYLLIUM
.01
.70
1.47
103.97
3.86
.21
220.39
.41
.58
.63
.03
19.84
27.55
2+
2+
NO
NO
NO
NO
2+
2+
2+
2*
2*
2+
2*
2+
2+
2*
2*
NO
2*
NO
2+
NO
NO
NO
NO
2+
2*
2*
NO
2*
2+
2*
2*
2*
NO
2+
2*
2+
2*
2*
NO
NO
NO
-NO MATR1X-
1.18 NO
.94 NO
END OF RUN
YES
NO
NO
NO
NO
YES
YES
YES
YES
YES
NO
NO
NO
NO
YES
NO
NO
NO
NO
NO
169( 85)
NO
NO
YES
NO
103<
I0K
190(
8S(
170<
55(
sec
5I(
76C
47(
7|{
45(
40(
60<
39 (
82(
35(
31(
27 (
23(
38 (
57(
34(
51(
28 (
30 (
4SC
20(
30(
51)
50)
95)
43)
85)
28)
28)
25)
25)
24)
24)
23)
20)
20)
20)
41)
18)
16)
14)
12)
19)
19)
17)
17)
14)
15)
15)
10)
10)
Figure 7
63
-------
Table 2
Mass Spectrometric Analyses of the
Benzene-Soluble Tar, Volume-Percent
Run HP-1
Structural Type No. 92,
(Includes Alkyl Illinois3
Derivatives) No. 6 coal
Benzenes
Indenes
Indans
Naphthalenes
Fluorenes
Acenaphthenes
3-ring aromatics
Phenylnaphthalenes
4-ring pericondensed
4-ring catacondensed
Phenols
Naphthols
Indanols
Acenaphthenols
Phenanthrols
Dibenzofurans
Dibenzothiophenes
Benzonaphthothiophenes
N-heterocyc 1 icsc
Average molecular
weight
b2.1
b8.6
1.9
11.6
9.6
13.5
13.8
9.8
7.2
4.0
2.8
(b)
.9
-
2.7
6.3
3.5
1.7
(10.8)
212
Run HPM Run HP- 11 8
No. Ill, No. 118 ,a
Run HPL Montana Pittsburgh
No. 94, Subbituminous Seam
Lignite Coal Coal
4.1
1.5
3.5
19.0
7.2
12.0
10.5
3.5
3.5
1.4
13.7
9.7
1.7
2.5
—
5.2
1.0
(3.8)
173
3.9
2.6
4.9
15.3
9.7
11.1
9.0
6.4
4.9
3.0
5.5
9.6
1.5
4.6
.9
5.6
1.5
(5.3)
230
b1'9
D6.1
2.1
16.5
10.7
15.8
14.8
7.6
7.6
4.1
3.0
(b)
.7
2.0
—
4.7
2.4
(8.8)
202
a Spectra indicate traces of 5-ring aromatics.
Includes any naphthol present (not resolved in these spectra).
c Data on N-free basis since isotope corrections were estimated.
doubly-charged and triply-charged ions as wen as
isotopes of the element other than the one used for
the computation of concentration.
PRELIMINARY APPLICATION
TO COAL GASIFICATION EFFLUENTS
In analyzing waste products and effluents from the
Synthane Process, the Bureau of Mines chemists used
organic mass spectremetry for analysis of tars, and
spark source mass spectrometric analyses were
performed on aqueous wastes at the SERL (ref. 1).
Table 2 shows organic compounds found in the tars.
These compounds must also be considered in
wastewater analyses. Table 3 lists the 20 chemical
elements found to be present in concentrations
greater than 1 part per billion in the aqueous effluent.
Until the composition and variation in composition
of aqueous wastes from coal gasification are firmly
established, comprehensive analyses such as these are
recommended. After knowledge of the variation in
composition is known, then an appropriate
monitoring program can be set up and comprehensive
analyses will be required only where experience
dictates.
If such an approach is followed, the coal
gasification industry will be a leader in providing
information to assess the environmental impact of
aqueous effluents. It will also be in a good position to
increase cost-effectiveness of resource management
while protecting the aquatic environment.
REFERENCES
1. J. Forney. W. P. Haynes, S. J. Gasior, G. E.
Johnson, and J. P. Strakey, Jr., "Analysis of
Tars, Chars. Gases, and Water Found in Effluents
from the Synthance Process," Bureau of Mines
Technical Progress Report TPR 76, January
1974.
2. R. G. Webb, A. W. Garrison, L. H. Keith, and J.
M. McGuire. "Current Practice in GC-MS
Analysis of Organic; in Water," Environmental
64
-------
Table 3
Trace Elements in Condensate from
an Illinois No. 6 Coal Gasification Test
Ppm:
Ppb:
Zinc ,
Arsenic ,
Nickel ,
Cobalt ,
No. 1
4.4
.... 2.6
1.5
0.8
401
117
109
82
44
36
.... 32
44
23
33
25
16
7
4
4
1
-No. 2
3.6
2.9
1.8
0.7
323
204
155
92
83
38
61
28
34
24
26
20
5
8
2
2
Average (by weight)
4
3
2
0.8
360
160
130
90
60
40
40
30
30
30
20
20
6
6
3
2
4.
Protection Agency Research Report
EPA-R 2-73-277 .August 1973.
C. E. Taylor and W. J. Taylor, "Multielement
Analysis of Environmental Samples by Spark
Source Mass Spectrometry," Environmental
Protection Agency Research Report EPA
660/2-74-002. January 1974.
"Methods for Chemical Analysis of Water and
Wastes," Environmental Protection Agency
Manual, Analytical Quality Control Laboratory.
Cincinnati, Ohio, July 1971.
5. L. V. Azarraga and A. C. Me Call, "Infrared
Transform Spectrometry of Gas
Chromatography Effluents," Environmental
Protection Agency Research Report EPA
660/2-73-034, January 1974.
65
-------
66
-------
14 May 1974
Session III:
ENVIRONMENTAL ASPECTS OF
SPECIFIC FUEL CONVERSION SYSTEMS
David H. Archer, Ph.D.
Session Chairman
67
-------
-------
SOME IMPLICATIONS OF ENVIRONMENTAL REGULATORY ACTIVITIES
ON COAL CONVERSION PROCESSES
E. S. Rubin and F. C. McMichael*
Abstract
Existing U.S. environmental regulatory policies for
air and water pollution control are reviewed in detail
from the point of view of their potential implications
on coal conversion processes presently under
development in this country. The discussions focus
on standards of environmental qualityf new source
performance or discharge standards, and the
interactive roles of Federal, State, and focal
authorities in defining and implementing
environmental control programs. Elements of existing
regulatory activities are shown to impose potentially
conflicting or inconsistent requirements that may be
counterproductive to environmental quality. Several
areas for further study are indicated.
INTRODUCTION
Background and Scope of Discussion
Coal conversion plants are soon to be pan of the
fuel technology of the United States. They are
envisioned to be a complex of physical-chemical unit
operations that offer the promise of clean fuels to our
society. However, it is important that the
environmental impact of coal as a fuel is not simply
transferred from existing industries to new kinds of
facilities at other locations.
Table 1 lists several of the more well-known
processes that are under development in the United
States to produce clean fuels from coal, including
high-Btu gas, low-Btu gas, and synthetic liquids. While
it is clear that commercial production and utilization
of low-sulfur, low-ash synthetic fuels will significantly
help enhance environmental quality at many sites, it
is also clear that there are potential environmental
problems associated with the conversion processes
themselves. These potential problems are quite
sizeable and must be carefully evaluated (refs. 1-4).
Air pollution, water pollution, solid waste disposal,
and thermal pollution problems, already familiar to
much of today's in-place industrial technology, will
be among the problems also encountered in coal
conversion processing.
'Both are at Carnegie-Mellon University, Pittsburgh, Pa.
E. S. Rubin, Associate Professor, Mechanical Engineering and
Public Affairs, and F C. McMichael is Associate Professor,
Civil Engineering and Public Affairs.
Environmental control measures in these areas will
take place within a regulatory framework established
by Federal, State, and local agencies charged with
defining and implementing environmental control
policy with respect to one or more areas of impact.
To gain some perspective on the possible shape of
such a policy, this paper is directed at a review of
some of the recent environmental regulatory activities
that are likely to affect new coal conversion
processes, including an examination of some of the
implications of these activities on coal conversion
process requirements and resulting environmental
impacts. Discussions will be restricted principally to a
consideration of problems in air and water pollution,
in that these are the areas in which regulatory
activities are at present most strongly focused. These
two problems are strongly related to one another, and
it is the nature of this relationship and the ability of
regulatory policy to deal with it (as with the
relationship to other problems such as solid waste
disposal) that will be held up for particular attention.
Nature and Sources of Pollutants from Coal
Conversion Processes
Tables 2 and 3 indicate the major air and water
pollutants known or suspected to be associated with
coal gasification or liquefaction processes (refs. 4-9).
Table 2 for air pollutants indicates whether release of
the pollutant occurs principally as a result of the coal
conversion process or as a result of fuel combustion.
The latter includes auxiliary combustion required for
the conversion process (e.g., to provide utilities such
as steam and electric power), as well as end-use
combustion of the synthetic fuel products. Since
boilerhouse steam, raised by direct combustion, is
required to operate pollution control systems on
plant process streams, it is appropriate to view
combustion-generated pollutants as resulting in part
from the need for other environmental control
measures. In this light, tradeoffs among different
pollutants and environmental media become
somewhat more apparent, as will be further
illustrated later. First, the following paragraphs
briefly review the major sources of air and water
pollutants in coal conversion processing.
Air Pollutants
Sulfur dioxide is emitted principally from the
-------
Table 1. Selected Coal Conversion Processes
NAME
DEVELOPER/SPONSOR
STATUS
HIGH-BTU GASIFICATION
BI-GAS
COGAS
COg Acceptor
HYGAS
Lurgi
Molten Salt
Synthane
LOW-BTU GASIFICATION
Agglomerating Gasifier
Atgas
Entrained Gasifier
Koppers-Totzek
Lurgi
Stirred Fixed Bed
LIQUEFACTION
COED
Direct Hydrogenation
Hydrogen Donor
Project Gasoline
Solvent Refined Coal
Turbulent Catalytic
BCR/OCR-AGA
FMC Corp.
Consol/OCR-AGA
IGT/OCR-AGA
Lurgi
M.W. Kellogg
BuMines
Westing./OCR-Private
ATI/EPA
CE/OCR
Koppers
Lurgi
BuMines
FMC/OCR
Univ Utah/OCR
Exxon
Conoco
P&M/So. Svcs/OCR
BuMines
Pilot (u/c)
Pilot
Pilot
Pilot
Comm'l (prop.)
Bench
Pilot (u/c)
Pilot (u/c)
Bench
Design
Comm'l
Comm'l
Bench
Pilot
Bench
Bench
Pilot
Pilot
Bench
*Ref. 2
tailgas stream of the sulfur recovery plant and from
stack gases of auxiliary systems requiring fuel
oxidation. The latter most prominantly includes coal
pretreatment processes, plant boilerhouse, and
miscellaneous process heaters and burners fired with
sulfur-bearing fuels.
Paniculate matter can be released to the
atmosphere both as a fugitive dust and as a process or
combustion-based stack emission. Fugitive emissions
would be most likely to occur at receiving, handling,
and storage areas for coal, solid wastes, or solid
products, but could also occur as leakages from
process equipment trains. Process stack emissions
would include the exhaust streams of pollution
control equipment such as scrubbers, precipitators,
and baghouses associated with unit operations
including coal driers, pulverizers, gasifiers, prilling
towers, and the like (details of which would vary
from process to process). Again, fuel combustion
would provide another potentially significant source
of particulate where furnaces or boilers are fired with
solid or perhaps liquid fuels.
Nitrogen oxide emissions result from combustion in
boilers and process heaters fired on either gaseous,
liquid, or solid fuels. Emissions would depend on the
fuel type, boiler design, various combustion
parameters, and the fuel nitrogen content.
Hydrocarbon emission in coal conversion could
occur from liquid product storage areas, from leakage
at valves, flanges, and seals of the assorted pipes,
vessels, pumps, and compressors throughout the
plant, and from evaporation of hydrocarbon liquids
dissolved in effluent or cooling streams.
Combustion-generated hydrocarbons may also
emanate from furnace and boiler stacks as a result of
incomplete combustion.
Carbon monoxide, produced in large quantities in
coal gasification processes, is a prime fuel constituent,
and no significant release to the atmosphere would be
expected from the process stream. As with
70
-------
Table 2. Types and Sources of Potential Air
Pollutants from Coal Conversion Processes
Pollutant Process-Generated Combustion-Generated
Particulate Matter x x
Sulfur Oxides x x
Reduced Sulfur Compounds x
Nitrogen Oxides x
Hydrocarbons x x
Carbon Monoxide x x
Trace Metals x x
Odors x
Other Gases (incl. NH , HCN, x
HC1) 3
Table 3 Composition of Wastewaters Representative
of Coal Conversion Process Waters
Pollutant Ammonia Liquor* Synthane By-Product Water**
(mg/liter) (ing/liter)
pH
COD
Ammonia
Cyanide
Thiocyanate
Phenols
Sulfide
Alkalinity (as CaC03)
Specific conductance
(as umho/cm)
8.3-9.1
2,500-10,000
1,800-4,300
10-37
100-1,500
410-2,400
0-50
1,200-2,700
11,000-32,000
7.9-9.3
1,700-43,000
2,500-11,000
0.1-0.6
21-200
200-6,600
N/D
N/D
N/D
*Ref. 15
**Ref. 6
N/D = Not determined
71
-------
hydrocarbons, some amount of CO may be released
to the atmosphere as a result of incomplete
combustion of fuel in plant heaters and boilers.
Reduced sulfur compounds (principally H2S, COS,
and CS2) occur in the initial product streams of
virtually all coal conversion processes, from which
they are nominally stripped and converted to a
recoverable substance. Potentially, emissions could
occur as a result of incomplete removal {such as from
a CO2 exhaust steam), leakage from valves and seals,
and evaporation (at cooling towers) from scrubbing
water containing dissolved gases and from water
quenching of solid process residues or slags containing
sulfur.
Trace element emissions of such substances as
mercury, berillium, arsenic, cadmium, vanadium, and
other heavy metals (all of which are contained in coal
in small amounts) is a subject about which relatively
little is presently known, although some work in this
area is emerging (refs. 10-13). Studies of trace metal
emissions from coal-fired boilers, for example,
indicated that most of the mercury and possibly
other trace metals in coal are vaporized and emitted
in the stack flue gas. The fate of these substances in
coal conversion plants requires further detailed study.
Finally, other gaseous emissions, especially
hydrogen cyanide and ammonia (as well as hydrogen
chloride and gaseous odorants), may also be
associated with coal conversion plants, as some
developing emission regulations anticipate (ref. 9).
Such emissions would again most likely occur via
evaporation from the cooling of scrubbing liquors,
although not much quantitative information is
currently available.
Water Pollutants
Wastewaters from coal conversion processes can
originate from four sources: (1) moisture in the coal,
(2) water of constitution, (3) water added for
stoichiometric process requirements, and (4) water
introduced for byproduct recovery or gas scrubbing.
The first two sources alone, for example, may
contribute a flow of 20 to 30 gallons per ton without
considering condensates formed by other mechanisms
(ref. 14). Since these process waters come into
contact with contaminates in coal, they are the
principal source of pollution, as opposed to
nonprocess waters such as used for indirect cooling.
Since coal conversion processes, however, are net
consumers of water, all streams could theoretically be
recycled for use in the process, and no wastewater
streams need emanate from the plant. Effluent
streams occur in practice because it is often difficult
or impossible, for reasons of technology and/or
economics, to recycle all wastewaters consumptively
and control all stream flows to yield the precise
overall stoichiometric water requirement.
The complex composition of the process waters
from coal reflects the fact that water is a universal
solvent. In many ways, coal process waters have an
inorganic composition as saline as sea water. They
include practically all the organic compounds found
in coal. Any condensate water should be expected to
have a composition that falls within the range of
composition shown in table 3.
A major wastewater stream from the byproduct
coking industry, waste ammonia liquor, may offer
some hint to the expected composition of coal
conversion plant process wastewaters. The similarity
in table 3 of ammonia liquor contaminants with data
reported for Synthane byproduct waters further
suggests the complexity of coal conversion plant
wastewater.
REGULATORY POLICIES FOR AIR
AND WATER POLLUTION CONTROL
Table 4 summarizes the nature of existing
regulatory policies for air and water pollution
control. Generically, our present environmental
policies take the form of two types of regulations: (1)
standards of environmental quality, and (2) standards
limiting the discharge of specified substances to the
environment, either by specifying a maximum
allowable discharge rate and/or concentration, or by
requiring specific types of control equipment or
system design.
The two types of standards may or may not be
related to, or consistent with, one another. In air
pollution, environmental air quality standards often
do provide the philosophical and quantitative basis
for the national emission control programs presently
in place. In water pollution, however, present control
programs are in practice based mainly on
considerations of technological capability rather than
on compatibility with water quality standards. The
following paragraphs elaborate on the current types
of environmental and discharge standards that may
affect coal conversion processing.
Standards of Environmental Quality
Standards of environmental quality for air and
water are established by local. State, and Federal
authorities. The 1970 Clean Air Act Amendments
have given the Federal Government the leading role in
72
-------
Table 4. Summary of Current U.S. Regulatory Policy for
Air and Water Pollutants
(A User's Guide to the Regulatory Lexicon)
ELEMENTS OF AIR POLLUTION
CONTROL POLICY
ELEMENTS OF WATER POLLUTION
CONTROL POLICY
AMBIENT AIR QUALITY STANDARDS
(AAQS)
Nat'l Primary Standards
Nat'l Secondary Standards
Non-degradation Standards
State & Local Standards
EMISSION STANDARDS
New Source Performance
Standards (NSPS)
Hazardous Pollutants
State and Local Standards
THRESHOLD LIMIT VALUE
RECEIVING WATER QUALITY STANDARDS
(RWQS)
U.S. PUBLIC HEALTH SERVICE
DRINKING WATER STANDARDS
EFFLUENT LIMITATIONS
New Source Performance
Standards (NSPS)
Best Practicable Technology
Best Available Technology
Pretreatment Standards
Zero Discharge
Toxic Substances
State and Local Standards
the area of air by requiring EPA to promulgate
national ambient air quality standards (AAQS),
including primary standards that are protective of
human health, and secondary standards protective of
human welfare (table 5). Emission control strategies
must be designed to achieve primary standards by
mid-1975 and secondary standards as soon as possible
thereafter. State and local authorities, however, may
promulgate air quality standards that are more
stringent than the national standards, or that apply to
pollutants or averaging times not covered by Federal
regulations. Table 6 illustrates this for six States
located in the eastern coal fields of the United States
(fig. 1).
Federal responsibility also includes insuring the
"nondegradation" of air with a quality better than
the national standards. In 1973, EPA proposed four
alternative plans to prevent "significant
deterioration" (ref. 18), although no final plan has
yet been adopted. More recently, a modified version
of that plan was suggested by EPA, as summarized in
table 7. It has also invited Congress to reexamme this
issue.
In the water pollution area, State-imposed receiving
water quality standards (RWQS) also apply to all of
the Nation's waterways, but do not usually serve as
the basis for establishing source effluent limitations.
The Federal Water Pollution Control Act
Amendments of 1972 aim to "restore and maintain
the chemical, physical, and biological integrity of the
Nation's waters." It is the "national goal that the
discharge of pollutants into the navigable waters be
eliminated by 1985." However, by July 1, 1983, it is
the "national goal wherever attainable to have water
quality which provides for the protection and
propagation of fish, shellfish, and wildlife and
provides for recreation in and on the water."
Furthermore, it is "the national policy that the
73
-------
Table 5. National Ambient Air Quality Standards
Contaminant
Suspended
Participates
Sulfur
Dioxide
Carbon
Monoxide
Photochemical
Oxidant
Hydrocarbons
(non-methane)
Nitrogen
Dioxide
Averaging
Interval
1 year
24 hr.
1 year
24 hr.
3 hr.
8 hr.
1 hr.
1 hr.
3 hr.
(6-9 a.m.)
1 year
Primary Standard
ug/m3
75
260
80
365
10,000
40,000
160
160
100
ppm
(by vol . )
__
0.03
0.14
9.0
35.0
0.08
0.24
0.05
Secondary Standard
pg/m3
60
150
1,300
10,000
40.000
160
160
100
ppm
(by vol . )
__
0.5
9.0
35.0
0.08
0.24
0.05
Notes: 1. All values other than annual values are maximum concentrations
not tp_ be^ exceeded more than once per year.
2. PPM values are approximate only.
3. All concentrations relate to air at standard conditions of 25°C
temperature and 760 millimeters of mercury pressure.
4. Annual average refers to arithmetic mean for gases and geometric
mean for particulates.
discharge of toxic pollutants in toxic amounts be
prohibited." There is an attempt to separate or
decouple effluent standards and receiving water
quality standards. The water quality standards
program has been expanded to include intrastate as
well as interstate waters. The States individually set
their own receiving water standards, which must be
approved by the EPA, and are expected to meet the
goals and deadlines of the new law. They are also to
be used to measure the effectiveness of effluent
limitations. The EPA and the States may prescribe
more stringent effluent limitations to protect high
quality bodies of water when it is evident that
receiving water quality does not provide for the
beneficial uses of human recreation and fish
propagation.
There are also general water quality criteria
designed to protect the water uses of streams. These
limits typically refer to the elimination of floating
solids, films, scums, bottom deposits, and
objectionable odors. States also set specific limits,
sometimes daily averages as well as monthly averages.
for particular pollutants. Commonly, all States will
set limits on pH, temperature, and dissolved oxygen.
However, the levels and averaging periods are often
different. Specific wastewater parameters such as
phenol, ammonia, and cyanide may be set at different
limits on the same river by different States, e.g., the
phenol limit for West Virginia and Pennsylvania (table
8).
Special types of air and water quality standards
indicated in table 4 are the U.S. Public Health Service
Drinking Water Standards and Threshold Limit Value
(TLV) standards for air pollutants. Public Health
Service drinking standards specify the maximum
concentration of various substances acceptable for
drinking water use on interstate carriers. (They are
also the generally accepted comparison for rating all
public water supplies.) Threshold limit values define
maximum concentrations of air pollutants for
industrial exposure as required under the
Occupational Safety and Health Act, and are usually
considerably less stringent than standards applying to
the population as a whole.
74
-------
Table 6.Selected Local Aniient Air Quality Standards
for Six Eastern States
State
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
Pollutant
N/A
N/A
Fieri des
Hydrogen Sulfide
Hydrogen Fluoride
N/A
Settled Particles
Suspended Particulates
Lead
Beryllium
Sulfates (H.SO.)
C 4
Fluorides (as HF)
Hydrogen Sulfide
Standard (ug/n3)*
N/A
«/A
80 ppn (30-da avg)
0.01 yym (1-hr avg)
0.82 30-da)
1.64 1-wk)
2.86 24-hr)
3.68 12-hr)
H/A
800 (1-yr)
1500 (30-da)
" 330 (4-hr)
5 (30-da)
0.01 (30-da)
10 (30-da)
30 (24-hr)
5 (30-da)
0.005 ppn (24-hr)
0.1 pptn (1-hr)
Vest Virginia
N/A
H/A
Maximum value, not to be exceeded
Allegheny County only
Table 7. Proposed Nondegradation Standards
Applicability
Haxiirin Allowable Degradation
Sulfur Dioxide Particulate Hatter
2one 1 Areas
(Restricted Development)
Zone 2 Areas
(Modest Development)
Zone 3 Areas
(Concentrated Development)
2 ug/o (annual avg) 5 ug/n (annual avg)
5 ug/si3(24-hr avg) 10 ug/m3(24-hr avg)
25 ug/m3(3-hr avg)
15 ug/ci (annual avg)
100 ug/o3(?4-hr avg)
300 ug/n (3-hr avg)
10 ug/n (annual avg)
30 ug/n3(24-hr avg)
Up to Secondary tabient Air Quality Standards
(1300 ug/n , 3-hr avg) (60 ug/s .ar.r.-jal avg)
(150 ug/m3. 24-hr avg)
Ref. 19. Degradation for Zones 1 ard 2 are essentially the sare levels
for-ally proposed by EPA as alternative definitions of 'significant
deterioration.' (Ref 18).
75
-------
/• ^^ t-"-.., /
i/" • I**
•^ -i
Figure 1. Coal Fields of the United States
-------
Teble 8. Selected State Receiving Meter Quillty Standards
STATE
Ohio
Pennsylvania
Watt Virginia
ORSANCO
POLLUTANT
Toxic Substances
Cyanide
Threshold Odor Ho.(60*C)
Temperature
Phenol
Total Iron
Total manganese
Threshold Odor No. (60*C)
Temperature
Toxic Substances
Cyanide
Phenol
Arsenic
Chromium (hexavalent)
Threshold Odor No. (60*C)
Temperature
Cyanide
Chromium (hexavalent)
Arsenic
Threshold Odor No. (60*C)
Temperature
STANDARD
0.1 TLn-48 hour
0.20 mg/ liter
Z4
Seasonal Units
O.OOS ng/llter
1.5 mg/ liter
1.0 mg/llter
24
(lax. B7*F
0 1 Tln-96 hour
0.025 ng/llter
0.001 mg/llter
0.01 mq/ltter
0.05 mg/llter
8
Seasonal limits
0.2 ng/llter
0.05 mg/llter
O.OS ng/llter
24
Seasonal Halts
Standards on Lewi of Pollutant Discharge
Federal Performance Standards
Regulatory limitations on pollutant discharges to
the environment are of several types. Both air and
water pollutions are subject to new source
performance standards (NSPS) which limit emissions
of particular substances from specific processes or
unit operations that are newly constructed or
"substantially modified" subsequent to publication
of the NSPS. These standards are promulgated by the
Federal Government (U.S. Environmental Protection
Agency) as authorized by the 1970 Clean Air Act
Amendments and the 1972 Federal Water Pollution
Control Act Amendements. New source standards call
for the use of "best adequately demonstrated
technology," which in the case of air pollution must
also take cost into account. Federal standards also
apply to existing sources of water pollution. For
source types specified by the EPA, effluent
limitations include installation of "best pollution
control technology currently available," to be
installed by mid-1977, and "best available technology
economically achievable." to be in place by
mid-1983. There is also a congressionally mandated
national goal to "zero discharge" by 1985.
For both air and water pollutants. Federal NSPS
will generally impose the most stringent limitations
on allowable release of pollutants to the environment.
While no standards yet exist for coal conversion
processes, NSPS have been promulgated or proposed
for industrial processes that are related to coal
conversion schemes. Petroleum refineries and coal
carbonization plants offer two particularly interesting
cases since they encompass many of the operations
anticipated in coal conversion processing.
Table 9 indicates the air and water pollutants
subject to NSPS for four industrial processes as well
as new fossil-fuel-fired steam generators. Tables
10,11, and 12 give selected current standards.
Proposed effluent guidelines for petroleum refineries
divide the industry into six subcategories based on
the raw waste load with respect to the type of
77
-------
Table 9. Selected Federal New Source Performance Standards*
StCaBl P«tr«
Substence Generator! Rcflr
•
R
•
• XI
X •
•
fefl »-».»
refinery, process technology employed, and the waste
severity from the operations (ref. 20). The
subcategories are (a) topping, (b) low cracking, (c)
high cracking, (d) petrochemical, (e) lube, and (f)
integrated. Table 10 indicates the range of pollutant
effluent limits over all subcategories. Typically, the
lower limit applies to the most complex refinery
(integrated). Note that new source refinery standards
specify both the maximum effluent for any one day,
and the maximum average of daily values for any
period of 30 consecutive days.
The proposed NSPS limitations for byproduct
coking are listed in table 11. Values for each
pollutant are also specified for a 30-day average limit
and a maximum daily limit (ref. 21). Comparing
tables 10 and 11, one notes that the Federal effluent
limitations differ in several important ways. The
petroleum guidelines set different limits for different
categories. More complex plant are permitted larger
discharges (ranging an order of magnitude) of
pollutant per unit of feedstock. All coke plants,
however, are limited to a single standard, regardless of
process technology or product stream. Petroleum
limits are based on the quantity of feedstock
processed, while coke plants are limited on basis of
the product produced. While fundamentally the latter
type of limit (based on product output) rewards
process efficiency, the conversion efficiency of coal
to coke does not vary enough to make this an
effective incentive. Crude feedstock seems to have
been selected as the basis for petroleum limits
because refinery products are too numerous and
changeable to serve as an acceptable reference basis.
enough to make this an effective incentive. Crude
feedstock seems to have been selected as the basis for
petroleum limits because refinery products are too
numerous and changeable to serve as an acceptable
reference basis.
On the air pollution side, NSPS for processes
related to coal conversion apply to fewer pollutants,
but are specific to individual unit operations (tables
9, 12). For fuel combustion, emissions are limited
either on the basis of heat input rate (boilers) or
pollutant input mass concentration (refinery plant
gas). For process operations, emission limits are based
principally on mass or volume concentration and
opacity. One NSPS also specifies control devices.
Finally, a special class of federally mandated
discharge limitation applies to substances categorized
as hazardous pollutants (air lexicon), or toxic
substances (water lexicon). Such substances are
generally discharged in relatively few and highly
localized locations, but are particularly harmful to
health and require stringent control. Table 13
summarizes substances presently categorized as
hazardous or toxic.
State and Local Regulations
For sources or processes not covered by Federal
new source performance standards (including all
existing stationary air pollution sources), emission
and effluent limitations are established by State and
local agencies, subject to EPA approval except where
such regulations are more stringent than Federal
performance standards, in which case the local
standard takes precedence. For example, 19 States
have adopted regulations for sulfur dioxide emissions
from fossil-fuel-fired steam generators that are more
stringent than the new source performance standard
for solid fuels (ref. 24).
An illustration of the form and variation in State
air pollution regulations is provided in table 14 which
shows selected paniculate, SO2, and NOX standards
for the six eastern coal States noted earlier. For sulfur
recovery plants, the Ohio regulation of 0.01 Ib
SO2/lb S input is the most stringent mass emission
regulation for plant sizes less than 900 tons/day (ref.
8), and corresponds to 99.5 percent control. This is
the regulation suggested by EPA in its guidelines for
State implementation plans (ref. 25). Table 15 shows
emission limitations recently adopted by the State of
New Mexico specifically for coal gasification plants
78
-------
Table 10
NEW SOURCE PERFORMANCE STANDARDS FOR PETROLEUM REFINING
(pounds per 1000 barrels of feedstock)
Pollutant
5-day Biochemical Oxygen Demand
(BODS)
Chemical Oxygen Demand (COD)
Total Organic Carbon (TOC)
Total Suspended Nonfilterable
Solids (TSS)
Ammonia (as N)
Total Chromium (CrT)
Hexavalent Chromium (Cr6)
Oils and Grease
Phenols
Sulfide
Zinc
pH (all categories identical)
30- Day Max**
Range
1.5-6.6
5.3-48.2
1.3-9.2
0.93-4.2
0.30-2.6
0.023-0.106
0.00046-0.0021
0.46-2.1
0.0099-0.046
0.0081-0.038
0.046-0.16
6.0-9.0
One Day Max*
Range
1.85-8.2
6.6-60.2
1.6-11.4
1.2-5.2
0.40-3.4
0.030-0.132
0.00058-0.0026
0.58-2.6
0.014-0.065
0.013-0.059
0.058-0.21
6.0-9.0
*
maximum for any one day
maximum average for dally values of any period of 30
consecutive days
Table 11
NEW SOURCE PERFORMANCE STANDARDS FOR BY-PRODUCT COKE MAKING
(pounds per 1000 pounds of coke)
Pollutant
Cyanides amenable to
chlorination
Phenol
Ammonia (as N)
5-day Biochemical Oxygen
Demand (BODS)
Sulfide
Oil and Grease
Total Suspended Nonfilterable
Solids (TSS)
PH
One Day Max.*
0.0002
0.0004
0.0083
0.0166
0.0003
0.0083
0.0083
6.0-9.0
30 Day Max.**
0.0001
0.0002
0.0042
0.0083
0.0001
0.0042
0.0042
6.0-9.0
maximum for any one day
maximum average of daily values for any period of 30 consecutive
days
79
-------
Table 12. Selected New Source Performance »
Standards (KSPS) for Air Pollution Sources
Source Pollutant Emissions Not to Exceed
STEAM GENERATORS
Fossil-fuel fired Participate Hatter 0.10 lb/106 Btu input
£250 x 106 Btj/hr input 20X opacity
Sulfur Dioxide 1.2 lb/106 Btu
(Solid Fuel)
0.8 lb/106 Btu
(Liquid Fuel)
Nitrogen Oxides 0.7 lb/106 Btu
(as N02) (Solid Fuel)
0.3 lb/106 Btu
(Liquid Fuel)
0.2 lb/106 Btu
(gaseous fuel)
PETROLEUM REFINERIES
Catalytic Cracking Unit Paniculate Hatter 0.027 gr/dscf + 0.10 lb/106
Catalyst Regenerator Btu aux. fuel. 30% opacity.
except for 3 rain/hr
Carbon Monoxide 0.050! by volume
Plant Gas Fuel Sulfur Dioxide 0.10 gr H.S/dscf In fuel gas
Combustion
Petroleum Storage Hydrocarbons Specified Vapor Pressure
Vessels Limits and Required Control
Devices
IRON AND STEEL INDUSTRY
Basic Oxygen Furnaces Participate 0.022 gr/dscf
Hatter
*Refs. 20, 23
Table 13. Hazardous or Toxic Pollutants
AIR" WATER
Asbestos Aldrin and Dieldrin
Beryllium Benzidme and its salts
Mercury Cadmium and its compounds
Cyanide and its compounds
DDE, TDE. DOD. and DOT
Endnn
Mercury and its compounds
PCB's and mixtures of chlorinated
biphe.nyl compounds with various
percentages of chlorination
Toxaphene (chlorinated camphene)
*For specific sources only
80
-------
Table 14.Selected State Emission Regulations for Six Eastern States
State
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
Large Combustion Units
(>1000 ttlDtu/hr)
Participate
(Ib/MMBtu)
0.10
0.10
0.10
0.10
0.10
0.05*
502
(Ib/MMBtu)
1.0 (coal)*
0.8 (resld)
0.3 (dlst.)
1.2*
NSPS*
1.0
0.3 (coal)*
0.2 (oil)*
1.6*
N0x
NSPS
NSPS
NSPS
NSPS
N/A
N/A
General Process Operation
(>500 ton/hr)
Paniculate
(Ib/hr)
67.0
Lesser of 61.0
Ib/hr or 0.10
lb/1000 Ib dls
charge at STP
69.0
69.0
Greater of
0.02 gr/scf
or weight rate
given for
various pro-
cesses
21.2 - 50.0
S02
(ppm)
19.5 P°'67lb/hr
P-tph wst rate)
2000
500*
500*
2000
Sulfur Recovery
Plant
S02
(Ib/lb S Input)
N/A
N/A
N/A
0.01
0.32 E'0-5
(E-long ton/
day)
0.06
• Less stringent limits apply to parts of
the state and/or some types or size of equipment.
Tablel5.Proposed New Mexico Emission Regulations for
Coal Gasification Plants
Gas-Fired Power Plant
Component Associated with Coal
Gasification Plants
Participate Matter 0.03
Sulfur Dioxide 0.15
Nitrogen Oxides 0.20
Non-methane Hydrocarbons
Sulfur (Vapor)
Reduced Sulfur (Sum of hydrogen
sulfide, carbon disulfide,
and carbonyl sulfide)
Hydrogen Cyanide
Hydrogen Chloride and Hydro-
chloric Add
Ammonia
Ib/MMBtu
Ib/MMBtu
Ib/MMBtu*
N/A
N/A
N/A
N/A
N/A
N/A
Gasification
Plants
0.03 Ib/MMBtu
~
--
Nil
0.04 Ib/MMBtu
100 ppm
10 ppm
5 ppm
25 ppm
Adopted as gas-burning equipment emission regulation
**
Becomes 0.008 December 31, 1978
81
-------
conversion processes, all of which require steam and
power that is usually produced by an onsite boiler
plant, often fired by coal or char in present designs.
At the present time, the sulfur content of solid fuels
proposed for boilerhouse use generally exceeds the
Federal NSPS, which is equivalent to about 0.7 to 0.8
percent sulfur. The implication of present regulations,
therefore, is that boiler plants utilizing solid fuels will
likely require either (1) stack gas cleaning systems,
(2) coal or char pretreatment, (3) fluidized bed
combustion, with bed additives to control sulfur, or
(4) conversion of the solid fuel to a low-Btu gas,
followed by gas purification to remove sulfur as H2S.
Further development and demonstration of all four
alternatives, however, is needed to evaluate both the
technology and economics, including the economics
relative to alternatives such as the use of cleaner
synthetic fuel products.
Note too that existing NSPS for SO2 from steam
generators do not include a limitation for gaseous
fuels, such as an H2S-laden low-Btu gas. Such a
standard, however, does exist for combustion of
petroleum refinery plant gas, where SO2 emissions
are restricted by a limitation on H2S content of 0.10
gr/dscf (table 12). For high-Btu gasification processes,
this H2S level is in fact much less stringent than
chemical process requirements, which demand
extremely low sulfur concentrations to avoid
poisoning of methanation catalysts. However for
low-Btu gas used as a boiler fuel, the refinery fuel gas
standard would require more extensive
desulfurization than the present solid and liquid fuel
new source standards for steam generators, the most
stringent of which is presently 0.8 pounds sulfur
dioxide per million Btu (liquid fuels). Combustion of
a low-Btu gas with a heating value of 250 Btu per
cubic foot and an H2S content of 0.10 gr/dscf would
be equivalent to 0.1 pounds S02 per million Btu, or
nearly an order of magnitude more stringent than
existing steam generator standards.
Despite this, some low-Btu gas processes for boiler
fuel are being designed with gas purification systems
to achieve desulfurization only to the level of new
source standards for solid- and liquid-fired boilers.
New regulations in this area may well be more
stringent, with direct implications on the detailed
design and economics of at least some coal conversion
processes. Indeed, tighter regulations have already
been adopted by one State (table 15).
New source paniculate standards for combustion
units do not present the concern occasioned by S02
standards since existing control systems such as
mechanical and electrostatic collection are expected
to be adequate. Nonetheless, paniculate collection
from boilers fired with low-sulfur char or synthetic
liquid fuels has not yet been demonstrated, and such
projects will have to be undertaken before the
implications of new source paniculate standards for
steam generators can be fully assessed.
Standards for nitrogen oxides might also pose
problems for auxiliary boilers. While it has been
clearly demonstrated for fossil-fuel-fired boilers that
NOX emissions can be substantially reduced by
combustion modifications, these are more readily
accomplished for gas- and oil-fired equipment than
for coal-fired boilers. Also full-scale data are not yet
available for boilers fired on char or synthetic liquid
fuels. In the latter case, the relatively high fuel
nitrogen content of some synthetic liquids would
tend to worsen NOX emissions (ref. 8). Again, the
precise implications of new source performance
standards will have to await full-scale demonstration
projects.
For particulate emissions from process unit
operations not presently subject to Federal new
source performance standards, table 12 provides some
indication of the control levels one might expect.
Most of the new source particulate standards
promulgated to date, including a number of
industries not shown in table 9, limit emissions to
approximately 0.02 gr/dscf, or control levels typically
in excess of 99 percent relative to uncontrolled
processes. Applicable technologies include
electrostatic precipitators, high energy scrubbers, and
fabric filters, all of which have been demonstrated to
achieve high degrees of paniculate control.
Secondary Environmental Impacts
Environmental impacts from coal conversion plants
will include various secondary as well as primary
impacts. An example of this is the utility (steam and
power) requirement of gas-cleaning and effluent
treatment systems. Here, the incremental atmospheric
emissions, resulting from boilerhouse fuel consumed
onsite to control process air and water pollution,
funher degrades the air environment.
Tradeoffs are found among pollutants discharged to
a given medium as well as to different media. Many of
these are well known, such as limestone scrubbing of
sulfur dioxide stack gases, which can produce a
potential solid waste disposal problem. Many of these
tradeoffs are difficult to acknowledge in regulatory
policy. This is due to both the existing institutional
arrangements and the basic difficulty of weighing the
relative significance of discharging different
substances to different media.
82
-------
Less understandably, existing regulatory policies
with respect to emission standards also appear to
discourage tradeoffs or incentives to minimize
emissions of the same pollutant to the same medium.
Figure 2 illustrates one secondary impact. It shows
the combined S02 emission rate of the sulfur
recovery tailgas plus that portion of the boilerhouse
stack gas resulting from steam generation for
desulfurization (i.e., onsite steam-generated electric
power plus direct steam requirements). Sulfur
recovery efficiency is assumed to be 99.5 percent, or
an S02 emission rate of 0.01 Ib SO2 per Ib of sulfur
processed. Steam is assumed to be supplied by a
boiler fired with solid fuel, emitting SO2 at the level
of the new source performance standard (1.2
Ib/million Btu). The required net energy addition is
taken as 1.000 Btu per pound of steam produced,
with a boiler thermal efficiency of 80 percent. This
gives a heat input requirement of 1,250 Btu per
pound of steam. A desulfurization system requiring 7
Ib steam/lb S thus causes an incremental SO2
emission at the boiler house of 0.01 Ib SO2/lb S, or
an amount equal in magnitude to the assumed
emission at the tailgas stack. The boilerhouse energy
requirement in f igure 2 is taken over the range of
values reported for several processes desulfurizing
coke oven gas (ref. 26). Low pressure coal gasification
systems would likely have similar energy
requirements, with less energy required for higher
pressure operations.
For this example, the effective control efficiency
decreases by 0.075 percent for each Ib steam/lb S
when additional steam requirements are accounted
for. Thus, a sulfur recovery system with a nominal
recovery efficiency of 99.9 percent requiring 12 Ib of
boilerhouse steam per pound of sulfur processed
effectively operates at 0.9 percent less, or 99.0
percent.
The question of intramedia tradeoffs is also suited
to this example since energy requirements for sulfur
removal increase exponentially with increasing
removal efficiency for many processes. Indeed, it is
easy to envision cases in which a reduction in process
sulfur recovery efficiency (which increases plant
tailgas emissions) could reduce the total plant
emissions (tailgas plus stack gas) because of a more
substantial reduction in boilerhouse energy
requirements. How significant such tradeoffs will
prove to be in practice, of course, remains largely to
be seen, as does the question of how such findings
might influence development of future new source
performance standards. Nevertheless, regulatory
policies in place today would not permit a new coal
conversion plant to implement a favorable tradeoff of
this type, even if it were possible, if it required
relaxing the NSPS for a given unit operation.
Implications of Multiple Regulatory Authorities
Current institutional arrangements for
implementing environmental regulatory policy call
for a sharing of regulatory activities among Federal,
State, and local agencies which are often charged with
only a single area of environmental concern. A case
study can perhaps best illustrate the potential
implications of such an arrangement on coal
conversion processes.
Catch-22: The Allegheny
County Experience
The largest byproduct coke manufacturing facility
in the world is the U.S. Steel facility at Clairton,
Pennsylvania, which processes about 30,000 tons of
coal per day, or several times more than most coal
conversion plants proposed for commercial scale.
Indeed, existing coal processing plants of this size are
few (of the 64 coke plants in the United States only
six process more than 9,200 tpd coal).
For many years, the Clairton coke plant has
operated with zero discharge of a major process
wastewater by using it to quench hot coke. This
complied with a Pennsylvania State regulation
forbidding the discharge of certain contaminants into
the waters of the State. Recently, however, the U.S.
Steel entered into a consent decreee with the U.S.
EPA, the State of Pennsylvania, and Allegheny
County to develop a wastewater treatment system for
coke plant wastes. This major change in operating
practice was brought about by an enforcement action
of the Allegheny County Bureau of Air Pollution
Control, under a local air pollution regulation that
does not permit water to be used for quenching that
is not suitable for discharge to the nearest stream.
Another Allegheny County air pollution regulation
prevents the water quenching of slag--a major
byproduct from the production of pig iron-unless the
discharge to the air of hydrogen sulfide or other
contaminants is prevented. Here too, a major
negotiated control program is underway to solve a
problem which again bears similarities to aspects of at
least some coal conversion processes.
The implication of cases such as this is to strongly
underscore the need for an early and thorough
assessment of process environmental impacts in order
to minimize or avoid future problems. Similarly, the
early and coordinated involvement among local. State
83
-------
20
310
£
if
I5
Ib stean at
bollerhouse
per Ib S
Recovery plant
at S« SI sulfur
removal
100 ZOO 300 (CO
Sulfur Input to Recovery Plant (tons/day)
500
90
80
Equivalent coal tulfur content
of recovery plant feedstraaa
96.0 97.0 Sa.o 99.0
Sulfur Recovery Efficiency (X)
100.0
Fig. 2 Total SO. Emissions fron Sulfur Recovery
Tallgai Plus Ooflcrhoutc Sieia for Sulfur
Recovery (Boiler In compliance Htih NSPS
for solid fossil fuel)
Flg.3 Influence of Coal Typ« and Control Syitea
Efficiency on Equivalent SO. Collisions froa a
Sulfur Recovery'Plant at a 20.000 TonyDay
Coal Convenlon Facility
and Federal regulatory authorities is essential for the
efficient implementation of environmental regulatory
policies.
IMPLICATIONS OF ENVIRONMENTAL
QUALITY STANDARDS
Ambient Air Quality Standards
As noted earlier, national ambient air quality
standards (AAQS) for six major air pollutants have
been promulgated by the U.S. Environmental
Protection Agency (table 5). Individual States have
promulgated other AAQS that apply locally, and may
be more encompassing or more stringent than the
national standards.
The implications of ambient air quality standards
on coal conversion processes go directly to questions
of plant siting. One must consider all regional sources
of air pollution, and the way in which they interact
with the coal conversion plant to affect ambient air
quality at any location. This involves concern for the
geographical distribution of sources, pollutant mass
emission rates, discharge stack heights, process
parameters and local or regional meteorology. Even
where there is ready compliance with all applicable
emission standards, the added constraint of air
quality standards can profoundly restrict the design
flexibility and siting of a particular facility.
Coupling of Emissions
to Air Quality
A simple illustration draws on the case of present
(State) regulations for sulfur recovery plants which
specify a sulfur recovery efficiency by defining the
maximum allowable mass emission rate of SO2 per
mass of sulfur input. Figure 3 indicates how the total
mass emission rate of sulfur dioxide varies with sulfur
recovery efficiency for five different coals at a plant
with a total coal input rate of 20,000 tons per day.
Plants processing different coals in compliance with a
specified sulfur recovery efficiency emit different
total masses of sulfur dioxide, which can have
substantially different impacts on environmental
quality. At a control efficiency of 99.5 percent, a
plant processing a Pittsburgh seam coal with a sulfur
content near 4 percent would emit approximately 8
tons/day of SO2. while the same plant operating on
an eastern Kentucky coal of 1 percent sulfur would
emit about 2 tons/day. Although both plants would
be in compliance with the applicable S02 emission
standard, the former case could result in up to a
four-fold degradation of air quality relative to the
latter case.
A quantitative estimate of the ambient
concentrations resulting from a specified pollutant
mass emission rate can be obtained with diffusion
84
-------
Table 16. Adjusted New Source Performane Standards for
By-Product Coke Making and Petroleum Refining (30-day Maximum)
(pounds of pollutant per 10 Btu feedstock)*
Pollutant Petroleum Refineries
BODS
COD
TOC
TSS
Ammonia (as N)
Total Chromium
Hexavalent Chromium
Oil and Grease
Phenols
Sulfide
Zinc
Cyanide amenable to
Chlorination
230-1015
815-7415
200-1415
143-646
46-400
3.5-16
0.07-0.32
71-323
1.5-7.1
1.2-5.8
7.1-25
N/A
By-Product Coke Making
477
N/A
N/A
242
242
N/A
N/A
242
12
5.8
N/A
5.8
*Assumes heating values of 6.5 MMBtu/bbl for crude oil and 12,000 Btu/lb
for coal, with a coke yield of 0.69 Ib coke/lb coal.
N/A not applicable
and auxiliary boilers, in anticipation of two
Lurgi-based gasification plants scheduled for
construction. These are presently the only State
regulations directed at coal conversion processing.
For water pollutants, State and local standards will
generally not be as stringent as Federal effluent
guidelines, although some exceptions can be
expected. Pennsylvania, for example, presently
permits no measurable discharge of cyanide or phenol
into waters of the Commonwealth.
IMPLICATIONS OF PRESENT EMISSION AND
EFFLUENT STANDARDS FOR FUTURE COAL
CONVERSION PROCESSES
Current regulatory activities suggest that coal
conversion processes will be subject to separate
emission and effluent limitations in much the same
way that new sources in various industrial categories
are presently regulated. Although this may not be the
optimal regulatory framework in which to minimize
the environmental impact of coal conversion
factilities, current policy points strongly in this
direction, at least for the immediate future. It is
useful, then, to examine the implications that existing
emission and effluent limitations will or could have
on coal conversion processes.
Implications of Existing National Effluent Standards
Some insights as to the nature of effluent standards
for coal conversion processes can be obtained by
comparing the new source performance standards for
the related industries of byproduct coke making and
petroleum refineries, shown earlier (tables 10 and
11). The two sets of standards may be compared
directly by expressing them on the common basis of
energy input of the process feedstock (table 16). For
this comparison, crude oil is assumed to have a
heating value of 6.5 million Btu/bbl. Standards for
coke making based on coke produced are transformed
to a heat input basis assuming each ton of coal yields
0.69 tons of coke (the national average), and
assuming coal has a heating value of 12,000 Btu/lb.
The range of the limits for petroleum refineries in
table 16 again reflects the philosophy of setting
separate limits that depend on process technology
and product mix for refineries. No such range exists
for coke making. However, with the exception of the
phenol limit, which is higher for coking, and cyanide
which is not explicitly limited for refineries, all coke
industry limits fall within the range of the petroleum
refinery limits. While these relationships may be
85
-------
fortuitous, they may also suggest a basis for
estimating potential effluent standards for coal
conversion processes. Nonetheless, since the suggested
limitations in fact range over an order of magnitude
for some pollutants, the capability and cost of
achieving specific effluent guidelines will still depend
strongly on the actual performance of individual
processes.
In this regard, it is also unclear whether one might
expect a range of regulations for coal conversion
effluents, perhaps based on output products, in such
a way as to reward process efficiency. It is similarly
uncertain whether more complex plants will be
subject to "end-of-the-pipe" effluent standards,
which permit internal decisions for controlling
effluent compositions, or to separate standards for
selected processes or unit operations. Byproduct coke
making, for example, is often an integral part of a
steel manufacturing plant, yet its wastewaters are
regulated separately from those of iron or steel
making processes which discharge the same pollutants
into the same pipe at the same plant.
Implications of Existing National Emission Standards
Of the several existing new source standards for air
pollutants, those for fossil-fuel-fired steam generators
(table 12) will have a direct bearing on coal
modeling techniques. Figure 4 shows isopleths of
annual average groundlevel SO2 concentration for a
hypothetical coal conversion plant located in
southwestern Pennsylvania, predicted by the Air
Quality Display Model (ref. 27). The plant is assumed
to have two sources of S02 emissions. One is the
stack gas of a boiler operating in compliance with the
NSPS of 1.2 Ib SO3/million Btu input for solid fossil
fuel at a heat input rate of 2,500 million Btu/hour
(yielding an emission of 36.0 tons of SO?/day). The
second is the tail gas stream of a sulfur recovery plant
processing 500 short tons per day of sulfur at a
required recovery efficiency of 99.9 percent (yielding
an S02 emission of 1.0 ton/day). The two sources are
assumed to be at approximately the same location,
with effective stack heights of 400 feet and 200 feet,
respectively. For these conditions, the predicted
maximum annual average SO2 concentration is 37
M9/rn3, or nearly half the national primary standard,
without considering the added contribution of nearby
or background sources. Increases in the assumed stack
heights, however, would significantly
decrease groundlevel concentration.
Figure 5 isolates the annual S02 concentration due
only to tailgas emissions plus that part of boilerhouse
emissions required for sulfur recovery, where steam
requirements are assumed to be 12 Ib/lb S
Flg.4. Annual Average SO. Concentration (/jg/n J
for a Hypothetical Coal Conversion Plant
(A Indicates source location)
Annual Average SO. Concentration
(jjg/irr) Due Only to Combined
Effect of Tailgas Emission Plus
Bollerhousp Steam for Sulfur
Recovery System
86
-------
(contributing 9.0 tons/day to total SO2 emission).
Approximately 80 percent of the peak concentration
here is due to the boilerhouse SO2 emission.
Implications of Nondegradation
Standards
The present Federal mandate to prevent
"significant deterioration" of clean air is a
particularly crucial issue in terms of the implications
of environmental policy on coal conversion processes.
Indeed, the tentative levels of incremental
degradation shown earlier in table 7 would preclude
operation of the hypothetical plant of figure 4 in
many areas of the country. Alternately, they would
demand more stringent emission controls, alternative
cleaner fuels and/or taller stacks to reduce ambient
concentrations adequately. Nondegradation policies
of the type presently being contemplated, therefore,
may well pose the most critical constraints on the
siting and design of coal conversion facilities.
Impacts on Receiving Water Quality
It was indicated earlier that receiving water quality
standards are in practice not as strongly coupled to
discharge standards as are air quality and emission
standards. Nonetheless, water quality considerations
are indeed present and must be considered.
One assessment of the environmental impact of
water pollutant discharge from coal conversion
facilities may be obtained by examining the relative
quantities of emissions of the same pollutant from all
sources in a given region. For water problems, it is
most reasonable to examine a watershed. Table 17
lists the distribution of refineries and byproduct coke
plants in a six-State region that affects the watershed
primarily of the Ohio River. The list includes all
facilities in the State, not just those discharging into
the Ohio River and its tributaries. Nevertheless, the
methodology provides a key to assessment. This
six-State region holds more than one-fifth of the U.S.
petroleum refinery crude capacity, as well as slightly
less than two-thirds of the country's byproduct coke
capacity.
Table 18 estimates the total regional burden of
selected pollutants for a situation in which six new
20,000 ton/day coal conversion plants are assumed to
be sited in the region (an average of one per State),
with all sources complying with the NSPS indicated
in the table. In terms of total effluent quantities, six
plants would contribute as much as either coking or
refineries. This comparison does not, of course, deal
with the more important problem of the local impact
of each individual facility, which is expected to be
considerable when one considers that such plants are
of size comparable to the Clairton coke plant.
However, the estimate of total regional emissions
does provide some perspective of the impact of new
coal conversion facilities for this eastern area.
SUMMARY AND CONCLUSIONS
These discussions have examined detailed aspects of
current environmental regulatory policy for air and
water pollution control as they are likely to bear on
coal conversion processes presently under
development in this country. The discussions focused
on the types and levels of controls likely to be
required, and attempted to illustrate existing or
potential areas of conflicts among standards for air
and water discharges, and levels of environmental
quality.
The analysis suggests a series of questions requiring
further consideration and study in the development
of coal conversion plant regulatory policies:
• To what extent is a multimedia (air, water,
land, etc.) approach to environmental control
necessary? How do we evaluate cross-media
tradeoffs7
• Within a single medium, is it necessary to
allocate waste loads according to specific
processes or unit operations? Can a "total
plant" standard lead to less severe
environmental degradation?
• How should plant size and product mix enter
into the regulatory picture? Can incentives be
structured to reward process efficiencies that
reduce environmental impact?
• Can the existing U.S. regulatory structure be
modified to streamline policy formulation and
avoid or minimize jurisdictional conflicts
(Federal vs. State vs. local; air vs. water vs.
other)?
Clearly, these questions are by no means unique to
coal conversion processes, but in fact could be
applied to virtually any of our existing industries.
What makes this particularly relevant to coal
conversion, however, is that we are in this case
speaking of a potentially large-scale industry whose
environmental impacts can be significant, but which
is at present less constrained and encumbered relative
to other industries, hence, better able to respond to
environmental concerns.
In large part, the key to success will lie in the early
recognition of environmental factors, and in the
integration of environmental and process
considerations. Indeed, the substance of the case for
87
-------
Table 17. Distribution of Coke Plants and Petroleum
Refineries for the Six Major Eastern Coal States
No. of
State Refineries
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
Total USA
10
9
3
8
12
2
44
247
1971 Refinery
Capaci ty*
(1000 bbl/day)
908
558
163
572
683
11
2895
13000
No. of No. of
Coke Plants Ovens
5
6
1
13
12
3
40
64**
455
2361
146
1796
3491
668
8917
4255
*Ref. 29.
**The 64 coke plants process about 82 million tons of coal per year.
Table 18. Estimated Total Wastewater Emissions of Selected Pollutants
for a Six-State Region
(pounds per day based on 30-day average NSPS limits)
Pollutant
Phenols
Ammonia
8005
TSS
Oil & Grease
Refineries*
30-138
900-7,800
4,500-145,000
2,790-12,600
1,380-6,300
Coke Plants**
39
1638
2910
1638
1638
Coal Conversion Plants***
33
1378
2756
1378
1378
*Assumes 22 percent (3 million bbl/day) of U.S. crude flow is processed in the
six-state region with range of emissions depending on process technology mix.
**Assumes 63 percent (52 million tons/yr of coal) of U.S. by-product coke is
processed in the six-state region.
***Assumes six 20,000 ton/day plants (120,000 tons of coal per day, total) oper-
ating at NSPS limits for coke plants over the six-state region.
-------
careful assesssment and management of the
environmental problems of coal conversion processes
was summarized recently in a report on the "Nation's
Energy Future" (ref. 1) and bears repeating here:
"Disruption of the energy program can be
prevented by anticipating potential problems
related to each technology and by determining as
rapidly as possible the effects on health,
ecosystems, and society- Perhaps the largest
barrier to be faced is the need to convince
energy-related technologists and planners that
this seemingly distract!ve commitment must be
made at the outset to prevent very major
disruptions in energy production."
REFERENCES
1, "The Nation's Energy Future," report No.
WASH-1281, report to the President of the
United States, Submitted by Dr. Dixie Lee Ray,
Chairman AEC, December 1,1973.
2. S. W. Gouse. and E. S. Rubin, "A Program of
Research, Development, and Demonstration for
Enhancing Coal Utilization to Meet National
Energy Needs," CMU/NSF-RANN Workshop on
Advanced Coal Technology, Carnegie-Mellon
University, Pittsburgh. NTIS No. PB-226 631,
October 1973.
3. "The Implications of Self-Sufficiency Energy
Policies for Environmental Research," Report of
the Panel on Technology and Environmental
Impact, Chemist-Meteorologist Workshop 1974,
Wash. 1217-74, U.S. AEC/EPA, Ft. Lauderdale,
Florida, January 14-18,1974.
4. Supply Technology Advisory Task Force Report
on Synthetic Gas from Coal, FPC-622, Federal
Power Commission, Washington, D. C., 1973.
5. E. M. Magee, C. E. Jahnig, and H. Shaw,
"Evaluation of Pollution Control in Fossil Fuel
Conversion Processes, Gasification; Section
1: Kop pe rs -To t ze k Process,''
EPA-650/2-74-009a, E.P.A., Washington. D.C.,
January 1974.
6. A. J. Forney et al.. "Analysis of Tars, Chars.
Gases, and Water Found in Effluents from the
Synthane Process," Bureau of Mines TPR-76,
U.S. Dept. of Interior, January 1974.
7. "Project Description and Environmental
Assessment, Development Coal Gasifier
Project," El Paso National Gas Company, Texas,
August 1973.
& S. W. Angrist, L. L. Lynn, F. C. McMichael, E.
S. Rubin, and A. S. Walters, "Systems Analysis
of the Solvent Refined Coal Process,"
Environmental Studies Institute,
Carnegie-Mellon University. Pittsburgh, Pa.; also
Report to the Pittsburg and Midway Coal
Company, Merriam, Kansas, November 1973.
9. State of New Mexico Air Pollution Regulations.
Environmental Improvement Agency, Santa Fe,
N.M.
10. H. Schultz et al., 'The Fate of Some Trace
Elements During Coal Pre-Treatment and
Combustion," Amer. Chem. Soc., Div. of Fuel
Chemistry. Vol. 8, No. 4 (August 1973).
11. A. Attari, 'The Fate of Trace Constituents of
Coal During Gasification," EPA-650/2-73-004,
E.P.A.. Washington, D.C.. August 1973.
12. C. E. Billings et al., "Mercury Balance on a
Large Pulverized Coal-Fired Furnace,"
J.A.P.C.A.. Vol. 23. No. 9, (September 1973).
13. N. E. Bolton et al., 'Trace Element Mass
Balance Around a Coal-Fired Steam Plant," ACS
Div. of Fuel Chem., Vol. 8, No. 4, (August
1973).
14. P. J. Wilson, Jr., and J. H. Wells, Coal, Coke and
Coal Chemicals, McGraw-Hill, New York, 1950.
15. J. E. Barker, R. J. Thompson. W. R. Samples,
and F. C. McMichael, "Biological Removal of
Carbon and Nitrogen Compounds from Coke
Plant Wastes." EPA-R2-73-167, E.P.A.,
Washington, D.C., April 1973.
16. "A Report on Pollution of the Ohio River and
its Tributaries in the Pittsburgh, Pennsylvania,
Area," U.S. Environmental Protection Agency,
Region 111,1971.
17. "National Primary and Secondary Air Quality
Standards," Federal Register. Vol. 36. No. 84,
(April 30,1971).
18. "Prevention of Significant Air Quality
Deterioration," Federal Register, Vol. 38, No.
135, July 16,1973.
19. Energy Resources Report, Silver Springs, Md.,
February 22, 1974.
20. "Petroleum Refining Point Source Categories,
Proposed Effluent Limitation Guidelines and
New Source Standards." Part II. Federal
Register, Vol. 38, No. 24, (December 14, 1973),
pp. 34541-34558.
21. "Iron and Steel Point Source Category.
Proposed Effluent Limitations, Guidelines and
New Source Standards," Part III. Federal
Register, Vol. 39, No. 34, (February 19,1974).
22. "Standards of Performance for New Stationary
Sources," Federal Register, Vol. 36, No. 247,
(December 23, 1971).
-------
23. "Standards of Performance for New Stationary 30.
Sources," Part II, Federal Register. Vol. 39, No.
47, (March 8, 1974).
24. L. J. Duncan, "Analysis of Final State
Implementation Plans-Rules and Regulations," 31.
APTD-1334, E.P.A., Washington, D.C., July
1972.
25. "Requirements for Preparation, Adoption, and
Submittal of Implementation Plans," Part II,
Federal Register Vol. 36, No. 158, (August 14,
1971). 32.
26. M. J. Massey and R. W. Dunlap, "Economics
and Alternatives for Sulfur Removal from Coke
Oven Gas," Paper No. 74-184, 67th Annual
Meeting, Air Poll. Control Assn., Denver, Colo.,
June 9-13, 1974. 33.
27. Air Quality Display Model, prepared for EPA by
TRW Systems Group on Contract No.
PH-22-68-60, November 1969. 34.
28. "United States Energy Fact Sheets 1971," U.S.
Dept. of Interior, Washington. D.C.
29. "Proposed Toxic Pollutant Effluent Standards,"
Federal Register. Vol. 38, No. 247, (December
27, 1973).
"Steam Electric Power Generating Point Source
Category, Proposed Effluent Guidelines and
Standards," Federal Register. Vol. 39, No. 43,
(March 4, 1974).
R. W. Dunlap, W. L. Gorr, and M. J. Massey,
'' D e s u I f u r i z at ion of Coke Oven
Gas: Technology, Economics, and Regulatory
Activity," The Steel Industry and the
Environment, J. Szekely (ed.). Marcel Dekker,
New York. 1973.
E. J. Cleary, 'The ORSANCO Story: Water
Quality Management in the Ohio Valley under
an Interstate compact," Resources for the
Future, Inc., Baltimore, Johns Hopkins Press,
1967.
"National Emission Standards for Hazardous Air
Pollutants." Part II. Federal Register, Vol. 38,
No. 66, (April 6, 1973).
"State Air Laws," Environment Reporter,
Bureau of National Affairs, Inc., Washington,
D.C.. 1972.
90
-------
ENVIRONMENTAL ASPECTS OF EL PASO'S
BURNHAM I COAL GASIFICATION COMPLEX
Cecil R. Gibson,
Gene A. Mammons, and
Don S. Cameron *
Abstract
The El Paso Natural Gas Company plans to build a
fuel conversion complex, utilizing proprietary
technology supplied by Lurgi Mineraloltechnik
GMBH and others. This complex will convert coal to
high-Btu pipeline quality gas. The basic processes
utilized in the complex will be reviewed briefly.
The quality, quantity, and composition of the
effluent streams from the complex will be presented.
Over 98 percent of the sulfur in the feed to the
complex will be recovered. Maximum use of water
will be achieved by recycling all reclaimable internal
effluents. Aqueous waste streams which cannot be
recycled will be discharged to evaporation ponds.
El Paso's Bumham I Coal Gasification Complex has
been designed to meet all applicable environmental
standards. Extensive studies designed to obtain data
on the existing environment are being conducted to
add to the existing knowledge of the area.
INTRODUCTION
Coal is the most abundant source of fossil fuel
energy in the United States. Combustion of coal
often results in unacceptable levels of pollutants;
therefore, various methods of utilizing coal while
producing minimum pollutants are being examined.
The conversion of coal into a gas which is
interchangeable with natural gas (synthetic natural
gas or SNG) is one means of producing clean energy
from coal and producing minimum air and water
pollutants. El Paso Natural Gas Company plans to
build a plant in Northwestern New Mexico which will
convert 28,254 tons of coal per day into 288 million
scfd of SNG. The plant will be based on Lurgi
technology. This facility, named the Burn ham Coal
Gasification Complex, is estimated to cost about
$605 million, based on mid-1973 dollars. The plant.
including all utilities, will have a gross investment of
*C. R. Gibson is Chief Engineer of the Solids Gasification
Section of the Chemical Engineering Division of El Paso
Natural Gas Company. G. A. Mammons and 0 S. Cameron
are Senior Chemical Engineers with El Paso Natural Gas
Company.
$491 million, and the mine and coal preparation
facilities will have a gross investment of $114 million.
The product gas from this plant, which will have a
heating value of 954 Btu/cf, will be delivered to El
Paso's mainline system at a 25-year average cost of
about $1.17/mcf.
Oxygen-blown Lurgi gasifiers, as illustrated in
figure 1, will be used to produce a medium-Btu
(appoximatety 320 Btu/scf) gas from coal. Since coal
is deficient in hydrogen (as compared to methane),
large quantities of steam are also utilized in the
gasifier as a hydrogen source. The primary processing
units required to upgrade the medium-Btu gas to SNG
are illustrated in figure 2.
Airblown Lurgi gasifiers will be used to produce a
fuel gas (approximately 190 Btu/scf). This gas will be
used to fuel the gas turbines and steam boilers and
thus produce the electricity and steam requirements
for the plant.
CONTROL OF AIR POLLUTANTS
The State of New Mexico air pollution emission
regulations with which the Burnham Complex must
comply are illustrated in table 1.
Sulfur Control
A sulfur balance around the High-Btu Gas
Production sections of the Burnham Complex is
shown in figure 3. The proposed New Mexico
regulations, both on total sulfur and on reduced
sulfur, are achieved.
The bulk of the inlet sulfur with the coal,
approximately 95 percent is converted to H2S in the
gasifier. Approximately equilibrium amounts of H2S,
COS. CS2, mercaptans, and the thiophenes (C4H4S)
are formed. The percentage of the sulfur in the input
coal which is converted to each of the gaseous organic
sulfur compounds is given in table 2. The other
organic sulfur is thus primarily mercaptans, since the
equilibrium constants for the formation of CS2 and
thiophenes are fairly small.
Before any of the sulfur compounds are removed, a
portion of the raw synthesis gas is passed through a
Lurgi Crude Gas Shift Unit. The gas quantity through
91
-------
ff ED COAL
ORIVf
SCRUBBING
COOLER
FIGURE 1
THE IDROI SASlfltR
CAS
WATCH JACKET
FIGURE 3
PROCESSES REOUIBED TO UPGRADE
HAW OAS (330 BTU/5CFI TO SMC («M BTU/SCF)
ITiAM
OXYGEN
GASIF CATION
»^IFT
CONVERSION
1
[
GAS
COOLING
RECTISOL
METHANATIOH
. QUALITY
OAS
CONVERSION OF
GOAL. STEAM.
AND OXYGEN
WTO A MEDIUM
ITU GAS
OK ITU/5CFI
PROVIDE HYDROGEN
REQUIRED TO PREVENT
CARSON FORMATION
IN METHANATION.
COOL GAS
PRIOR TO
RECTISOL
REMOVE CO}.
»f, AND ORGANIC
SULFUR PRIOR
TO METHANATim
CONVERT CO.
CO). AND H]
INTOCH,
92
-------
Table 1. State of New Mexico air pollution emission regulations
Gas-fired boilers
Sulfur dioxide emissions
Nitrogen dioxide emissions
Particulate emissions
Coal gasification plant
Sulfur emissions
Hydrogen sulfide, carbon disulfide,
and carbonyl sulfide emissions
0.16 Ib/MM Btu fired (LHV basis)
0.20 Ib/MM Btu fired (Ihv Basis)
0.03 Ib/MM Btu bired (LHV basis)
0.03 Ib/MM Btu fired (LVH basis)
100 ppm by volume (total)
FIGURE 3
SULFUR BALANCE FOR MANUFACTURE
OF HIGH BTU GAS
SULFUR W/COAL
UHOLBJMR
SULFUR FLAMT VENT
lOeLBJWfl
SULFUR PLANT
INCINERATOR
BLUHR
HIGH ITU GAS
PRODUCTION
PROCESSES
BV PRODUCT SULFUR
11S04 LBJHR
BY PRODUCT TAR
340LB.SHR
BY PRODUCT TAR-OIL
IlLUMR
BT PRODUCT NAPTHA
ttLBJHR
NOTE II ALL FIGURES ARE IN LB/HR at SULFUR
H EMISSION CALCULATES AS 000IW LB SflKW BTU OF INLET COAL
tl SULFUR PLANT VENT is REDUCED SULFUR WITH CONCENTRATION
LESS THAN 100 VPPM
93
-------
Table 2. Estimated quantities of
sulfur compounds in the product gas
from a Lurgi gasifier
% of sulfur in input
coal which appears
Compound in product gas as
H2S
COS
cs2
Mercaptans
Thiophenes
95.0
2.4
0.3
2.0
0.3
Total
100.0
shift is set by the H2 to CO ratio required in
methanation, and, for the Burnham Complex,
approximately 50 to 60 percent of the total gas is
shifted. In the Shift Unit, the unreacted steam is used
to produce H2 by water-gas shift reaction:
+CO2
(1)
Since organic sulfur may be hydrolyzed to H2S and
C02 at elevated temperatures (300° to 750°F), that
portion of the gas which goes through shift has
essentially equilibrium conversion of the organic
sulfur. Table 3 illustrates the approximate
equilibrium conversions of various organic sulfur
compounds to H2S at approximately 720°F.
The converted gas from shift, and from the crude
gas bypass are recombined and cooled prior to the gas
purification step. During this cooling step, gas liquor
is condensed which contains water and a number of
other coal carbonization products. Following cooling,
the raw synthesis gas is purified in a Lurgi Rectisol
unit. In this unit, the C02, H2S, and organic sulfur
compounds are removed from the gas by absorption
in cold methanol. The Rectisol process has the
following advantages for this application:
(1) It removes saturated and unsaturated
hydrocarbons without contaminating the
solvent beyond regeneration.
(2) It removes sulfur compounds, both H2Sand
organic sulfur compounds, to less than 0.2
vppm; a Rectisol unit at South African Coal,
Oil, and Gas Corporation (SASOL) has
achieved sulfur removal to 0.007 vppm.
(3) It effectively removes HCN.
Table 3. Equilibrium organic sulfur
conversion in shift unit
% conversion
Compound
to H2S
COS
cs2
RSH
63
100
100
100
(4) The methanol solvent will not contaminate
the methanation catalyst.
(5) It is currently in use to treat the gas from
Lurgi pressure gasification. At the SASOL
plant, sulfur-sensitive Fisher-Tropsch catalyst
are utilized immediately following the
Rectisol unit.
In the Burnham Complex, the offgas from the
Rectisol solvent regeneration section has the
approximate composition shown in table 4. The
concentration of H2S, as shown in table 4, is far too
low to be used as a Claus plant feed. Normally, the
feed to a Claus unit contains a minimum of 12
percent H2S. Although this stream could be
concentrated, economic studies have indicated that it
would be better to use the Stretford Process in the
Table 4. Kectisol offgas
composition
Component
Mol
co_
2
H.S
2
C2H4
CO
H0
2
CH.
4
C2H6
N- + A
2
97.63
0.75
0.24
0.07
0.43
0.56
0.32
__
Total 100.00
94
-------
Burn ham Complex. This process converts the H2S
and a portion of the organic sulfur to elemental sulfur
by the following reactions:
(2)
(3)
v's+) Reduced ADA (4)
Reduced ADA + O2 <» ADA + H2 O (5)
This process will give the Burnham Complex
approximately 99 percent overall sulfur recovery so
as to meet all applicable sulfur emission regulations.
Coal-fired boilers will not be used in the Burnham
Complex. Thus, the problem of finding a workable
stack gas scrubbing system will be avoided. A power
and steam generating system using airblown Lurgi
gasifiers to fuel both gas turbines and waste heat
boilers will be used. Since the sulfur in the coal is
converted primarily to H2S in a Lurgi gasifier, high
sulfur removal efficiency can be attained.
A sulfur balance around the steam and power
generation system for the Burnham Complex is
illustrated in figure 4. The expected emissions are
0.13 lb/106 Btu, considerably below the New Mexico
and Federal regulations of 0.16 lb/106 Btu.
The Stretford process will be used to remove the
H2S from the fuel gas. This Stretford absorber will
operate at about 250 psig. as opposed to atmospheric
operation of the Stretford absorber in the high-Btu
gas production area. The chemical reactions occurring
are the same as previously described.
Paniculate Control
The coal charged to a Lurgi gasifier is typically in
the size range of 1% X V* inches. Any of the fine coal
which is blown out of the gasifier by the upflowing
gas is removed from the gas in a water scrubber
immediately following the gasifier. This coal dust
tends to collect in the condensed tar. which is
recycled to the gasifier. Particulate emissions from
the processing area are thus negligible.
Coal gasification is a particularly attractive means
of controlling paniculate emissions in the utilization
of low-sulfur Western coal. Precipitator efficiency has
been demonstrated many times to be very poor when
operating on low-sulfur coals.
Particulate emissions in the coal crushing and
conveying areas will be kept to a minimum. The coal
on the conveyors will be sprayed with water at
transfer points to minimize paniculate emissions.
Nitrogen Oxide Control
Fuel nitrogen has been reported (refs. 1.2) to be
more reactive for the production of nitrogen oxides
(NOX control techniques, such as two-stage firing,
have been reported (refs. 1,2) to be less effective on
nitrogen-containing fuels, such as coal.
FIGURE 4
SULFUR BALANCE FOR MANUFACTURE
OF LOO BTU FUEL CAS
SULFUR W/COAL
MNLB^MR
TURBINE'S BOILER STACKS
141 LBJHR
STEAM SUPERHEATED
' STACK
IOL8JHR
FUEL GAS
PRODUCTION
-, FUEL OAS HEATER STACK
^^ • LB./MR
. BY PRODUCT SULFUR
1701 IBJMR
NOTE II ALL FIGURES ARE IN LB./HR OF SULFUR
1) EMISSION CALCULATES AS 0 1KB LB£Oj/MM BTU FIRED
95
-------
to
CO
WATER
7056
HP STEAM
3564 r
MOISTURE fc
IN COAL "^
630
HP STEAM
S16
MOISTURE IN fc
COAL 13S "^
MOISTURE fc
IN AIH 6
1
WATER TREATING.
HIGH AND LOW
PRESSURE BOILERS
HIGH BTU GAS
PRODUCTION
PURIFICATION
AND
METHANATION
*
REACTED WATER
1897
FUEL GAS
PRODUCTION
AND
PURIFICATION
1
REACTED WATER
237
MINE AND
OFFSITE USERS
1289
FIGURE 5
SIMPLIFIED WATER FLOW DIAGRAM
FOR THE BURNHAM COMPLEX
• BOILER. WATER TREATING
1 SLOWDOWN. EVAPORATION
f687
OTHERS
170
TARRV OILY CONDENSATE
2497 CONDENSATE _ GAS I-IOUOR 2378
WET
ASH
380
WET <
ASH
-------
FIGURE 6
TAR AND TAR-OIL SEPARATION SYSTEM
-------
The nitrogen in coal is converted primarily to NH3
in a Lurgi gasifier. In the fuel gas production system
for the Burnham Complex, most of the NH3 will be
removed with the condensate prior to the Stretford
unit. The inlet temperature to the Stretford unit is
90°F. Thus, essentially no fuel nitrogen or ammonia
will be combusted in the gas turbines or waste heat
boilers. The absence of fuel nitrogen combined with
the reduced flame temperatures (both in the turbine
and waste heat boiler), due to the low heating value
of the fuel gas, will allow us to achieve the New
Mexico and Federal regulation of 0.20 lb/106 Btu
HHV(asN02).
CONTROL OF WATER POLLUTANTS
Steam in excess of that required for reaction is
generally supplied to a Lurgi gasifier. This excess
steam is required to maintain the desired temperature
profile in the gasifier. The unreacted steam exits the
gasifier with the raw gas. A part of the excess steam is
required as a reactant in the shift conversion unit,
while the remainder is condensed from the gas, along
with the tar, tar oil, ammonia, phenols, other organic
compounds, and acid gases.
In the Burnham Complex, the condensed excess
steam will be purified to the extent required for use
as cooling tower makeup water. A simplified water
balance for the Burnham Complex is shown in figure
5. Approximately 2,379 gpm will be purified and
reused as cooling tower makeup. About 329 gpm of
condensate will be separated because of its high
halogen, phenol, and other organic compound
concentrations and sent to solar evaporation ponds.
This high solids condensate is estimated to contain a
high percentage of the chloride and fluoride in the
coal. This percentage is a strong function of the
temperature level at which the separation is made. By
separating the halogens, the quality of the remainder
of the "clean" condensate (2,379 gpm) is
considerably improved for usage as cooling tower
makeup water.
Boiler blowdown and cooling tower blowdown are
also sent to solar evaporation ponds after being used
as sluicewater in the ash-handling system.
Water reclamation techniques are being examined.
Any of the water presently being sent to evaporation
ponds will be reclaimed if economically feasible.
Tar and Tar Oil Removal
The top portion of a Lurgi gasifier acts as a
distillation section in which large quantities of tar and
tar oil are produced. These products are carried from
the gasifier with the raw gas and are subsequently
condensed from the gas. A Lurgi designed tar-oil
separation unit will be utilized to separate tar and oil
from the waste water. A schematic diagram of this
system is shown in figure 6. The separators utilize the
specific gravity difference between tar, oil, and water
to effect a separation. Tar is defined as being all
organics heavier than water, and oil is defined as
being all organics lighter than water. The expected
quantities of tar and tar oil to be produced in the
Burnham Complex also are shown in figure 6.
As illustrated in figure 6, there will be two tar-oil
separation systems, one of which will handle the high
solids (high halogen) condensate, and the other will
handle the "clean" condensate (low solids). After
tar-oil separation, each of these condensate streams
will be sent to the Phenosolvan area, a proprietary
Lurgi process for the extraction of phenols and
removal of acid gases.
Phenol Removal
In the Phenosolvan process, isopropyl ether is used
as a solvent to extract phenols and other organic
compounds from the waste water. As illustrated in
figure 7, Lurgi guarantees a maximum of 20 ppm of
steam volatile phenols in the effluent water.
Separate extractors will be utilized for the high
solids and low solids condensate streams.
Ammonia and Acid Gas Removal
Before the waste water can be used as cooling
tower makeup, the acid gases (CO2 and H2S) and
ammonia must be stripped out of the water. In the
Burnham Complex, the acid gases will be stripped
from the water in a reboiled, pressurized column. The
overhead from this deacidifier has the composition
shown in table 5. The gas is sent to the low pressure
Stretford absorber, where 99.9 percent of the H2S is
converted to elemental suflur.
Following acid gas removal, the ammonia will be
stripped from the waste water, and the stripped gases
will be condensed as an aqueous ammonia solution.
About 250 tons per day of anhydrous ammonia could
be produced from this stream. The water from the
bottom of the ammonia stripper will be used as
cooling tower makeup water. El Paso has simulated
this water composition at the SASOL plant and has
been studying the operabihty of a test cooling tower
and heat exchanger for about one year. The results of
these tests are being used to study the characteristics
98
-------
FIGURE 7
PHENOL EXTRACTION SECTION
FRESH SOLVENT
MAKE UP
CLEAN
GAS LIQUOR
HIGH SOLIDS
GAS LIQUOR
EXTRACTOR
RECOVERED
SOLVENT
EXTRACT
GRAVEL
FILTER
I
DEPHENOLIZED
GAS LIQUOR-TO
COOLING TOWER
MAX 20 PPM
STEAM VOLATILE
PHENOLS
EXTRACTOR
EXTRACT
11.271 LBJHR
OF CRUDE
PHENOLS
RECOVERED
DEPHENOLIZED
GAS LIQUOR
TO EVAPORATION
POND
EXTRACT TO
PHENOL AND
SOLVENT SEPARATION
-------
Table 5. Composition of acid gases
stripped from gas liquor
Component
Mol % (dry)
co_
2
H0S
2
95.91
4.09
Total 100.00
Total dry gas = 8,853 Ib mols/hr
of the Burnham cooling water system, such as
allowable cycles of concentration, foaming tendency,
slime buildup in tower, and heat transfer
characteristics of the test heat exchanger.
SUMMARY
El Paso Natural Gas Company has designed the
Burnham Coal Gasification Complex with full
consideration to minimizing air and water pollutant
emissions. Sulfur emissions in the high-Btu gas
production areas will be minimized by utilizing the
Stretford Process to remove the H2S from the acid
gas from the Rectisol plant. Lurgi gasifiers will be
used to produce a fuel gas. and a high pressure
Stretford unit will be used to effectively remove the
H2S from this fuel gas. This fuel gas system will
provide the fuel for steam and power production. A
coal-fired boiler-stack gas scrubbing system will not
be utilized. Paniculate emissions from the Burnham
Complex will be low, since 1% inch X '/& inch coal is
typically fed to Lurgi. gasifiers. The prevailing NOX
regulations will be easily achieved with the planned
low-Btu gas power and steam generating systems.
Water pollutants will be minimized through the use
of proprietary Lurgi processes for the removal of tar,
tar oil, phenols, and acid gases from the gas liquor
(dirty condensate). Water reuse will be maximized by
utilizing much of the gas liquor as cooling tower
makeup water.
REFERENCES
1. Milton R. Beychok, "NOX Emissions From Fuel
Combustion Controlled," The Oil and Gas
Journal, February 26, 1973, pp. 49-56.
2. W. Bartok et al., "Systematic Field Study of NOX
Emission Control Methods for Utility Boilers,"
ESSO Research and Engineering for the EPA,
National Technical Information Service (NTIS)
PB-210 739, December 31,1971.
100
-------
ENVIRONMENTAL ASPECTS OF THE WESCO
COAL GASIFICATION PLANT
Thomas E. Berty and James M. Moe*
Abstract
Some of the essential processing factors in the
Lurgi gasification process are very briefly reviewed.
The quantity and types of byproducts are described,
and the environmentally related problems are
presented. The efforts to conserve water are
discussed, and the manner in which the air quality
standards are achieved is described in detail.
INTRODUCTION
of the water from the gas. This aqueous mixture
(called gas-liquor) is processed by the Phenosolvan
unit and the gas-liquor unit.
The partially purified gas stream, after cooling, is
treated in the Rectisol plant to remove acid gas
constituents: CO2, H2S, COS, CS2, and HCN. After
this treatment, the gas is a very pure mixture of CO,
CO?. H2. and ChU which is then upgraded to pipeline
quality SNG by the methanation unit.
The present and projected shortage of natural gas
has led to several ambitious projects to produce
substitute natural gas from coal. At the present time,
four projects to produce SNG from coal by the Lurgi
pressure gasification process are in various phases of
engineering design. Each of these plants will produce
250 million of SNG. It seems likely that more plants
utilizing the Lurgi process will be planned for the
future.
Any process based on coal will inevitably encounter
many environmental problems, and the Lurgi process
is no exception. A large proportion of the total plant
cost is devoted to environmentally related matters
and to byproduct treating.
Process Descriptions,
Figure 1 shows, in block form, the overall
processing sequence. In the gasification section, coal
is reacted with oxygen and steam to form a crude gas
which is primarily a mixture of carbon dioxide,
carbon monoxide, hydrogen, methane, and water
vapor. The gas stream also contains ammonia.
hydrogen cyanide, hydrogen sulfide, carbonyl sulfide.
and carbon disulfide. Halogens in the coal will form
their respective acid. Additional compounds in the
crude gas are the hydrocarbon byproducts which
consists of tar, tar-oil, naphtha, crude phenols, and
fatty acids.
The function of the other processing units in figure
1 is to upgrade the crude gas stream, and separate and
recover the various byproducts. All of the tars, tar-oil,
naphtha, phenols, and fatty acids are separated from
the gas stream by cooling. This also condenses most
•Principal Process Engineers, Fluor Engineers and
Constructors, Inc., Los Angeles, California.
Auxiliary Units
The auxiliary units include a cryongenic air
separation plant to produce oxygen, a Claus sulfur
plant for sulfur recovery, a coal-fired steam plant
with flue gas treating for SO2 removal, cooling water
systems, byproduct storage and loading facilities,
safety systems, effluent water treatment and reuse
systems, ash handling systems, and numerous service
facilities and buildings.
Water Usage
The WESCO plant gasifies 21,800 tons per day of
coal and requires 5.100 gpm of raw water intake. This
amounts to 1.4 pounds of water per pound of coal.
This includes water required by the coal mining
operation as well as the gasification plant and its
auxiliary utility services.
Since the supply of water to the project is
contractually limited, every effort has been made in
the design to conserve water usage and to maximize
the recycle, and reuse. Some of the major design
features used to achieve those objectives are:
1. About 250.000 hp of large compressor-driving
steam turbines will be provided with air-cooled
exhaust steam condensers. The condensed steam
will be recovered and reused as boiler feedwater.
The air-cooled condensers will provide 2 billion
Btu/hour of heat removal. If cooling water were
used for this heat removal, the evaporative water
loss from the cooling tower would be increased
by about 4,000 gpm (6,400 acre-ft per year).
This would almost double the raw water feed
requirement. The larger cooling tower would also
incur larger windage losses.
101
-------
SECTION 10
GASIFICATION
1
ASH
CRUDE GAS
SECTION 2O
SHIFT
CONVERSION
I
LIQUOR^
GAS LIQUOR
SECTION 70
GAS LIQUOR
SEPARATION
Til
cr -i
<
SECTION 30
GAS COOLING
e
~
8
SECTION 30
GAS COOLING
ft
SECTION 40
RECTISOL
WASH
INCINERATION
SECTION 60
PHENOSOLVAN
SECTION 50
METHANATION
I
SECTION 80
RECTISOL
WASH
PRODUCT GAS
TO COMPRESSION
NH3 STRIPPER
OFF-GAS
FIGURE I.
BLOCK FLOW DIAGRAM LURGI
COAL GASIFICATION PROCESS,
UJ
-------
2. Raw water will be treated to boiler feed water
quality, and then it is converted to high-pressure
steam. A major portion of this steam is fed into
the gasifiers. The unreacted steam is recovered as
a "gas liquor" from which byproduct
hydrocarbons that include phenols will be
recovered. The dephenolized gas liquor is
stripped of dissolved ammonia and hydrogen
sulfide, then it is treated for removal of oil and
suspended solids, and finally it is biochemically
oxidized in two stages of biotreating. The treated
and clarified effluent will then be reused as water
makeup to the plant cooling water system. In
fact, it will supply 100 percent of the cooling
water makeup needs.
3. Byproduct water produced in the methanation
reaction will be recovered and reused as boiler
feedwater.
4. Mechanical refrigeration will provide the low
temperatures needed in the Rectisol Unit.
Mechanical refrigeration with air-cooled
condensers was chosen in preference to an
absorption refrigeration system to avoid the very
large cooling water evaporation losses associated
with absorption refrigeration.
5.
6.
Water will be extracted from water treatment
sludges and recycled for reuse.
Slowdown from the cooling water system will be
reused for quenching of the ash from both the
gasifiers and the coal-fired boilers.
The plant will require only 8,200 acre-h per year,
or about 75 percent of the contract water availability.
This plan provides a margin of safety for any
unforeseen contingencies.
Table 1 shows the Water Requirements and
Disposition for the project. The ultimate disposition
of the 5,100 gpm intake water can be briefly
summarized as:
Process consumption 10.2%
Return to atmosphere 69.6%
Disposal to mine reclamation 8.4%
Others 11.8%
100.0%
emissions must also be controlled. The majority of
the particulates are removed with electrostatic
precipitators. However, the stack-gas treating process
also removes some particulates, so the net result is
that only 1.8 tons/day of participate matter is
discharged to the atmosphere.
The tail gas from the Claus sulfur plant is
incinerated in the boiler (to oxidize the H2S to 802)
and then treated with the flue gas for SO2 removal. A
decision has not yet been made on the stack-gas
treating process, although the Chiyoda 101 and the
MKK-Wellman Lord processes are being considered.
The MKK process recovers the sulfur as sulfunc acid
while the Chiyoda process yields gypsum.
The CO2 stream vented to the atmosphere in the
Rectisol plant amounts to 284 million scfd. This
stream is 98.3 percent C02, with the balance being
hydrocarbons (CH4, C^He, and C2H4). About 35
ppm of COS is also in the gas. The presence of
ethylene in this stream, even though it amounts to
only 0.35 volume %, may be somewhat of a problem.
In some locations, it may be possible to vent this
material directly to the air. In situations where this is
not permitted, it may be necessary to install another
cleanup device such as a catalytic oxidizer.
Table 1. Water Requirements and Disposition
Process Consumption GPM %
To supply hydrogen 1,120
Produced as methanation by product 600
Net Consumption 520 10 2
Return to Atmosphere
Evaporation.
From raw water ponds 420
From cooling tower 1,760
From quenching hot ash 150
From pelletizing sulfur 250
From wetting of mine roads 730
3,310
Via stack gases
From steam blowing of boiler tubes 200
From stack gas SO scrubbers 40
240
Total return to 3,550 69 6
atmosphere
Disposal to Mine Reclamation
In water treating sludges 100
In wetted boiler ash 30
In wetted gasifier ash 300
Total disposal to 430 8.4
mine
Others
Retained in slurry pond 20
Miscellaneous mine uses 580
Total others 600 11 B
GRAND TOTAL 5.100 100 0
Because a coal-fired boiler is used, particulate
(i)
Does not include water derived from burning of boiler
fuel
103
-------
The stream superheater furnace effluent meets
environmental regulations without treatment by
firing a low-sulfur fuel oil.
The air emissions described are those which occur
during normal operation of the plant. Some
intermittent emissions also occur during regeneration
of the shift catalyst and certain startup operations.
These emissions are handled by incinerating them in
the boiler plant, after which they are treated by the
stack-gas treating process.
Solid Waste
Waste solids are disposed of by being buried in the
mine. These materials consist of ash from the boiler
plant and from the gasifiers, coal wash plant waste
slurry, and the combined sludge from the water
clarifier, biotreating unit, and the sanitary waste
treatment.
Conclusion
It can be appreciated that a great deal of effort and
money is required to meet the environmental
regulations in a coal gasification plant. Nevertheless,
meeting present day regulations is within the realm of
proven technology, and, at the same time, they allow
the designer some latitude of choice in selecting
appropriate processes. For example, in the WESCO
plant the decision was made to use a coal-fired boiler
and stack-gas treating for SO2 removal rather than
one of the so-called "clean fuel cycles". This choice
was made on the basis of the specific economic
factors appropriate to the WESCO plant.
It is important to note that about 70 percent of the
water will be returned to the regional atmospheric
environment and will eventually become rainwater.
About 20 percent of the water is returned to the
environment in the form of liquid water.
It is also important to note that the 20 percent will
be disposed of on-site, principally as sludges and
wetted ash used in the reclamation of the coal mining
area.
A schematic diagram of the water treatment and
reuse systems is included as figure 2 and graphically
illustrates the extent to which recycle and water reuse
has been designed into the plant:
(1) As already discussed, the water used to provide
turbine steam is condensed and recycled for 100
percent reuse.
(2) The water fed into the gasifiers (as steam)
provides the hydrogen required to convert the
coal to methane (SNG).
After serving as a gasification reactant, the excess
steam is condensed as phenolic gas liquor from
which useful byproduct phenols are then
extracted. After oil and solids removal, and
biotreatment, the recovered water provides 100
percent of the makeup needs for the process
cooling water system.
This water has now served three useful
functions:
(a) Supplied necessary reactant in the
conversion of coal to SNG;
(b) Served as the medium for removal and
recovery of byproduct phenols (as well as
ammonia);
(c) Supplied 100 percent of the cooling water
makeup needs.
(3) The cooling water system is a closed loop with
an evaporative cooling tower. Water is recycled
and reused in the system about 3-6 times before
the buildup of dissolved salts necessitates a
blowdown to maintain a tolerable level of salts
within the circulating water. Even this blowdown
is reused; it quenches the hot ashes from the
gasifiers.
(4) Boiler blowdown water, rinse waters from the
water demineralizers, treated effluent from the
sanitary system biotreatment unit, and excess
process condensate will be selectively reused to
provide:
(a) Water for wetting of roads in the mining
area (dust abatement);
(b) Water for pelletizing the byproduct sulfur;
(c) Other uses in the mining and coal processing
operations.
Air Emissions
All of the materials emitted to the atmosphere
occur at three sources: the boiler plant stack, the
steam superheater furnace, and the CC^ stream
discharged from the Rectisol plant. Figure 3 shows
the arrangement and the overall sulfur balance.
If the allowable SO2 emissions were decreased by
say, a factor of two, this choice of processes would
not be possible. The point we wish to make is that
the current environmental regulations are taxing
technology to the utmost, and more stringent
regulations would force matters into unproven
techniques of highly uneconomical alternatives.
104
-------
WATER TREATMENT AND REUSE SYSTEMS
o
CJI
RIVER WATER
5100 GPM*
SL
SELECTIV
REUSE
(SEE BELC
1570 GPU
L______
ROAD WET
SULFUR P
OTHER Ml
fc EVAPORATION
f"^ FROM PONDS
RAW
WATER ^ STB
TREATING ~ GENEF
1 1 (DOMESTIC WATEI
UDGE RINSES jgJSJBB
•~~"*
M- BOILER BLDWDOWNS
*^ RINSES BIOLOGI
I ' TREATED
EFFLUENT 1
r PROCESS „ T
, CONDENSATE 1 SLUD
- --* o
TIMf! W _
ELLETIZING N ____
NE USES l—^ PROC
COOLI
PROCESS PROCESS COMPENSATES
* 5TEAM 2700 GPM ^
_^BOILER 1
*M — ^ TUBE la
IATKJN BLOWING BuWXWN
A 1 PROCESS
? •. STFAM EXHAUST
} SLOWDOWN TURBINES STEAM j AIR COOLER
|O
-------
o
en
S= 3.0 (SULFUR LEAN GAS)
COAL= 21.
SULFUR= 200
3"
TAR
8=4.1
S = 180.7
GASIFICATION
Q= 363,300
MILLION BTU/D,,.
HHV
TAR OILS 8=1.3
S=IO.O
(SULFUR-RICH GAS)
SULFUR PLANT
95% S
RECOVERY
OFF GAS
TO VENT
1
"
S=92
8=174.5
RECTISOL
Lt
COS = 60 PPMV(MAX)
S=0.5
NAPHTHA
S= 0.4
COAL- 3760
SULFUR = 32.7
ASH -S= 1.6
BOILERS
Q = 70,800
MILLION BTU/D
5=3,,
S02=O.II3LB/M. BTU
I S=4.02 *
90% S REMOVAL
-«
TOTAL SULFUR EMISSIONS
4.85 TONS/DAY
5=36.28
FUEL OIL -310
SULFUR = 0.86
SUPERHEATER
Q = 10,200
MILLION BTU/D
LHV
S=0.86 _j
'
NOTE;
ALL QUANITIES ARE IN SHORT TONS
PER DAY EXCEPT SHOWN OTHERWISE
M. BTU
ANALYSIS WT%
MOISTURE
ASH
FIXED CARBON
VOL. MATTER
SULFUR , WT%
HHV, BTU/LB
LHV BTU/LB
GASIFIER
COAL
12.4
25.6
33.8
28.2
OO.O
0.915
8310
7860
BOILEf
COAL
123
14.1
40.2
33.4
100.0
0.87
9870
9420
FUEL OIL
0.28
17,490
16,500
SULFUR BALANCE
FIGURE 3
(I.) DESIGN VALUE BASED ON LURGIS COMPOSITE SAMPLES
-------
ANALYSES OF TARS, CHARS. GASES, AND WATER FOUND
IN EFFLUENTS FROM THE SYNTHANE PROCESS*
Albert J. Forney, William P. Haynes, Stanley J. Gasior,
Glenn E. Johnson, and Joseph P. Strakey, Jr.t
Abstract
Extensive studies have been made of the various
effluents found in the Synthane coal-to-gas process.
Analyses have been made of the waters, gases, and
trace elements present in some of the streams. Results
of analyses show the water effluents are the area
where extensive research is needed.
INTRODUCTION
One of the answers to the shortage of natural gas is
to convert coal to a high-Btu gas. Four
co a I-con version projects are proceeding to the
prototype plant scale (75 to 120 tpd coal utilization)
(ref. 1). An aspect of coal gasification that is of major
importance is the possible pollution resulting from
the process. While the four prototype plants have
different types of processing units, they will have
similar effluents. This paper discusses this aspect of
the Synthane process, based on the Bureau of Mines
laboratory-scale gasifier at Bruceton, Pa.
The advantage of the Bruceton laboratory-scale
Synthane gasifier in studying effluent problems is
that the waters, tars, gases, and solids streams are
representative of those that will be obtained from a
commercial operation. There will be some difference
due to temperatures and variations in steam-oxygen
feed quantities, but the samples of streams discussed
in the following tables will be quite representative of
larger scale operation. This will also be true of the
byproducts of the methanation step. Most of our
knowledge of these effluents is based on the work at
the Bruceton laboratories of the Pittsburgh Energy
Research Center (PERC).
ACKNOWLEDGMENT
At PERC the solids, water, and tar analyses were
mostly performed by the General Analysis group
•Bureau of Mines Application of Improved Technology to
Provide Clean Energy Program, Technical Progress Report 76.
U.S. Department of the Interior, January 1974.
tAII are with the Pittsburgh Energy Research Center,
Pittsburgh, Pa- Forney is research supervisor, Haynes and
Strakey are supervisory chemical engineers, Gasior and
Johnson are chemical engineers.
headed by H. Schultz, with special thanks due to F.
E. Walker. J. F. Smith, and M. F. Ferrer. Other water,
tar, and gas anlyses were made by the Spectra-Physics
group headed by R. A. Friedel with A. G. Sharkey
and C. E. Schmidt. Trace element analysis (table 2) of
the waters was done by Charles E. Taylor of EPA,
and the tar and gas were analyzed by Bernard Keisch
of Carnegie-Mellon University. The HCN analyses
were performed by Dr. Schultz's group.
THE OVERALL PROCESS
The overall process is shown schematically in figure
1. It shows the 75-tpd pilot plant which was designed
by the Lummus Co. and is being built as Bruceton,
Pa., by the Rust Engineering Co. The major units
shown are the gasifier, shift converter, purification
systems, and methanators. Each of these units has its
byproduct streams.
WATER ANALYSIS
The major effluent problem is the contaminated
condensate from the gasifier. The Bruceton
laboratory gasifier, shown in figure 2, condenses the
water, tars, and dusts in two water-cooled condensers
operated at 100° and 50°C. Table 1 shows the
analysis of the condensate from gasification tests with
a number of different coals compared with a
coke-plant weak ammonia liquor. Bethlehem Steel
Co. at its Bethlehem, Pa., plant (ref. 2) has reduced
the phenol level of its weak ammonia liquor to 100
ppb by biological oxidation and has reduced the
thiocyanates by an average of 70 percent. This plant
has been operating at Bethlehem for over 10 years,
and the effluent of the plant satisfactorily meets
Pennsylvania pollution requirements. Therefore, we
consider this system a satisfactory means of solving
the effluent problems of the Synthane plant.
However, work is continuing on new and better
methods of alleviating these problems.
Additional analyses of the condensate were
performed by the Environmental Protection Agency
at its Southeast Environmental Research Laboratory;
the trace elements in the water are shown in table 2.
For a commercial coal-to-gas plant, this water
would be purified as completely as possible and then
107
-------
racjclt 3 to I
FIGURE 1. - Flowsheet of prototype Synthane process.
Cool feed
Steam generator
gasifier
Oxygen Chromotogroph
analyzer
Figure 2. Forty-atmosphere fluid-bed gasifier.
108
-------
Table 1. Byproduct water analysis, from Synthane gasification of various coals, mg/l (except pH)
pH
Suspended solids...
Phenol
COD
Cyanide
NH3
Chloride
Bicarbonate
Total sulfur
Coke
plant
9
50
2,000
7,000
1,000
100
5,000
—
Illinois
No. 6
coal
8.6
600
2,600
15,000
152
0.6
8,100*
500
6,000t
ll.OOOt
1 ,400f
Wyoming
sub-
bitu-
minous
coal
8.7
140
6,000
43,000
23
0.23
9,520
_
Illi-
nois
lignite
7.9
24
200
1,700
21
0.1
2,500
31
North
Dakota
lignite
9.2
64
6,600
38, COO
22
0.1
7,200
—
Western
Kentucky
coal
8.9
55
3,700
19,000
200
0.5
10,000
—
Pitts-
burgh
seam
coal
9.3
23
1,700
19,000
188
0.6
11,000
—
* 85 percent free NH3.
t Not from same analysis.
O = 300; S
1,400;
= 1.000.
Table 2. Trace elements in condensate from an Illinois
No. 6 coal gasification test
ppm:
Calcium
Iron
Magnesium
Aluminum
ppb:
Selenium
Potassium
Barium
Phosphorus
Zinc
Manganese
Germanium
Arsenic
Nickel
Strontium
Tin
Copper
Columbium
Chromium
Vanadium
Cobalt
No. 1
4.4
2.6
1.5
0.8
401
117
109
82
44
36
32
44
23
33
25
16
7
4
4
1
No. 2
3.6
2.9
1.8
0.7
323
204
155
92
83
38
61
28
34
24
26
20
5
8
2 •
2
Average (by weight)
4
3
2
0.8
360
160
130
90
60
40
40
30
30
30
20
20
6
6
3
2
109
-------
Table 3. Components in gasifier gas, ppm
H_S
cos
Thiophene
Methyl thiophene
Dimethyl thiophene..
Benzene
Toluene
C0 aromatics
o
so,
2
cs»
2
Methyl mercaptan —
Illi-
nois
No. 6
<:oal
9,800
150
31
10
10
340
94
24
10
10
60
Illi-
nois
char
186
2
0.4
0.4
0.5
10
3
2
1
0.1
Wyoming
sub-
bitu-
minous
coal
2,480
32
10
434
59
27
6
0.4
Western
Kentucky
coal
2,530
119
5
100
22
4
2
33
North
Dakota
lignite
1,750
65
13
11
1,727
167
73
10
10
Pitts-
burgh
seam
coal
860
11
42
7
6
1,050
185
27
10
8
Table 4. Mass spectrometric analyses of the benzene-
soluble tar, volume-percent
Structural type 1
(includes alkyl (
derivatives) 1
Ni
Benzenes
Indenes
Indans
Flourenes
Phenylnaphthal enes
4-ring pericondensed
4-ring catacondensed
Naphthols
Indanols
Dibenzothiophenes
Benzonaphthothiophenes. . .
N-heterocyclics3
Average molecular weight.
ton KP-1
4o. 92,
Illinois1
). 6 coal
2.1
28.6
1.9
11.6
9.6
13.5
13.8
9.8
7.2
4.0
2.8
(2)
0.9
2.7
6.3
3.5
1.7
(10.8)
212
Run HPL '
No. 94,
lignite
4.1
1.5
3.5
19.0
7.2
12.0
10.5
3.5
3.5
1.4
13.7
9.7
1.7
2.5
5.2
1.0
(3.8)
173
Jun HPM No. 11
Montana
subbituminous
coal
3.9
2.6
4.9
15.3
9.7
11.1
9.0
6.4
4.9
3.0
5.5
9.6
1.5
4.6
0.9
5.6
1.5
(5.3)
230
Run HP-118
No. 118,1
Pittsburgh
seam coal
1.9
26.1
2.1
16.5
10.7
15.8
14.8
7.6
7.6
4.1
3.0
(2)
0.7
2.0
4.7
2.4
(8.8)
202
*Spectra indicate traces of 5-ring aromatics.
Includes any naphthol present (not resolved in these spectra).
30ata on N-free basis since isotope corrections were estimated.
110
-------
Table 5. Sulfur content of coals and products,
weight-percent (except gas)
Coal
Char
Tar
Condensate
Gas (vol-pct)
Pittsburgh
seam coal
1.5
0.5
0.8
<0.1
0.3
1
Illinois
No. 6 coal
3.5
1.1
2.7
<0.1
1.1
-oal type
Montana sub-
bituminous coal
0.6
0.4
0.5
<0.1
0.4
North Dakota
lignite
1 .1
0.6
1.0
<0.1
0.3
Table 6. Representative analyses of coals and
chars, weight-percent
«
Coals:
Moisture
Volatile matter
Fixed carbon
Ash
Hydrogen
Oxygen
Carbon
Nitrogen
Sulfur
Chars (from above coals):
Moi sture
Vol ati 1 e matter
Fixed carbon
Ash
Hydrogen
Oxyqen
Carbon
Nitrogen
Sulfur
Illi-
nois
No. 6
coal
8.3
37.5
43.0
11.2
5.3
15.9
63.0
1.1
3.5
0.8
4.0
69.9
25.3
1.0
1.3
70.4
0.6
1.4
West-
ern
Ken-
tucky
coal
4.3
34.6
44.5
16.6
4.7
10.9
62.7
1.2
3.9
1 .2
4.8
63.3
30.7
1.0
1.1
64.5
0.7
2.0
Wyo-
ming
sub-
bitu-
minous
coal
18.1
31.9
32.0
18.0
5.4
30.3
45.2
0.6
0.5
0.5
5.1
38.1
56.3
1.0
1 .2
40.6
0.4
0.5
North
Dakota
lignite
20.6
32.9
38.2
8.3
5.7
32.6
51.5
0.7
1.2
1.2
10.0
50.2
38.6
0.9
0.0
58.9
0.2
2.0
Pitts-
burgh
seam
coal
2.5
30.9
51.5
15.1
4.7
9.3
68.4
1 .2
1.3
1.4
1.6
69.3
27.7
1.0
1 .7
68.9
0.5
0.2
111
-------
used as a recycled cooling water; therefore, it could
not possibly contaminate any streams.
GAS ANALYSIS
Besides the large quantities of H2, CO. CO2, CH4>
and C2H6 made in the gasifier, a number of trace
components are found. These are shown In table 3
which shows the sulfur compounds plus the BTX
(benzene-toluene-xylene) components. The sulfur
compounds must be removed before methanation
because of their poisoning effect on the nickel
catalyst. The use of Benfield* hot-carbonate-gas
purification followed by sponge iron and activated
carbon traps should accomplish this goal.
In industrial practice, the BTX would be removed
in the oil scrubber (fig. 1). A commercial plant
(250,000,000 scfd) will produce about 25,000 gpd of
BTX.
TAR ANALYSIS
Tar analyses were made by our own and other
laboratories, as shown in tables 4 and 5. Table 4
shows analyses of tars from various coals and the
variety of products found in the tar.
Elemental analyses of tars are shown below, in
percent:
UIin2i§.N2j? IJ!iQSU£b3£ Lignite
82.6 83.4 83.8
Carbon
Hydrogen...
Nitrogen
Sulfur
6.6
1.1
2.8
6.6
1.1
2.6
7.7
1.0
1.1
These analyses are reported on a moisture- and
ash-free basis. Oxygen can be obtained by difference
from 100 percent. It is planned to burn the tars in the
boiler because it would be too expensive to try to
separate the chemical compounds for sale.
•Reference to trade names is made to facilitate
understanding and does not imply endorsement by the
Bureau of Mines.
SULFUR ANALYSIS
Sulfur analyses of the various coals tested and
products are shown in table 5.
SOLID ANALYSIS
The residue (char) from the gasifier in a commercial
plant is to be burned along with the tars to raise
steam for the process. The ultimate and proximate
analyses of the chars are shown in table 6. The chars
would contain a percentage of trace elements shown
in ash analyses done by the Bureau (refs. 3,4). A
problem may exist with SOX in stack gases when
burning the char and tars from the gasification of
high-sulfur coal.
OTHER STREAMS
Since we operate both gasification and methanation
laboratory-size equipment at PERC, we have analyzed
these streams extensively. No serious contaminants
have been detected in the water from the
methanation reactors. The other process steps are not
being investigated by PERC, but some assumptions
can be made. It would be reasonable to assume that
the contaminated condensate from the shift converter
would be similar to, but more dilute, than the gasifier
condensate shown in table 1. There should be no
effluent from the hot carbonate unit if the feed gas
contains the proper partial pressure of water. The
Stretford unit should have a gas effluent low enough
in sulfur for air pollution requirements for the 75-tpd
plant at Bruceton.
TRACE ANALYSIS
Other analyses that took special methods are shown
in table 7. The HCN analysis is of special significance
since it could effect the operation of the Stretford
unit in the 75-tpd pilot plant. However, the low level
Table 7. Trace components in gas and tar
Illinois char
Illinois No. 6 coal...
Western Kentucky coal .
North Dakota lignite...
Wyoming subbitum. coal.
Gas (by volume)
HCN, ppb
5
20
11
3
2
Mercury, ppm
0.00001
Tar (by weight)
Mercury, ppm
0.003
Arsenic, ppm
0.7
112
-------
(ppb) indicates no serious problem. Mercury is
present in the gas from the gasifier, but none was
detected in the final product; that is, in the high-Btu
gas. The mercury and arsenic in the tars, if burned,
would probably end up in the stack gas.
CONCLUSION
While we have obtained much data, we are
continuing to analyze these effluent streams
exhaustively. We hope to completely characterize
these effluents and to have solutions available for
handling them before the 75-tpd plant is operating.
No serious problems are foreseen at this time.
REFERENCES
1. A. J. Forney, "Progress Report on SNG
Technology," Pipeline Industry, Vol. 37, No. 4
(September 1972). pp. 27-29..
2. P. D. Kostenbader and J. W. Flecksteiner,
"Biological Oxidation of Coke Plant Weak
Ammonia Liquor." J. Water Pollution Control
Federation, Vol. 41, No. 2, pt. 1 (February
1969), pp. 199-207.
3. R. F. Abernethy, M. J. Petersen, and F. H.
Gibson, Major Ash Constituents in U.S. Coals,
BuMines Rl 7240,1969. 9 pp.
4. T. Kessler, A. G. Sharkey, Jr., and R. A. Friedel,
Analysis of Trace Elements in Coal by
Spark-Source Mass Spectrometry, BuMines Rl
7714,1973.7pp.
113
-------
114
-------
CLEAN ENVIRONMENT WITH KOPPERS-TOTZEK PROCESS
J. Frank Farnsworth,
D. Michael Mitsak,
and J. F. Kamody*
Aostract
The Koppers-Totzek Process is the first
commercially proven gasification process to be
evaluated (in 1973) for the U.S. Environmental
Protection Agency by Esso Research and Engineering
Company.
This process converts any rank coal or heavy liquid
hydrocarbon into a gas whose composition is
essentially carbon dioxide, carbon monoxide, and
hydrogen. Sulfur appears as hydrogen sulfide and is
recovered in a Claus unit. Gas can be used as low-Btu
(30V) fuel; in reducing applications; as feedstock for
chemical synthesis; or it can be upgraded to pipline
quality. Oxygen and steam are introduced into the
gasifier with the feedstock. This process produces
only gas and slag; there are no liquid tars or
hydrocarbons.
IMTpnouCTIOM
As a result of recent shortages ot clean gaseous and
liquid fuels in the United States, numerous
development programs have been initiated for the
production of synthetic fuels from our indigenous
natural resources. This activity has introduced into
the American society a group of technical and
nontechnical Americans, whom we identify as
"Environmentalists." We find these concerned people
among our friends, neighbors, and members of our
families. They are a part of a group that is concerned
with the protection of the environment from adverse
affects of any future energy plants. In essence, their
slogan could be. "Use the natural resources, but
whatever residuals are returned to the earth must be
of a purity equal to, or better than, the original
material."
Gasification of solid or liquid fuels by the
commercially proven Koppers-Totzek (K-T) process
offers a pollution-free means of producing a 300 Btu
per cubic foot synthesis gas which can be readily
*J. Frank Farnsworth is senior staff engineer in coal and
gas technology; D. Michael Mitsak is manager of the chemical
project section; and J. F. Kamody is project engineer. They
are with the Engineering and Construction Division of the
Koppers Company, Inc., Pittsburgh, Pennsylvania.
substituted for natural gas in industrial fuel
applications. It can be catalytically upgraded to a
heating value of 960 Btu per cubic foot to provide a
gas comparable to, and interchangeable with, natural
gas. The gas is an excellent base for the production of
chemicals, such as ammonia and methanol. The K-T
synthesis gas can also be converted to liquid
hydrocarbons by the use of the well-known
Fischer-Tropsch technology. Actually, this
application gave birth in 1948 to the K-T process. At
the time, the U.S. Bureau of Mines selected the K-T
partial oxidation of pulverized coal in steam and
oxygen process to supply the synthesis gas for
coal-to-oil demonstration plant at Louisiana,
Missouri. Koppers-Pittsburgh joined Koppers-Essen in
developing the gasification technology from
laboratory data into an operating unit designed for a
gasification capacity of 36 tons of coal per day.
Results at Louisiana were successful. Since 1952,
Koppers-Essen has engineered and installed 33
3asifiers in 12 different locations throughout Europe,
Africa, and Asia. Currently, 15 additional gasifiers at
four locations are in various stages of construction.
These plants, in general, use low-rank coals such as
lignite or subbituminous. and the syn-gas is converted
into ammonia. The rapid expansion of the natural gas
and oil industries in the 1950's, with their abundant
supplies of low cost gas and oil, relegated the K-T
process to the shelf until the present energy shortage
emerged.
To date, the Koppers-Totzek process is the only
commercially proven gasification process to undergo
a pollution evaluation study for the U.S.
Environmental Protection Agency. Esso Research and
Engineering Company, Linden, New Jersey, under
contract to EPA, began the evaluation of the K-T
process in early 1973. The completed report, titled
"Evaluation of Pollution Control in Fossil Fuel
Conversion Process, Gasification; Section
1: Koppers-Totzek Process. January 1974," has been
issued and is available upon request through the
Environmental Protection Agency, Research Triangle
Park. North Carolina 27711. Of particular interest are
the following excerpts taken from the report:
'This process can be used to make synthesis
115
-------
gas, reducing gas, or fuel gas, and wai
studied first for several reasons: (1) more
complete information is available than on
some other processes; this specific design
does not include proprietary clean-up
processes; and there are a number of
commercial plants in operation; (2) it is a
simple and relatively clean process in that it
does not produce tar, oil, or phenols. (Minor
amounts of cyanide, ammonia, etc., are
produced); (3) the process developer was
cooperative in supplying requested
information."
"Low-Btu gas, such as that from the
Koppers-Totzek gasifier, would be expected
to give lower NOX due to lower flame
temperature." (This refers to comparison
with natural gas and coal firing.)
Although EPA has reviewed and approved the report
for publication, the approval is qualified as
follows: "Approval does not signify that the
contents necessarily reflect the views and policies of
the agency, nor does the mention of trade names or
commercial products constitute endorsement or
recommendation for use." In our opinion, this report
must be considered a base for the position that
regulatory agencies may take, since it indicates what
is attainable with present technology.
PROCESS DESCRIPTION AND
PROCESS FEATURES
The total process for producing clean, desulfurized
utility gas or synthesis gas is shown schematically
(figure 1). Depending on rank, the coal is dried to
between 2 and 8 percent moisture and is pulverized
to about 70 percent through 200 mesh (figure 2). The
coal is conveyed with nitrogen from storage to the
gasifier service bins. Controls regulate the
intermittent feeding of coal from the service bins to
the feed bins, which are connected to variable-speed
coal screw feeders (figure 3). The pulverized coal is
continuously discharged into a mixing nozzle where it
is entrained in oxygen and low pressure steam.
Moderate temperature and high burner velocity
prevent the reaction of the coal and the oxygen until
entry into the gasification zone.
The oxygen, steam, and coal react in the gasifier
(figure 4) at a slight positive pressure and at 3,300°F.
The carbon and volatile matter of the coal are
gasified, and the coal ash is converted into molten
slag. About 50 to 70 percent of this slag drops into a
water quench tank and is carried from the tank to the
plant disposal system as a granular solid, and the
remainder is entrained in the gas exiting the gasifier.
Low pressure steam for the gasifier reaction is
produced in the gasifier jacket from the heat passing
through the refractory lining.
Gas leaving the gasifier is direct-water quenched
when it is necessary to solidify entrained slag droplets
and then passed through a waste heat boiler where
high pressure steam up to 1,500 psig is produced.
After leaving the waste heat boiler, the gas is cleaned
and cooled in a venturi scrubbing system in which the
entrained solids are reduced to 0.002 to 0.003 grains
per SCF, and the temperature lowered from 350°F to
about 95°F. Electrostatic precipitators are used to
reduce particulates to 0.0001 grains per SCF, if the
K-T gas is to be compressed to high pressures for
chemical synthesis or for the production of high-Btu
gas. Several gasifiers can share common cleaning and
cooling equipment.
Particulate-laden water from the gas cleaning and
cooling system is piped to a clarifier. Sludge from the
clarifier is pumped either to a filter or to the plant
disposal area. Clarified water is recirculated through
the venturi scrubbers and the excess overflows into
the cooling tower system at the gas cooler.
Evaporation, windage, and blowdown water losses at
the cooling tower, plus moisture in clarifier sludge
and in slag, necessitate the addition of a small
quantity of makeup water to this system. If water is
at a premium, air cooling may be used for certain
applications, and the cooling tower can be reduced in
size to provide only the final trim in water
temperature.
The cool, clean gas leaving the gas-cleaning system
contains sulfur compounds which must be removed
to meet gas specifications. The type of system chosen
depends upon the end uses and pressure of the
product gas. For low pressures (up to 150 psig) and
low-Btu gas application, there are the chemical
reaction processes such as amine and carbonate
systems. At higher pressures, the physical absorption
processes such as Rectisol, Purisol, and Selexol are
used. The choice of the process is also dependent
upon the desired purity of the product gas and the
desired selectivity with respect to the concentrations
of carbon dioxide and sulfides.
Tables 1 & 2 show typical gasification data for
western and eastern coals and petroleum coke
feedstock.
The K-T process offers advantages not available in
existing nonsuspension systems. In the gasification of
116
-------
K-T Gasification Process
JTUII emm
S.UMITO
OIIMMl
KOPPERS
FIGURE 1
-------
COAL PREPARATION
PNEUMATIC COAl
CONVEYING LINE
PNEUMATIC COAL
CONVEYING LINE
N, FROM
GAS HOLDER
KOPPERS
FIGURE 2
-------
!*•**•" ^
FIGURE 3. COAL SCREW FEEDER
coal, the entire mine output is usable. Coal size is not
a limiting factor, and coking coals can tie handled
without pretreatment. Other features include:
Versatility. The process is capable of continuous
operation for the gasification of a variety of
feedstocks, including all ranks of solid fuels, liquid
hydrocarbons, and pumpable slurries of carbonaceous
materials in liquid hydrocarbons. Feedstocks of high
ash and sulfur contents, not environmentally
acceptable in present energy plants, can be readily
used in the K-T process.
Flexibility. The change-over from solid to liquid
fuels involves only a change of the burner heads.
Multiple feed burners and variable speed screw
feeders permit turndown to 70 percent. The process
is capable of instantaneous shutdown; from hot
standby, full gas production is resumed in less than
30 minutes.
Simplicity of Construction and Ease of Operation.
The only moving parts at the gasifier are screw
feeders for solids, or a pump for liquid feedstocks.
Control of the gasifiers is achieved primarily by
maintaining C02 concentration in the clean gas at a
reasonably constant and predetermined value. Slag
fluidity may be visually monitored. Gasifiers display
good dynamic response.
' Low Maintenance. Simplicity and a minimum of
moving parts result in little maintenance between
scheduled annual shutdowns for boiler inspection.
The gasifier is lined with a monolithic castable
refractory which lasts as long as 5 years with a
minimum of patching.
High Capacity. K-T units are designed for coal feed
rates of up to 850 tons per day, or for a production
of about 45 million standard cubic feet per day of
300-Btu gas.
Safe and Efficient. The K-T process has over 20
years of safe operation. The onstream time or
availability is better than 95 percent. Heating value of
the product gas is equivalent to 70-77 percent of the
calorific value of the feedstock. Additional energy
recovered as steam from the available sensible heat
119
-------
TO
LOW PRESSURE
STEAM DRUM
PULVERIZED
COAL, STEAM
AND OXYGEN
BOILER FEED WATER
BOILER FEED WATER
BURNER
COOLING WATER
FIGURE 4
amounts to about 15 percent of the calorific value of
the coal.
ENVIRONMENTAL CONTROLS
Control of the environment in a fuel conversion
facility depends, to a great degree, upon the
controlability and simplicity of process operations.
The 25-year K-T record of commercial operation
shows a consistency in continuous production at 95
percent of the onstream design figure. This reliance
requires controlability. As noted in the
aforementioned pollution evaluation report, "the
process is simple and clean." This is possible since the
products from the Koppers-Totzek gasifier are slag
and a synthesis gas composed primarily of carbon
dioxide, carbon monoxide, and hydrogen. The sulfur
contained in the feed material is converted during
gasification to hydrogen sulfide and carbonyl sulfide.
The sulfur compounds can be removed from the gas
to regulatory environmental limits with commercially
proven processes, and converted to elemental sulfur
suitable for sale to the chemical industry. The
particulate matter in the gas is removed by water
scrubbing the gas in two stages of venturi scrubbers.
The slag as produced is granulated and, since it has
passed through the molten state in the gasifier,
contains little or no dust or teachable material. The
slag will be suitable for road aggregate, landfill, or for
use in cinder blocks. The trace amounts of ammonia,
cyanide, etc., in the raw gas are removed during gas
cleaning and disposed of by combustion in the Claus
sulfur unit. The clean gas can be burned in
conventional power-generating equipment, and the
combustion gases are acceptably low in NOX and
other atmospheric pollutants.
Coal Storage and Handling
Gasification plants require an emergency supply of
coal. To minimize air pollution due to coal dust, this
coal supply will be placed in "dead storage." The
term "dead storage" means that this quantity of coal
is held in a compacted and sealed pile not susceptible
to dusting during wind activity. The coal storage pile
is prepared by layering coal in 12-inch depths and by
compacting each layer to a bulk density of about 70
pounds per cubic foot. The height of the pile is set at
'about 25 feet, and the length and width are fixed by
the tonnage to be stored. In order to monitor
120
-------
TABLE
K-T GASIFIER DATA FOR VARIOUS FUELS
TYPE OF FUEL
GASIFIER FEED
Dry Feed to Gasifier
Analysts, WtS
C
H
N
S
0
Ash
Moisture
.
Gross Heating Value of Dry Feed,
Btu/Lb
Oxygen, Tons/Ton Dried Fepd
8 98% Purity
Process Steam, Lb/Ton Dried Feed
GASIFIER PRODUCTS
Jacket Steam, Lb/Ton Dried Feed
High Pressure Steam, Lb/Ton Dried Feed
§ 900°F/900 psig
Raw Gas Analysis, Vol$, Dry
CO
C02
H2
N2 + Argon
H2S
COS
Dry Gas Hake - SCF/Ton Dried Feed
Gas Gross Heating Value, Btu/SCF, Dry
% Heating Value of Gas/Heating Value
Feed (Gross Basis)
WESTERN
COAL
72.7
5-3
1.1
1.0
9.0
8.9
2.0
100.0
13.135
0.878
814
600
2760
52.55
10.00
36.09
1.00
0.34
0.02
100.00
69,690
287
76.1
EASTFUN
COAL
69-9
4.9
1'.3
1.1
7.1
13-7
2.0
100.0
12,640
0.849
810
554
2675
52.51
10.00
35-96
1-15
0.36
0.02
100.00
66,970
286
75.8
GREEN PETROLEUM
COKE
88.0
4.5
1.4
4.3
1.0
0.2
0.6
100.0
15,690
0.950
1182
629
3598
52.22
10.00
35.40
1.10
1.20
0.08
100.00
77,500
283
69-9
spontaneous combustion, thermocouples are inserted
throughout the pile. The outer surface of the pile is
sprayed with an organic polymer crusting agent to
prevent dusting or rain erosion. Crusting also prevents
rainwater penetration of coal particles; thus, water
runoff will have little or no contaminants such, as
those found in mine waters. In addition, the coal pile
will be located on a waterproof base to prevent water
seepage into the ground. Thus, all runoff water will
be contained and used in the process. Under this
arrangement, the daily in-and-out requirements of
coal transfers will be performed in totally enclosed
equipment, and coal from "dead storage" will be
taken only in an emergency when the normal supply
of coal is interrupted.
In normal practice, coal will be delivered to the
plant by rail (figure 5). To economically deliver the
large daily tonnages of coal required by gasification
121
-------
TABLE 2
K-T CASIFIER HEAT BALANCE
Western Coal (2% Moisture)
Gas Exit Temperature • 2730*F
Reference State = Liquid Water
HEAT INPUT - ABOVE 60°F
Calorific Value of Coal
Sensible Heat in Coal @ 160°F
Sensible Heat in Oxygen @ 230°F
Total Heat In Steam @ 250°F
TOTAL
Btu/Lb of Coal Feed
13.135
29
27
-------
COAL HANDLINC, STORAGE t PREPARATION
,,TO 6i& TVCC OUiT COLLECTOR
3F
/-TO BAC; T
/OUST COLL
t ' _l i
FIGURE 5
-------
and the house itself, will be connected to a dust
collecting system to control dust emission and to
negate the possibility of fires or explosions. In
addition, a vacuum-cleaning system will be provided
in these houses.
All conveyors will be completely enclosed in
galleries, and all conveyor junction towers will have
junction houses to completely enclose the coal
transfer points. Each junction house will have a dust
collection system.
Coal Preparation
The coal preparation facilities start with surge bins
which are fed by a totally enclosed belt-conveying
system originating at the concrete coal storage day
bins. Coal from a surge bin is delivered to a
pulverizing, classifying, and drying system in which
the coal is pulverized to 70 percent minus 200 mesh
and dried to 2 percent moisture. Flue gas at 800°F
produced by the combustion of clean process gas is
used as the drying medium. The flue gas intimately
contacts the wet coal in a fluidized or entrained
operation and drives off the moisture. At these
conditions, the coal temperature does not exceed
180°F; as a result, there are no chemical reactions or
devolatilization of the coal. Thus, the flue gas and
water vapor will not be contaminated and can be
discharged to the atmosphere as pollution free after
separation from the dried and pulverized coal.
Paniculate matter in the discharged gases will be
controlled to acceptable limits by the use of cyclones,
bag filters, or precipitators. Condensation of the
water vapor from the stack could be controlled by
the introduction of combustion gases from other
parts of the plant, or by the use ot tall stacks to
dissipate the vapors.
The conveyors and chutes feeding the surge bins
will be enclosed, along with the weigh belt feeders
and chutes feeding the roller mills. These housings
will be connected to a dust collecting system. The
product bins will be connected to a common bag-type
dust collector; individual dust collectors, vented back
to the product bins via the pneumatic conveying
system lines, will be provided for each service bunker.
The feed systems delivering dust from the pulverized
bag filters to the surge bins will be enclosed and
vented back to the dust collectors. The entire coal
preparation facility, starting with the pulverized mill
surge bins and including the product bins, will be
housed in a building constructed of sound-absorbent
panels where practical, to reduce noise level. Where
possible, operating equipment will be designed with
noise suppression features. The building ventilating
system will discharge through an additional bag filter
in order to control dust leaving the building. Also, a
vacuum cleaning system will be provided for the
facility to further insure clean working conditions for
the operators.
Since the entire coal preparation facility is enclosed
in an essentially dust-tight building, the only exit for
dust to the atmosphere will be the building
ventilating dust collector. Participates entering this
collector will be minimal because of the equipment
dust collectors within the building. Thus, the
particulate emission to the atmosphere from coal
preparation will not exceed the designated dust
loading.
Water requirements in the coal preparation area will
be limited to those used for cooling of bearings;
therefore, this facility does not add any polluting
products to the plant water systems.
The plant will be designed to reduce the noise level
at the plant boundary to 50 dB(A).
Gasification, Gas Cooling, and Cleaning
As mentioned earlier, the K-T process, due to the
high temperature (3,330-3,500°F) operations,
produces gas and slag. Because there are no
condensible hydrocarbons, possible pollution sources
are limited to the gas, slag, process waters, and/or gas
condensates. Environmentally, by today's EPA
standards, objectionable gaseous matter from any
plant includes particulate matter, cyanides, sulfur
compounds, and oxides of nitrogen.
Water-contaminating substances include oil, and such
serious taste-offending compounds as phenols and
pyridines. The K-T process does not produce phenols,
pyridines, or organics; however, ammonia and
cyanide are produced in amounts well under one
volume percent. This situation provides for minimal
treatment to meet EPA discharge standards.
The following gas analyses (table 3} at the various
processing stages indicate the possible contaminants
and their concentrations.
The reduction in the particulate matter from 12
grains/SCF to 0.002 grains/SCF in gas occurs in the
primary and secondary venturi scrubbers where the
gas is intimately contacted with recirculated water. In
the process the water soluble ammonia, sulfur
dioxide, hydrogen cyanide, and some hydrogen
sulfide are absorbed. A bleed stream from the
recirculated water system is continuously discharged
to a stripper, where the gaseous components are
stripped by vapor rising from a steam reboiler.
Gaseous NH3.SO2, and HCN flow to the Claus unit
and are combusted while the stripped water is cooled
124
-------
TABLE 3
VOLUME PERCENT
Component
CO
CO2
CH4
H2
N2
H2S
COS
HCN
NHa
H2O
Ar
S02
No
Particulates
(grs/SCF)
Gasifier
Outlet
37.36
7.13
0.08
25.17
0.30
0.23
178 ppmv
288 ppmv
0.17
29.19
0.32
22 ppmv
7 ppmv
11.57
To Compres-
sion & Acid
Gas Removal
49.50
9.42
0.11
33.35
0.40
0.30
235 ppmv
300 ppmv
0.22
6.20
0.42
1 5 ppmv
7 ppmv
<0.002
Product
Gas
53.16
9.44
0.12
36.51
0.44
3 ppmv
1.5 ppmv
1 ppmv
1 ppmv
160 ppmv
0.46
0.5 ppmv
3 ppmv
< 0.002
and returned to the stripper-water-circulatmg system.
Excess stripped water is bled to the boiler feedwater
system where it is treated and used in the generation
of steam at the gasifiers.
The particulate matter (entrained slag) remaining in
the water that passes from the venturi scrubbers is
removed in a clarifier. If water is not at a premium,
the particulate in slurry form can be pumped to a
disposal area outside the plant. When water is scarce,
the slurry would be filtered, the water returned to
scrubbers, and the filter cake placed in loadout bins
for truck or railroad car disposal. Since particulate
matter is slagged material, there should be no
teachable contaminants, and disposal should pose no
environmental problems. The water recirculating
system is pollution clear with the side stream
treatment arrangement. The cooling of the
recirculating water can be achieved on a direct basis
in a cooling tower, if this is acceptable
environmentally, or on an indirect basis with air or
water exchangers.
The following water analyses (table 4) of the
various gas cooling and cleaning steps at the Kutahya,
Turkey, plant were reported by the Kutahya
personnel in late 1972. The data is offered to indicate
what order of magnitude that concentrations are
possible, and identifies possible contaminants. It is to
be noted that the most objectionable contaminants,
phenols, tars, oils, and pyridines are missing.
As shown tn table 4, solubility of hydrogen sulfide
in water is slight; thus, the gas leaving the venturi
scrubbers contains most of the hydrogen sulfide and
car bony I sulfide. There are various acid gas removal
processes that have the capability of reducing the
sulfur content in the gas to 5 ppmv. The processes are
based on absorption in solution and subsequent
stripping of the acid gases of H2S and C02 from the
solution. The physical absorption processes, which
operate at pressures of 300-400 psig. exhibit the
greatest selectivity for hydrogen sulfide and carbon
dioxide removal. Since no chemical reactions occur,
these processes do not form stable compounds such
as thiosulfates and thiocyanates. Some chemical
reaction processes, such as carbonate and amine,
which form the aforementioned stable compounds,
can be used but will require periodic dumping of the
solution in order to maintain removal efficiency.
Dumped solution will require treatment to meet
permissible discharge limitations. The choice of
process is dependent upon economics, environmental
control, purity of product gas, and desired acid gas
selectivity. A plant can be designed to reduce sulfur
in product gas to 5 ppmv. to control the H2S level in
carbon dioxide in 10 ppmv, and to reduce the liquid
effluent to zero pollutants.
The acid gas stream, containing a minimum of 14
volume percent H2S, is catalytically converted to
elemental molten sulfur in a Claus unit. The tail gases
exiting the Claus unit contain SO2 and can be treated
to catalytically reduce the SO2 to H2S. Scrubbing
with an amine solution absorbs the H2S and
subsequent stripping yields an H2S stream which is
recycled to the Claus unit. This combination results
in overall sulfur recovery of 99+percent.
At this stage, the clean gas is available as fuel or as
feedstock for further processing to chemicals and to
pipeline (high-Btu) gas. As regards chemical usage, the
gas itself does not add to environmental
considerations. On the other hand, if the gas is used
as a source of fuel for inplant use or in combined
cycle power generation, then consideration must be
given to the combustion characteristics and NOX
formation.
Gases containing carbon monoxide and hydrogen,
such as coke oven gas, producer gas, water gas, and
blast furnace gas, have been used as industrial fuels
for many years. American manufacturers of modern
steam boilers and gas turbines foresee no major
problems in adapting furnaces and combustors to
utilize the K-T utility gas.
When comparing the calorific value of the K-T
utility gas with that of natural gas (300 versus 1,000
Btu), it is often misconceived by some people that
the combustion characteristics of the K-T gas are
125
-------
TABLE 4
Sample location
pH Value
Conductivity
p Value
• Value
Total Hardneis
CaO
KgO
Ma
K
Zn
Fe
Mm
N02
MO,
POi Total
er
so*
CN
u c
HjS
KMnOj, Consumed
COO
SI02
Suspended Solids
Hot Residue, 803°C
Stripped Residue
Hot Residue. 8C3*C
Cu
S
oval/I
nval/l
• dH
ng/l
ng/l
ng/1
mg/l
n>g/l
oig/l
«g/l
ng/l
mg/l
ng/l
mg/l
ng/l
PXJ/1
MM/I
mg/l
™g/l
ng02/l
<*/!
ng/1
mg/l
ir.g/1
ng/l
nig/1
8.8
10-4
0.4
5.8
20.8
78
97
17.5
5.6
0.01
0.05
0.32
0.02
58.2
1.89
18
42
0.26
8
It
14.8
14
4
568
268
0.01
8.8
1.8
10-3
2.4
13.2
33-5
101
161
17.5
8.B
0.03
0.22
157
0.13
3.32
0.81
85
216
0.52
9
18
16.0
4612
3918
812
550
0.01
8-9
2.0
10-3
4.0
14.0
36.8
78
194
17.5
10.0
0.02
1.95
184
4.47
13-7
1.21
96
155
12.5
400
128
14.8
5984
4356
940
588
0.01
7-5
*l
0.8
6.4
22.8
85
102
17.5
6.8
0.03
0.26
25
5.34
34.0
1.69
53
147
8.8
1.8
10-3
1.6
12.8
34.0
135
145
17.5
8.0
0.02
0.20
137
0.24
2t.7
0.81
57
255
7.0 1.4
14 11
18
30.6
278
134
606
366
0.06
16
19.8
3072
2690
706
526
0.01
8.9
1.8
10-3
2.4
14.8
34.8
179
113
17.5
8.0
0.02
0.64
122
4.37
22.9
2.70
46
109
14.0
145
63
42.6
50
46
724
512
0.06
8.9
I-?
10-3
2.2
14.0
35-2
179
129
17-5
7-9
0.02
0.24
72
23.7
42.0
2.41
36.
153
0.7
60 '
30.6
58
42
828
534
0.27
I) Cooling water to gasifier seal pot.
2) Water froa the gasifier seal pot.
3) Wash water after Masher-cooler.
4) Wash water after Theisen washer.
5) Water into clarlfler.
6) Water out of clarifler.
7) Water out of cooling tower.
inferior to those of natural gas. Actually, the K-T gas
displays excellent combustion characteristics resulting
in boiler or gas turbine performances equivalent to,
and in some ways better than, those for natural gas or
for other utility gases produced from alternate coal
gasification processes.
Table 5 compares the theoretical combustion
characteristics of the K-T gas with a typical natural
gas and with gas from an airblown fixed bed gasifier,
as well as with a typical second generation coal
gasification process (Bi-Gas). In each instance, the
gases are used for firing a utility boiler. Comparison
of the fuels is based on a total of one million Btu of
net calorific heat input (measured at 60°F, 30 in.
Hg). The net (or lower) heating value of the gas has
been selected for comparison, since the latent heat of
water vapor in the combustion gas is not recovered in
combustion equipment. Air, initially at a 40°F wet
bulb temperature, is compressed and enters the
com bust or at 600° F. For comparative purposes, all
fuels are based on a delivery temperature of 77°F to
the combustor, even though waste heat from a coal
gasification process can often be used to preheat
these fuels.
As can be seen in table 5, combustion of K-T gas
requires only about 75 percent of the quantity of air
required for theoretical combustion of the natural
gas. The weight of the products of combustion from
the K-T gas is about 95 percent of that which results
from natural gas combustion, or combustion of gas
from the BiGas Process. Thus, if these gases are fired
to steam boilers at a given calorific heat input with
126
-------
Table 5. Combustion Characteristics of Various Fuels
Table 5 (Continued)
DATA ON COMBUSTION AT FIXED MAXIMUM FIRING TEMPERATURE OF I950'F
to
in G;
as Turbine /
^ppucatior
High Btu
Natural Gas Bi-Gas
Composition, Volt
C02
CO
M2
N2 + Argon
CH,,
^2N6
H20
Total Lb-noles of Dry Gas
Lower Heating Value, Blu/SCF, Dry
Higher Heating Value, Blu/SCF, Dry
DATA ON COMBUSTION WITH THEORETICAL
Lb-Moles Air Required
Lb-Moles Theoretical Combustion Gas
Lb of Theoretical Combustion Gas
Adiabatie Maximum Flame Ten* *F
Composition of Complete Combustion
Gas, Volt
C02
N2 + Argon
H20
Dew Point of Combustion
Gas, °F
Bases
TJ One million Btu of net calorific
2) Air at 40*F wethulh temperature
at 600° F
o so
--
--
0 50
83 00
16 00
—
100 00
2 59
1020
M27
AIR
19 40
30 10
40 IS
0 68
9 37
--
0 30
100 00
901
293
322
1
Air-Blown
Fixed Bed
14 00
16 00
25 00
39 70
5 00
--
0 30
100 00
15 90
166
183
K_T
1
Utility
Gas
9 25
53 00
36 40
1 05
—
0 30
100 00
9 74
271
289
Lb-Moles Wet Air Required
Lb-Holes Theoretical Combustion Gas
Lb of Theoretical Combustion Gas
Percent Excess Al r
Composition of Complete Combustion Gas,
Volt
C02
N2 + Argon
H20
"2
Dew Point of Combustion
Gas, "F
High Btu
Natural Gas
86 47
89 05
2532
213
3 35
75 68
7 28
13 69
100 00
100
DATA ON COMBUSTION AT FIXED MAXIMUM FIRING TEMPERATURE
27 37
30 16
837
4075
9 90
71 65
IB 45
100 00
135
heat input
compresse
23 13
28 98
843
4000
18 30
63 20
IB 50
100 00
135
Suppl I GO tO
23 12
35 76
1035
3400
15 56
68 67
'5 57
100 00
129
20 77
26 16
794
4280
23 19
63 OS
13 76
100 00
124
turb i nc combus tor
3) All fuel gases enter comtaustor at 77*F
4) Combustion occurs at 140 psig
5) Fuel gases (except for natural gas) expected to
contain 0 3t
water
Lb-Holes Wet Air Required
Lb-Moles Theoretical Combustion Gas
Lb of Theoretical Combustion Gas
Percent Excess Air
Composition of Complete Combustion Gas,
Volt
C02
Nj + Argon
H,0
°2
Dew Point of Combustion Gas, *F
DATA ON COMBUSTION AT LEAN FLAMMABILITY
Percent Fuel In Air-Fuel Mixture
Percent Excess Air
Throretical Flame Temp, *F
62 02
64 81
1830
110
4 61
74 78
9 60
11 01
100 00
110
LIMITS
5 52
86
2710
BI-Gas
80 84
89 85
2498
246
6 12
72 92
7 19
13 77
100 00
99
OF 2400*F
56 67
62 52
1804
142
8 48
70 92
9 54
II 06
100 00
110
7 31
388
1605
Air-Blown
Fixed Bed
71 49
84 14
2422
206
6 61
73 89
7 62
11 88
100 00
101
47 95
60 59
1745
112
9 18
72.25
10 14
B.43
100 00
113
12 32 .
385
1540
K-T
Utility
Gas
81 36
86 75
2532
288
6 99
73 39
5 16
14 46
100 00
88
57 19
62 58
1838
173
9 69
71 56
6.73
12 02
100 00
110
7 74
453
1595
-------
zero percent overall excess air, no derating of
conventional boiler equipment is expected for the
K-T utility gas due to increased mass velocity which is
proportional to draft loss. Likewise, reduced
quantities of combustion gas result in less loss of
sensible heat whenever combustion gas leaves waste
heat recovery equipment. The gas from the airblown
process, on the other hand, results in about 25
percent more combustion gas than that which results
from natural gas combustion. Dew point of the K-T
theoretical combustion gas (124°F) is slightly lower
than that resulting for theoretical combustion of the
other gases used in the comparison (129° to 135°F),
so that no problems are expected with operation of
waste heat recovery equipment with the K-T gas.
Combustion gas, resulting from K-T utility gas,
contains a higher concentration of CO2 than that
from the other gases (23.2 percent versus 9.9 to 18.3
percent), resulting in increased emissivity of the gas.
This is advantageous in the operation of boiler
radiation sections.
Gas turbines operate in practice with excess air to
insure complete combustion as well as to control
firing temperatures. Table 5 presents a comparison of
the K-T gas versus other gases wherein the maximum
theoretical firing temperature is controlled at
1,950°F—typical for firing temperature of present
generation gas turbines and at a firing temperature of
2,400°F, which has been projected by turbine
manufacturers for advanced generation machines. As
can be seen, the K-T gas results in no sacrifice of the
all-important mass flow through the gas turbine. Most
of the combustion gas weight results from air which
must be compressed and supplied to the turbine
combustor. Air constitutes a higher proportion of this
weight, (97-98 percent) in the case of natural gas,
than that which occurs in fuels derived from coal
gasification.
Recently, much attention has been focused on the
control of oxides of nitrogen from combustion
sources. Formation of these oxides is influenced by
combustion temperature; (a 200°F increase in
temperature can more than tripple the rate of NOX
formation); hence, a number of successful techniques
are being used on boilers and gas turbines to control
the maximum combustion temperature. These
methods include water injection into gas turbines and
stage-firing techniques on boilers. Much of the recent
development work is concentrated on so-called "dry
fix" methods which employ burners designed to
obtain rapid and effective mixing of the fuel with air
to maintain low temperature and short residence time
at the burners. Combustion methods designed for
NOx abatement often present secondary
disadvantages. For instance, field work is being done
by some investigators to control NOX by combustion
with less than theoretical air (off-stoichiometric
firing) in order to reduce both the temperature and
the concentration of free oxygen in the combustion
gas. Unfortunately, this process leads to problems
with corrosion or with incomplete combustion and
unwanted side products such as ammonia. Therefore,
the success of NOX abatement technolgoy is difficult
to predict without extensive field work or without
thorough attention to design details.
The K-T gas affords a higher maximum flame
temperature (4,280°F) than that which occurs for the
other gases used in the comparison (figures 6 and 7);
thus, the K-T gas is well-suited for high temperature
applications. However, in the case of gas turbines,
firing temperatures are prescribed by the design of
critical hot gas components of the turbine. On other
combustion equipment, high temperature may be
prohibited by NOX formation, in which case, excess
air is merely added.
The K-T utility gas offers important properties not
available with natural gas, insofar as design of NOX
control systems are concerned. In order to sustain
combustion at the burner, the fuel-air mixture must
be within the explosive limits, which is an important
consideration in design of premix burners commonly
used on turbines. Table 5 compares the combustion
characteristics of other gases with those of the K-T
utility gas at the lean explosive limits. As can be seen,
if more than 86 percent excess air is added to natural
gas at the burner, the fuel-air mixture will not ignite.
At this level of excess air, the theoretical flame
temperature is greater than 2,700°F. Therefore, when
firing temperatures are to be controlled, it is the
practice with some combustors operating on natural
gas to use dilution holes (or alternate aerodynamic
methods), to add excess air between the burner and
the entry to the turbine nozzles. These dilution holes
are placed as close to the burner as possible to
minimize the time at which the gas is exposed to high
temperature without extinguishing the flame. The
K-T utility gas, however, has such a low lean
explosive limit that up to 453 percent excess air may
be added at the burner, resulting m a flame
temperature of about 1,600°F, which is still above
the auto-ignition temperature of the gas. Hence, for
firing temperatures in the range of 1.950-2,400°F,all
of the required excess air could be added directly at
the burner in the case of the K-T gas, and no "peak"
temperature is experienced. Peak flame temperatures
can also be controlled by maintaining fuel-rich
conditions at the burner, e.g., m stage-firing of
boilers. The K-T gas again offers an analagous
128
-------
36OO
KOPPERS-TOTZEK QAS
o% excess AIR
BI-OAS
QAS PROM
AIR-BLOWN
FIXED
LIMIT
FLAMMABILITY
TEMP. OF ADVANCED
OAS TURBINES
TEMP. OF PRESENT
GAS TURBINES
25
SO
75
1OO
125
LB.-MOLE AIR fa) 60O°F/MILLION
NET BTU OF FUEL
RANGE: O% EXCESS AIR TO LOWER
LIMIT OF FLAMMABILITY
FIGURE 6. FLAME TEMPERATURE VERSUS
AIR USED FOR COMBUSTION
advantage to natural gas in this instance, since the
rich flammabihty limit of the K-T gas is much higher
than the rich flammability limit of natural gas (75
percent versus 15 percent fuel in fuel-air mixture). A
fuel such as the K-T gas, with a high ratio of
rich-to-lean flammabihty limit, will display excellent
combustor performance.
Simplicity controlabihty and reliability of the K-T
process are important factors in the operation of a
clean and environmentally acceptable gasification
plant. As reported in the pollution evaluation report,
K-T plants can be designed to meet current
environmental codes. We in Koppers believe that
these codes can be attained with current technology
and equipment at economic costs.
129
-------
14OO
FLAME TEMPERATURE
VERSUS EXCESS AIR
USED FOR COMBUSTION
LOWER LIMIT
FLAMMABILITY
1OO% 2OO% 30O% 40O%
PERCENT EXCESS AIR @ 6OO°F
RANGE: O% EXCESS AIR TO LOWER
LIMIT OP FLAMMABILITY
FIGURE 7
50O%
130
-------
ENVIRONMENTAL ASPECTS OF THE BI-GAS PROCESS
R. J. Grace and E. K. Diehl*
Abstract
Because of the basic nature of the BI-GAS process,
control of those elements of the process that might
potentially affect the environment is believed to be
well within the realm of current, known technology.
Coal preparation is essentially no different than
that which is considered common practice in the
power industry today. Reactive components in the
coal are completely used in the process, and the ash
for disposal is in the form of granular, vitreous slag.
Sulfur appearing in the feed coal is ultimately
transformed in the process to its elemental form by
way of the gas cleanup system and its subsequent pass
through a conventional Cfausplant.
The severity of the gasification step results in
minimum formation of those compounds mat are
normally considered potential water pollutants.
Thus, environmental aspects of the BI-GAS process
center more on those factors that are associated with
the production of coal, handling of slag, and supply
of process water, rather than on anything unique in
the process itself.
INTRODUCTION
It is obvious that any new development such as the
conversion of coal to supplement natural gas supplies
will have some unavoidable effect on the
environment. Readily identifiable is the prospect of
an expanded coal mining industry to supply the raw
material for the large gasification plants that are
projected as being necessary during the next several
decades. Many of these plants will be located on sites
adjacent to coal deposits that can best be won by
stripping operations. Thus, ecological effects of such
operations will represent an important facet of the
new coal-to-gas industry. Adherence to good mining
practices, plus the promise of new developments in
the technology of mmed-land reclamation, should
serve to minimize any permanent, irreversible impact
upon the environment.
'The authors are with the Bituminous Coal Research, Inc.,
350 Hochberg Road, Monroeville. Pennsylvania 15146.
TFor purposes of protections and conceptual design
studies, a commercial plant is defined as having the capacity
to produce 250 million standard cubic feet per day of SNG.
The total water requirements for commercialt coal
gasification plants are estimated to be in the range of
27 to 32 million gallons per day, depending upon the
rank of the coal gasified. If partial air cooling is
employed, water requirements can be reduced to
between 14 and 16 million gallons per day. In either
case, a portion of the water supplied, approximately
2.5 million gallons per day, is consumed in the
process to provide hydrogen for gasification. Water
availability and water management, therefore, are
other areas where environmental compatibility will
have to be considered.
Another and often overlooked ecological effect is
the "people factor." For example, a commercial coal
gasification plant would employ approximately 370
persons. This group would include operating
personnel, maintenance crew, and the associated
supervisory, technical, and clerical personnel.
Additional manpower would be required for other
steps in the total operations. Depending upon the
specific gasification process, power plant
requirements could add as many as 230 persons to
the total plant force.
Separate from the coal gasification plant itself is
the manpower required to supply the coal. Assuming
that there is a plant production requirement of
15,000 tons per day, the mining workforce would
range from 434 men for strip mine operation to
1,340 for deep mine operation. These estimates are
based on recent productivity figures {ref. 1) of 11.2
tons per man per day for underground mines and
34.6 tons per man per day for strip mines.
It is conceivable, then, that a commercial coal
gasification installation, including coal production
facilities and depending upon its location, could
develop a manpower requirement of as many as 1,940
employees. Assuming that each employee represents a
family of four, nearly 8,000 people would be related
directly to the plant. Since most plant sites would be
near the coal, and therefore not near existing towns,
it is probable that new communities would need to be
established. Already, new communities are being
designed to handle the expected influx of people.
Though only indirectly related to the environmental
impact of coal gasification technology, the ecological
effects of the "people factor" would demand serious
consideration.
Each of the above is a part of the environmental
131
-------
impact of all gasification processes. The problems
created by each are receiving the attention of
knowledgeable experts and are separate and apart
from the environmental aspects of the technical
process.
The Bl-GAS Process
It should be emphasized at the outset that specific
details regarding the environmental impact of the
BI-GAS process cannot be established factually at this
stage in the process development. When the pilot
plant, now under construction at Homer City,
Pennsylvania, is operational in mid-1975, many of the
unit operations will be tested for the first time.
Operation of the pilot plant will be in the nature of
process research. Experience during operation may
well bring about some changes in the process that
could influence design of the subsequent commercial
plant.
Nevertheless, certain features of the BI-GAS
process can be assessed in relationship to their
influence on the environmental compatibility of the
process. The heart of the BI-GAS process is the
two-stage gasifier which uses coal in entrained flow.
(See fig. 1.) Fresh pulverized coal will be introduced
into the upper section (Stage 2) of the gasifier at
pressures in the range of 70 to 100 atm. Here, the
coal will come in contact with a rising stream of hot
synthesis gas produced in the lower section (Stage 1)
and be partially converted into methane and more
synthesis gas.
The residual char entrained in the raw product gas
will be swept upward and out of the gasifier. The char
will be separtated from the product gas stream and
recycled to the lower section (Stage 1} of the gasifier
In the lower section, the char will be completely
gasified under slagging conditions with oxygen and
steam, producing both synthesis gas and the heat
required in the upper section (Stage 2) for partial
gasification of the fresh coal.
The raw product gas from Stage 2 will be shifted to
adjust the hydrogen to carbon monoxide ratio,
purified by removal of hydrogen sulfide and carbon
dioxide, and upgraded in Btu content to pipeline
quality by catalytic methanation.
From the standpoint of environmental
consideration, several advantages of the BI-GAS
concept are:
1. Because it employs an entrained rather than a
fixed- or fluidized-bed system, all types of coal
should be amenable without special preparation or
prior pretreatment;
2. All feed coal is consumed in the process, and
3. Principal byproducts are slag for disposal and
elemental sulfur.
The actual daily coal requirement for the BI-GAS
process will vary somewhat, depending upon the rank
and source of the coal. The quantities presented in
this paper are based upon the pilot plant design and
reflect the use of Pittsburgh seam coal containing
7.03 percent ash and 2.46 percent sulfur.
Coal Preparation
Using Pittsburgh seam coal, a commerical BI-GAS
plant would gasify about 12,000 tons per day. An
estimated additional 1,700 tons per day would be
required for auxiliary purposes such as for steam
generation and drying. Thus, the daily coal
requirement for the process would be some 13,700
tons per day of cleaned coal.
Assuming a 25 percent refuse loss from cleaning,
18.267 tons per day of run-of-mine coal will be
processed in a cleaning plant at either the mine site or
at the gasification plant. In either case, conventional
cleaning, with the necessary environmental control,
can be applied. Refuse for disposal will amount to
4,567 tons per day.
Further coal preparation consists only of reducing
the size of the cleaning plant product (1% inch X 0)
to the size required for the process; namely, 70
percent minus 200 mesh. The grinding and
pulverizing will be done in two stages. The coal is first
reduced in a cage mill. The cage mill product is
pulped with water, and final pulverization is
accomplished in a wet ball mill.
The latter stage, wet pulverization, is incorporated
into the process as a step in the subsequent high
pressure slurry feed system. Its use, however, will
eliminate some of the potential dust problems that
are associated with dry pulverization and with
transport of dry pulverized coal.
Slag
As mentioned earlier, 12.000 tons of coal per day
will be completely consumed in gasification. The slag
produced will amount to 844 tons per day.
In the BI-GAS gasifier, molten slag from Stage 1
will drop into a reservoir of water for rapid
quenching, thus causing the slag to shatter into small
pieces. The resulting granules of vitreous slag will be
removed to a settling pond. Clarified water from the
settling pond will be recycled, and the slag will be
removed for disposal.
While the exact nature of the slag produced from a
132
-------
Coal
Steam
Steam
Stage 2
Gasifier
Cyclone
CO-Shift
Gas Purification
and
Methanation
Recycle Solids
Stage 1
Oxygen
Slag
Pipeline Gas
Figure 1. Simplified Flow Diagram for the BI-GAS Process
133
-------
particular coal under BI-GAS Stage 1 conditions is
yet to be determined, it is not expected to be too
unlike that which results from conventional slag-tap
boiler operation. The vitreous nature of the slag
should minimize concern over water-leaching in the
event that the material is returned to the mine site or
is used elsewhere as land fill. It is possible that a
productive use of the slag may be found that would
change a process waste into a useful material.
Sulfur
About 95 percent of the sulfur entering with the
coal is expected to leave the gasifier as hydrogen
sulfide. The remaining sulfur will leave in compounds
such as carbonyl sulfide and carbon disulfide. The
sulfur in these compounds will be hydrogenated into
hydrogen sutfide after passing through the catalyst
guard filters upstream of the shift reactor. As a
consequence, it appears that all of the sulfur in the
gas will enter the acid gas removal facilities as
hydrogen sulfide.
Hydrogen sulfide will be removed from the gas
stream in a SELEXOL unit and converted to
elemental sulfur in a Claus unit. Both of these steps
presently meet environmental standards.
About 295 tons of sulfur per day will be produced
in the commercial BI-GAS plant. In its elemental
form, it will be the most compatible with
environmental requirements.
Process Water Contaminants
Because of the conditions existing within the
gasifier, the BI-GAS process is not expected to
produce oils, tars, or phenols, which in some
processes represent an important contaminant in
process water streams. None of these were detected
during the extensive experimental work that preceded
design of the pilot plant. Their absence will be
confirmed when the pilot plant goes into operation.
The major process water contaminant will be
ammonia. The ammonia content of the gas stream is
not known at this time. It has been estimated that
about 70 percent of the nitrogen in the feed coal will
form ammonia in most SNG processes. Based on that
assumption, the BI-GAS process would produce
about 123 tons per day. Most of this would appear in
the water from the gas scrubber and in the shift
condensate. Conventional waste water treatment
methods can adequately remove ammonia, which
may be of sufficient purity for commerical use.
SUMMARY
The information presented should be considered as
the principal environmental aspects quantifiable at
this time. At its present stage of development,
BI-GAS promises some distinct advantages with
regard to its environmental compatibility.
Confirmation of these advantages will necessarily
have to await operation of the total process at the
pilot plant scale.
Process characteristics that are unique to BI-GAS
appear to favor control of some elements of the
overall environmental impact that will accompany a
coal gasification industry. Those problems that are
common to all processes can be solved, to a great
extent, with existing commerical technology and
good engineering practice.
ACKNOWLEDGMENT
This paper is based on work carried out by
Bituminous Coal Research, Inc., with support from
the Office of Coal Research, U.S. Department of the
Interior, under Contract No. 14-32-0001-1207, and
the American Gas Association.
1.
REFERENCE
U.S. Bureau of Mines, Mineral Industry Surveys,
Weekly Coal Report No. 2950, March 29, I974.
134
-------
SULFUR EMISSION CONTROL WITH LIMESTONE/DOLOMITE
IN ADVANCED FOSSIL FUEL-PROCESSING SYSTEMS
Dale L. Keairns, Eoin P. O'Neill, David H. Archer*
Abstract
High temperature sulfur removal can be achieved
with limestone and/or dolomite influidized bed fuel
processing systems, now being developed for power
generation. Westinghouse is developing this process
for low-Btu gasification and fluidized bed combustion
of fossil fuels. The use of limestone/dolomite for high
temperature emission control offers the opportunity
to meet sulfur dioxide emission standards; to
minimize the environmental impact of spent solids;
and to permit greater simplicity and versatility,
increased plant efficiency, and reduced electrical
energy costs over competitive processes.
Alternative sulfur removal system concepts have
been experimentally studied for each fuel-processing
system: once-through and regenerative sorbent
operation, pressurized and atmospheric pressure
operation, spent stone processing, and
disposal/utilization of processed stone. A
thermogravimetric analysis system, capable of
operating at elevated pressure with corrosive gases, is
being used to collect kinetic data over a wide range of
operating conditions-e.g., stone type, temperature,
pressure, particle size, and gas composition.
Illustrative data on sulfur removal and regeneration
are present for each fuel processing system and are
being used for establishing design and operating
conditions.
INTRODUCTION
Westinghouse is working on a multifaceted program
to develop advanced coal, oil, and low-grade fuel
processing for electric power generation (refs. 1,2).
Fluidized bed combustion and low-Btu gasification
processes for fossil fuels are being developed as shown
m figure 1. The fluidized bed coal-gasification process
will be studied in a 1.200 Ib coal/hr process
development unit which will be operational in
mid-1974. A commercial demonstration plant design
*Dale L Keairns. B.S., M.S., Ph.D. Chemical Engineering,
Manager, Fluidized Bed Engineering Research, Eoin P.
O'Neill, B.Sc., Ph.D. Physical Chemistry, Senior Engineer;
David H. Archer, B.S., Ph.D. Chemical Engineering, Manager,
Chemical Engineering Research, Westinghouse Research
Laboratories, Pittsburgh, Pa. 15235.
has been initiated. Commercial power plant designs
for pressurized fluidized bed combustion systems
have been completed (ref. 1). Laboratory and pilot
plant tests have been and continue to be carried out
by several contractors as part of the EPA and OCR
program. A preliminary design for a 30 MW
pressurized fluidized bed combustion boiler
development plant has been completed. Preliminary
design studies have been carried out for the
pressurized oil gasification system. Fluidized bed oil
gasification at atmospheric pressure has been studied
by Esso (U.K.) in a 1 MW pilot plant (ref. 4). A 50
MW demonstration plant design is underway (ref. 1).
These processes offer a solution to the problem
posed by the apparently conflicting and urgent
requirements of efficient power generation and
pollution abatement. Each of these processes has the
potential to reduce power plant capital costs; increase
overall operating efficiency, minimize emissions of
SO2, NOX, and particulates; and avoid the generation
of other environmental problems. The technologies
involved in the four processes have fundamental
similarities as illustrated in figure 1. One similarity is
the use of limestones and/or dolomites for high
temperature sulfur removal during the fuel-processing
step.
The sulfur removal system concepts explored
utilizing limestone and/or dolomite are illustrated in
figure 2. The sulfur is removed in solid form as
calcium sulfate or calcium sulfide with greater than
90 percent reduction in sulfur emission (ref. 5). The
spent stone may be regenerated to produce a reusable
sorbent for sulfur removal. The sulfur-rich gas
released as sulfur dioxide or hydrogen sulfide during
the regeneration process could be sent to a sulfur or
sulfuric acid recovery plant. This provides the
opportunity to minimize the sorbent feed
requirements and the spent stone. The molar feed
requirement of calcium to remove each mole of sulfur
in the fuel may be significantly less than one, the
stoichiometric ratio, for this regeneration process
option. Regeneration of the sorbent to minimize the
stone requirements is desirable; however, sulfur
recovery may not be desirable or economically
attractive. An alternative regeneration process
concept can be employed in specific cases which does
not require sulfur recovery. The sulfur-rich gas from
the regeneration process can be stoichiometrically
135
-------
COAL GASIFICATION —
COMBINED CYCLE PLANT
Fluidlted Bed
Devolotiliier/
Deeulfuriier
Particular
Removal
COAL COMBUSTION -
COMBINED CYCLE PLANT
Particular
Removal
Y
OIL GASIFICATION —
COMBINED CYCLE PLANT
Gatlfitr Detulfui
irlxer
Oil-*
Limestone—*
O-eatn
BOO°F
Porttculote
Removal
Steam
Hot Fuel Gas
(200-400 Btu
-••Spent Stone
(Gas)
OIL GASIFICATION—
CONVENTIONAL BOILER PLANT
Oil-*
Heat
Stack Gas
t
Boiler
High Temperature
Go* Comtauitor
Compressor
Turbine
>-©
S Genen
Air
Generator
09E
0 »EtTurblneY
High Pressure-Hot Flue Gas
Limestone —•
(CaCOj)
Gas To Heat Spent Stone •*-
Recovery and Stack 4 (CaSO*)
T .Compressor
«02Et,
Air
Turbine
Heat^ecover,
Stack Gas
t
High Temperature
Gas Combustor
Turbine1
Compressor
Ve
r Generator
(O.SEt)
Air
Stack Gas
Conventional
0-C
Generator
(OSEJ
^
Turbine
Limestones
(CoC03)
ISatn K I
V
—•> Spent Stone Y
j—" (CaS) ^
FIG. I. FLUIDIZED BED FUEL PROCESS ING FOR POWER GENERATION FROM FOSSIL
FUELS
136
-------
u
Fresh
Limestone *
or Dolomite
High
Sulfur
Fossil
Fuel
Fuel
Processing/
Sulfur Removal
System
Spent Stone
Spent Stone
Sopnt Stnnp .—
Regenerated
Stone
Wasl
Stor
(Ca/S
Spent Stone •-
D^/ionArortAH «
Rcycner aieu
Stone
Ca/S>l
Spent
Proce
Stone Ca/S>l
ssing
Regeneration
te »
le
<1)
Disposal/
* Utilization
Disposal/Utilization
* (including sulfur
recovery options)
Sulfur Rich _«,„.._,
Gas
Spent Stone
Processing
Regeneration
W«
St
(Ca/!
iste
one
5-1)
Sulfuric Acid
^ Disposal/ Utilization
(including sulfur
recovery)
Sulfur Rich
Gas
i
Stone
Processing
^Solids Disposal/
* Utilization
Figure 2- Sulfur removal system process concepts
-------
reacted with a side stream of stone from the
regenerator to produce calcium sulfate in a separate
vessel. This concept provides the potential to
maintain the stone requirement near stoichiometnc,
to produce a solid suitable for disposal, and to
eliminate the requirement for sulfur recovery. The
sulfur removal system may also be operated as a
once-through sorbent system. The spent stone may be
processed for disposal without regeneration or may
be suitable for direct disposal as in the fluid bed
combustion system when operated to produce
calcium sulfate/calcium carbonate. The once-through
option results in a greater stone requirement and
higher operating cost which must be balanced against
the potential for reduced capital cost, reduced space
requirements, increased plant efficiency, and
improved reliability.
Experimental Program
Laboratory support studies are being carried out at
Westmghouse to demonstrate the alternative steps in
the sulfur removal system concepts (ref. 6). The
overall object of the study is to determine the
optimum operating conditions for sulfur removal
systems within the engineering restraints imposed by
the energy-recovery objectives of the system.
APPARATUS
The primary experimental study is centered on the
use of a specially modified thermogravimetric
apparatus (TG). The TG is an electrically recording
balance which measures the changes in weight of a
solid suspended from the balance arm in an
electronically controlled furnace. The gaseous stream
flowing over the solid and the temperature of the
furnace may be adjusted or altered as desired, within
specifiable limits. The capability to study gas/solid
reactions at pressures up to 30 atmospheres at
temperatures up to 1,200°C and provision for the use
of corrosive gases at pressure required modifications
to the commercial TG systems which have been
described elsewhere (ref. 1). The primary data are the
rates of the gas-solid reactions under the experimental
conditions of sorbent pretreatment, temperature,
pressure, gas composition, sample geometry, gas flow
in the reactor, and the extent of reaction, or
utilization of the sorbent.
With this equipment, it is possible to measure
limiting rates of reaction under conditions where
properties internal to the sorbent prevent efficient
application of the reactions. It also provides a
measure of the capacity of the sorbent samples for
reaction (extent to which the solid reacts).
SCOPE OF EXPERIMENTAL PROGRAM
Fundamental data are required to determine the
feasibility and optimum conditions for each
processing step in each sulfur removal system, i.e ,
removal, regeneration, spent stone processing, and
confirmation of inactivity of the waste stone for
disposal. Thermogravimetric studies pertinent to each
of these areas have so far involved over 300
experiments on the reactions of limestone, dolomites,
and their chemical derivatives. These experiments
include routine tests for stone selection, su If at ion and
cyclic sulfidation-sorbent regeneration experiments,
feasibility tests on variations of recarbonation or
resulfation processes for dry spent stone disposal, and
activity tests on processed stone for disposal.
Illustrative examples of results and conclusions in the
areas of sulfur removal and sorbent regeneration are
presented in this paper to demonstrate the
contribution such a study makes to the overall
objectives of developing commercial sulfur removal
systems for advanced fossil-fuel-processing systems.
The results of this work have been and are being used
as a basis for sulfur removal system design and
economic studies, for both fluidized bed combustion
and fluidized bed gasification processes.
SORBENT FORM
Gasification or combustion in a pressurized system
(10 or 15 atmospheres) utilize combined gas and
steam turbines for power generation which can
provide increased overall plant efficiency. The
immediate impact of the pressurized options on the
sulfur removal process is to necessitate operation
under conditions where calcium carbonate rather
than calcium oxide is the stable form of the
dolomite/limestone sorbent.
In figure 3, the proposed operating conditions for
the pressurized fluidized bed coal gasification system
(ref. 2) are shown to favor stability of calcium
carbonate rather than calcium oxide. In figure 4,
proposed operating conditions for two pressurized
fluidized bed combustion systems lie in the region of
pressure and temperature where either the carbonate
or oxide form of the dolomite is stable. The
sulfidation and sulfation reactions of both
fully-calcined and half-calcined dolomites have been
studied at atmospheric pressure and at 10
atmospheres pressure in order to anticipate the widest
range of operating conditions.
138
-------
930
920
e
900
890
870 -
I Ml boundaries Shown Have Been Cjli uljted
From Ddld lor tne Reaction CaCO, ^r LdO +
Given by --Curran'
• Stern8
o Hills'
CO
Fully-Calcined Dolomite
MtjO CaO Stable in
this Region
Half-Calcined Oolomiie
MgO CaCOj Stable
in this Region
Operating
Condition
1700
1650
- 1600
JL
10 li ft 13 It 15 16 17 '
Total Pressure, atmospheres!7.E54COJ
Figure 3 -lernperature anil pressure conditions iar stability of the sorbent as hall-calcined dolomite at the protected
desulfuruer outlet conposilion of 7 85-1 CO,
990
950
The Boundaries Shown Have Been Calculated
From Data For The Reaction CaCO$ ~ CaO + C02
Given By Curran'
10% Excess Air
T
11 12 13 14 15
Total Pressure, Atmospheres
Figure 4- Temperature and pressure conditions for stability of the
sulfur sorbent as half-calcined or fully-calcined Dolomite at
projected combustor outlet gas compositions
139
-------
Sulfur Removal
The successful demonstration of the primary sulfur
capture process has long outdistanced any
understanding of the fundamental mechanisms, which
limit attainment of thermodynamic y.elds. While this
success might be thought to obviate the need for
further investigation, it is clear that the current limits
to the flexibility of the processes, and hence to their
usefulness, are bounded by physical conditions which
cannot be readily optimized since their effects have
not been fully explained.
For each of the major fuel-processing options,
desulfurization of the product gases has been
convincingly demonstrated in fluidized beds, within
limiting conditions, by workers at Argonne (ref. 11);
Esso (U.K.) (ref 4); Exxon (ref. 12); Consolidation
Coal (ref. 13); Pope, Evans, and Robbms (ref. 4); the
U.S. Bureau of Mines (ref. 15); and the National Coal
Board (U.K.) (ref. 16).
EFFICIENCY OF SORBENT UTILIZATION
IN COMBUSTION SYSTEMS
Sulfur removal in the fluidized bed combustion
process is affected by at least 13 variables (ref. 5).
Since some of these variables (e.g., temperature.
pressure) have a direct bearing on the kinetics of the
chemical reactions, their influences have been studied
in the TG apparatus and the data so obtained has
reproduced the performance of existing fluidized-bed
reactors (ref. 17). This ability to correlate TGA data
with fluidized bed data has been important in
establishing the utility of the TGA.
One important result from the sulfur removal
studies under oxidizing conditions relates to the
efficiency of use of the sorbent. A substantial body
of data shows that Ca/S molar ratios of 2.5 or greater
must be maintained in the fluidized-bed in order to
achieve 90 percent capture of the S02 liberated from
the fuel. This molar ratio corresponds to a mean
sulfation level of 36 percent of the CaO in the
fluidized bed. The results obtained with limestone
frequently correspond to even lower levels of
sulfation at the point where fresh sorbent must be
added to retain sulfur removal efficiency.
With dolomite as the sorbent. TG studies have
shown that (35 to 40 percent) sulfation is a critical
region for the kinetics of sulfation where a transition
occurs from a rapid reaction rate to a slow product
diffusion-controlled rate. This phenomenon is evident
in both the atmospheric pressure and pressurized TG
data. The relationship between the reaction rate tor
sulfation and the type of porosity in the calcined
stone has been convincingly demonstrated by
Borgwardt (ref. 18). Since the stone pore structure is
established as it calcines, this phase of the process
offers the possibility of altering the reaction
conditions to generate in the stone the desired pore
structure. The result of favorably altering the
conditions of calcination is shown for the pressurized
case in figure 5; the capacity of the stone to react
with SO^ in the fast phase of reaction has been
doubled. If 'this process can be duplicated in
fluidized-bed reactors, then a Ca/S mole ratio of
approximately 1.25 will suffice to meet S02 emission
standards, yielding a more homogeneous product
with less residual calcium carbonate or calcium oxide
(depends on operating conditions) and halving both
the quantities of fresh sorbent required and the waste
stone disposal burden.
Pressurized TG experiments show that half-calcined
dolomite reacts with SO 2/air mixtures at a rate
comparable to calcined dolomites (ref. 1). Since the
rapid deceleration of rate at approximately 36
percent sulfation noted with calcined stone does not
occur with half-calcined dolomite, utilization up to
about 60 percent can be projected for this stone. As
the decline in rate with sulfur load is not abrupt,
increased sorbent efficiency is attainable with modest
increases in gas residence time in the bed.
The pressurized fluidized bed combustion process
can be operated without heat transfer surface in the
combustor by operating with high excess air (ref. 1).
Consideration of the adiabatic combustion system
using 300 percent excess air as the heat sink to supply
power to a gas turbine in a pressurized combustor led
to the speculation that the increase in oxygen
concentration would increase the sulfur removal
efficiency by driving the equilibrium for reaction
toward the production of calcium sulfate and by
increasing the rate of attainment of equilibrium.
Experiments were carried out on the TG in which
the oxygen concentration was increased to 11 percent
at 10 atmospheres pressure. Since only minute
increases in reaction rate were observed on increasing
the oxygen fraction in the sulfating gas, the prospect
of enhancing the efficiency of sulfur removal in this
fashion can be ruled out (ref. 1). However, increasing
the partial pressure of osygen may be beneficial in
extending the temperature range for efficient sulfur
removal, indicating that the complexity of interaction
of the process variables requires a thorough
investigation.
140
-------
i—i—\—i—i—i—i i r
i—r
.40
.38
.36
.34
.30
**<%
420-500 Mm
5,000 ppm SOfc
4% 02 in N2
871°C
1.03x
CaS04
Calcined in C02
Calcined in N2
Calcined in C02
Calcined in N2
I I I I I I I
24 6 8 10 12 14 16 18 20 22 24 26 28
Time/Minutes
Figure 5-Comparison of pressurized sulfation of limestone and dolomite
141
-------
EFFICIENCY OF SORBENT UTILIZATION
UNDER REDUCING CONDITIONS
(Coal and Oil Gasification)
For the coal gasification process, TG studies at 10
atmospheres pressure have shown that sulfidation of
half-calcined dolomites proceeds rapidly up to greater
than 90 percent utilization of the sorbent CaCO3
content, at temperatures in the range 870-930°C and
with particle sizes up to 2,000 jum in diameter. The
primary desulfurizing reaction will not limit sulfur
removal in this system, and other factors such as
stone attrition in the fluidized bed are likely to limit
the performance of the process.
The retention of sulfur in fluidized-beds of calcined
lime under reducing conditions at atmospheric
pressure has been demonstrated by Esso at Abmgdon
(England) (ref. 4). A perplexing feature of their work
has been the decline in sulfur removal activity at low
sulfur loading of the sorbent stone (corresponding to
about 15 percent utilization of the CaO). The
sulfidation of dolomite was shown by Pell (ref. 19) to
proceed to completion. Our studies of calcined
limestones, ranging from high-purity CaC03 to
dolomites, indicate that little decrease in rate occurs
before 30 percent of the CaO is sulfided in 1,000 Aim
particles. At higher utilization, the rate of reaction
observed on the TG reflects the calcium oxide
concentration in the particular limestone (ref. 1).To
date, we have not succeeded in explaining the poorer
performance of the stones in the pilot plant
fluidized-bed oil gasifier. Figure 6 shows the current
projection of our data to the physical dimensions of
the Esso gasifier.
Possible explanations for the decline in activity
which have been advanced, include:
(1) A diffusional barrier to reaction which is
created by the carbon which deposits, during
gasification, on the sorbent surfaces;
(2) Sintering of the calcined stone at 870°C during
its residence in the gasifier bed;
(3) The cycle of oxidizing-reducing conditions to
which the stone is exposed causes a buildup of
calcium sulfate in the pores of the stone, hindering
transport of the sulf iding gases;
(4) The conditions of sulfur removal in the pilot
plant, e.g., location of oil injection, bed depth, etc.
The ability to achieve high utilization in the
atmosphenc-presure oil gasification process would
enhance the attractiveness of a once-through sorbent
process. Experiments are continuing to develop the
potential for high utilization which is evident from
the experimental data.
100
E 80
.E
c
o
0>
•5J
CO
"c
o>
fc?
CD
Q_
60
40
20
TG Data On
Sulfidation of Calcined
Limestone Applied To First Order
Model of Fluidized Bed
Esso CAFB Fluidized Bed Results
For Run 14 Using 13,000-1,0001 urn Limestone
I
I
I
I
I
I
2.0 4.0 6.0 8.0 10.0 12.0
CaO Percent Utilization
14.0 16.0 18.0
Figure6-Comparison of Esso CAFB oil gasification desulfurization and the
projection of fluidized-bed results from thermogravimetric data
142
-------
Regeneration of Sulfur Sorbent
The regeneration of the spent sulfur sorbent in a
usable form (\ e., with retention of its activity for the
sulfur removal reactions) with or without recovery of
the sulfur is economically and environmentally
desirable. In a regenerative system, less sorbent is
required, less waste produced, and the byproduct
sulfur may be used rather than discarded.
Several regeneration processes-atmospheric and
high pressure-have been considered (ref. 1). The
following pressurized regenerative process reactions
have been studied:
Results of these tests have been resported (refs. 1,6).
The first step, reduction of calcium sulfate to
calcium sulfide, proceeds readily to completion (refs.
6,20) and it is the second step (conversion of calcium
sulfide to calcium carbonate) which is crucial to
success of the process. TG studies at 10 atmospheres
pressure show that calcium sulfide is only partially
regenerable and that the nonregenerable fraction
increases as the sorbent is cycled between sulfidation
and regeneration. The activity of the sorbent in sulfur
removal decreases by approximately 3 percent of the
sulfidation rate per cycle as shown in figure 7, and is
CaS04 +
REACTION
4 CO
(4 H2> 10 ATM
CaS
4 C02
(4 H20)
APPLICABLE PROCESSES
Fluidized Bed Combustion
CaS
H20
C0
10 ATM
CaC0
3 + H2S
Fluidized Bed Combustion
Coal Gasification
Oil Gasification
.18
•| .16
1 -14
eu
o.
Z3
to •
3. .10
c
0
'•g .08
ra
| .06
'o
Q .04
.02
1 1 1 1 1 I 1 1 1
_ 0
o
MgO Ca CO + H,S « MgO CaS i
— ~ .^.
i o
-L— Q o
00
o
o
10 Atmospheres
1600F
1 1 1
_
hH20+C02
_
"~° w
-------
apparently not a critical factor. Thus the critical
phenomenon in regeneration has been identified as
the extent of reaction to form CaCO3 under
conditions which yield a sufficient concentration of
hydrogen sulfide for recovery in a Glaus system.The
decrease in regenerability on cycling the sorbent is
shown in figure 8, over a 21-cycle run. Since the stone
makeup rate will be partially governed by attrition
losses, 20 cycles is considered an acceptable sorbent
lifetime. Each mole of calcium transferred 4.7 moles
of sulfur to the regenerator during the run and, since
it would be discarded from the sorbent cycle in the
sulfided condition, can be projected to trap > 5.5
moles of sulfur. Decreasing the regeneration
temperature would improve the recovered
concentration of H2S, but would decrease the
regenerability of the stone. It has been noted in the
TG experiments that when regeneration rates become
negligible, the reaction is revived by increasing the
temperature. Further work on this aspect of the
problem continues to explore methods for improving
the yield of calcium carbonate in regeneration.
In assessing the value of kinetic results obtained by
the TG on these processes, it is pertinent to recall
that we are determining the conditions under which
thermodynamically favorable chemical reactions
become rate limiting in the overall process. The
projection that good sulfur retention and high
utilization of the CaO should be attainable in
fluidized beds is simply a statement that the chemical
reactions will not of themselves prevent the desired
conversion. In the actual situation of a fluidized bed,
some other process may intervene to become
rate-limiting, such as attrition of the sorbent,
coal-ash-sorbent agglomeration, tar deposition on the
sorbent, or eutectic formation. However, the
probability of overcoming such problems is enhanced
when the reaction rate itself is known to be favorable,
and can be eliminated from consideration as a source
of poor sulfur retention.
CONCLUSIONS
Low-Btu gasification and fluidized bed combustion
can employ high temperature sulfur removal with
limestones and/or dolomites to reduce the cost of
electrical energy, increase overall plant efficiency, and
avoid the generation of environmental problems. A
Regeneration
lOAtm
704°C
10% H20
10% CO
lOAtm
871°C
0.5%H2S
10% HoO
1200-1000 um Dolomite (1337)
TG No 307
10
Cycle Number
Figure 8-Cyclic regeneration of CaC03 in sulfided dolomite
144
-------
thermogravimetric analysis system, modified to
operate at high pressures and temperatures, has
provided a reliable and efficient method to obtain
design data. The results presented show:
(1) High utilization (1.2 to 1.5 Ca/S molar ratio)
of calcium in limestones/dolomites for sulfur removal
in pressurized fluidized bed combustion can be
achieved. This minimizes the sorbent requirement and
permits the use of a once-through sorbent process
wich has low cost, high efficiency, minimum
complexity, and high reliability.
(2) Sulfur removal under reducing conditions
approaches the stoichiometric maximum capacity of
the sorbent. Sulfur removal under reducing
conditions is not a limiting process step.
(3) Regenerability of CaS decreases on cycling
{21 -cycle test) and represents the limiting process
step in the gasification sulfur removal system.
(4) TG systems can be effectively used to
investigate fundamental chemical problems,
determine the feasibility of processes, assess the
effect of system modification, and provide design
data.
Acknowledgments
This work is being carried out by Westinghouse
Research Laboratories under contract to the Office of
Research and Development, Environmental
Protection Agency, and the Office of Coal Research,
Department of the Interior. Mr. P. P. Turner serves as
the EPA Project Officer; Mr. P. Musser serves as the
OCR Project Officer.
REFERENCES
1. D. L. Keairns et al.( "Evaluation of the Fluidized
Bed Combustion Process," Westinghouse
Research Labs, final report to the Environmental
Protection Agency, Vols. I. II, III, IV,
(EPA-650/2-73-048a,b,c,d), December 1973.
2. S. Lemezis and D. H. Archer, "Coal Gasification
for Electric Power Generation," Combustion Vol.
45, No. 5 (1973). p. 6.
3. D. H. Archer et al., "Coal Gasification for Clean
Power Production," Proceedings of the Third
International Conference on Fluidized Bed
Combustion, Hueston Woods. Ohio (1972),
issued as EPA 650/2-73-053, December 1973.
4. J. W. T. Craig et al., (Esso) Final report to EPA
on contract CPA 70-46, Report No.
EPA-R2-72-020, June 1973.
5. D. H. Archer et al., "Evaluation of the Fluidized
Bed Combustion Process," Westinghouse
Research Labs, final report on contract CPA
70-9, PB 211-494, PB 212-916, PB 213-152
(November 1971).
6. E. P. O'Neill. D. L. Keairns, and W. F. Kittle,
Proceedings of the Third International
Conference on Fluidized Bed Combustion,
Hueston Woods, Ohio (1972), sponsored by EPA,
issued as EPA 650/2-73-053, December 1973.
7. G. P. Curran, C. E. Fink, and E. Gorin
(Consolidation Coal Co.), "CO2 acceptor
gasification process in Fuel Gasification,"
Advances in Chemistry Series 69, American
Chemical Society, Washington, D.C., 1967 p.
141.
8. K. H. Stern and E. L. Weise, "High temperature
properties and decomposition of inorganic salts,
Part 2, Carbonates," NSRDS-NBS 30, National
Bureau of Standards, Washington, D.C., 1969.
9. A. W. D. Hills, Transactions/Section C of the
Institution of Mining and Metallurgy, Vol. 76.
C24I, 1967.
10. Chemical Rubber Co. Handbook, ed. Weast, 53rd
edition, F66, 1972.
11. A. A. Jonke et al., "Reduction of atmospheric
pollution by the application of fluidized-bed
combustion," Rept. ANL/ES-CEN 1002.
Argonne National Laboratory, 1970.
12. A. Skopp, J. T. Sears, and R. R. Bertrand, "Fluid
bed studied of the limestone based flue gas
desulfurization process," Final Report PH
86-67-130, NAPCA. 1969.
13. C. W. Zielke et al., "Sulfur removal during
combustion of solid fuels in a fluidized bed of
dolomite," paper presented at the Am. Chem.
Soc. Mtg., New York City, 1969.
14. E. B. Robison et al., "Study of characterization
and control of air pollutants from a fluidized-bed
combustion unit," report on contract CPA 70-10
by Pope, Evans, and Robbins, Inc. to EPA,
PB-210 828, February 1972.
15. R. L. Rice and N. H. Coates, "Combustion of
coals in fluidized beds of limestone," Proceedings
of the Third International Conference on
Fluidized Bed Combustion, Hueston Woods,
Ohio, (1972) sponsored by EPA, issued as EPA
650/2-73-053, December 1973.
16. D. G. Cox et al., "Reduction of atmospheric
pollution/' National Coal Board, U.K., Final
report to EPA on contract No. CPA 70-97, PB
210-673. PB 210-674. PB 210-675 September
1971.
17. E. P. O'Neill, D. L. Keairns, and W. F. Kittle,
145
-------
"Kinetic limits to the retention of SO2 in 67. No. 115 (1971) p. 23.
fluidized beds of limestone," in preparation. 20- G- J- Vogel et al., "Bench scale development of
18. R. H. Borgardt and R. S. Harvey, Environ. Sci. combustion and additive regeneration in fluidized
Technol., Vol. 6, No. 4 (1972). p. 350. beds." Proceedings of the Third International
19. A. M. Squires, R. A. Graff, and M. Pell, Conference on Fluidized Bed Combustion,
"Desulfunzation of fuels with calcined Hueston Woods, Ohio, 1972, sponsored by EPA,
dolomite." Chem. Eng. Progr. Symp. Sci., Vol. lssued at EPA 650/2-73-053. December 1973.
146
-------
CLEAN FUELS FROM COAL
BY THE COED PROCESS
J. A. Hamshar, H. D. Terzian,
and L. J. Scotti*
Abstract
Present supplies of natural clean fuels are not
adequate to meet our growing energy needs. The
conversion uf coal into synthetic clean fuels would
help solve this problem. The COED process has
demonstrated its ability to convert practically any
type of coal into very-low-sulfur synthetic crude oil,
clean fuel gas, and char. The char can be gasified to
produce additional clean fuel gas for power
generation. Syncrude can be fed to oil refineries or
used directly as fuel oil. Essentially all of the sulfur in
the coal is converted into hydrogen sulfide which is
readily recovered as elemental sulfur by conventional
techniques. This paper considers ways in which the
COED process can convert coal while satisfying
environmental concerns. Processing methods and
flows are described for a commercial COED plant to
process a high-sulfur, agglomerating coal and a
low-sulfur coal.
SUMMARY
In a COED plant with added char gasification, over
95 percent of the sulfur in the coal is recovered as
elemental sulfur. About 0.5 percent of the sulfur is
emitted to the air as SOa, and the remain ing sulfur is
in the ash. Total recycle of process liquors eliminates
water pollution as well as saves water. Ash disposal is
a moderate problem, but commercial handling
practices are well established.
The COED pilot plant is fully operational. Funding
by industry is being sought by FMC for a
development program to test the char gasification
step in existing processes.
An economic estimate using discounted cash flow
indicates that a 25,000 ton-per-day COED plant with
added char gasification can produce syncrude at $7 to
$9 per barrel and fuel gas at $0.70 to $0.80 per
million Btu. This is based on feeding Illinois No. 6
seam-coal at $8 per ton, with an investor's rate of
return of 12 percent after taxes (ref. 1).
INTRODUCTION
Project COED (Char-Oil-Energy Development) was
initiated in 1962 when the Office of Coal Research,
Department of the Interior, contracted with the FMC
Corporation to develop a process for upgrading coal
•FMC Corporation, Chemical R&D, Princeton, New Jersey.
to a synthetic crude oil, a salable gaseous product,
and char. Several years of bench-scale research and
the operation of a 100 Ib/hr process development
unit led to the design, construction, and operation of
a 36 ton-per-day pilot plant. Figure 1 is a photo of
the pilot plant located at the FMC Corporation R&D
Center in Princeton, New Jersey. The plant has been
in operation since July 1970 and is fully operational.
To date, over 18,000 tons of various agglomerating
and nonagglomerating coals have been processed
through the pilot plant. Several demonstration runs
of 30 days in duration were made in the pyrolysis
section, while several runs of over 2 weeks in duration
were made in the hydrotreating section.
From the data obtained in the 36 ton-per-day pilot
plant, a preliminary design of a commercial 25,000
ton-per-day COED plant was made. Environmental
aspects of such a plant are studied in this paper for
two coals: Illinois No. 6 seam-coal, a Midwestern
high-sulfur agglomerating coal; and Utah King coal, a
Western low-sulfur bituminous coal. Large reserves of
each of these bituminous coal types exist. Typical
properties of these coals are shown in table 1.
PROCESS DESCRIPTION
A schematic of a commercial COED complex is
shown in figure 2, and yields from this plant are given
in table 2. This flowsheet includes auxiliary plants
and shows the various process waste streams. I n the
COED process, coal is crushed, dried, and then heated
to successively higher temperatures in a series of
fluidized-bed reactors operated at low pressure (1 to
2 atm.). In each fluidized bed, pyrolysis liberates a
fraction of the volatile matter of the coal. The
temperature of each bed is just below the
temperature at which the coal would agglomerate and
plug the bed. Once the coal is partially devolatized in
one reactor, it can then be heated further in the next
reactor. Typically, four stages operating at 550°,
850°, 1000°, and 1550°F are used. The number of
stages and the operating temperatures vary with the
agglomerating properties of the coal. Heat for the
process is generated by burning char in the fourth
stage with a steam-oxygen mixture, and then using
hot gases and the hot char from the fourth stage to
heat the other vessels.
147
-------
PROJECT COED PILOT PLANT
FMC Corporation, Princeton, N.J
-------
Table 1. Properties of typical coal feeds
Utah 111. No. 6
Bituminous rank High volatile High volatile
B bituminous B/C bitnminous
Moisture, wt Z 6.4 14
Proxinate analysis,
wt Z. dry
Volatile matter 41.7 38.1
Fixed carbon 51.9 49.8
Ash 6.4 12.1
Ultimate analysis,
vt 2. dry
Carbon 75.8 o7.0
Hydrogen 5.8 4.8
Nitrogen 1.7 1.3
Sulfur 0.6 4.1
Oxygen 9.7 10.5
Ash 6.4 12.1
Chlorine 0.004 0.2
Iron* 0.12 1.6
Higher heating
value, Btu/lb
dry coal 13,900 12,150
* Included in "ash" above.
Table 2. Product yields for a commercial COED plant
Illinois
Utah Coal No. 6 Coal
Feeds
Coal, ton/day, dry 24,000 24,000
Oxygen, ton/day 3,800 3,800
Products
Syncrude, bbl/day 31,700 26,000
Net pyrolysis gas, million scf/day3 113 112
' heating value (HHV), Btu/scf 510 510
Char, ton/day 13,200 12,950
Sulfur, ton/day 72 390
Ammonia, ton/day 55 49
Products with char gasification added
Syncrude, bbl/day . 31,700 26,000
Net pyrolysis gas, million scf/day 202 201
heating value (HHV), Btu/scf 510 510
Net low-Btu gas, million scf/dayc 1,385 1,267
heacng value (HHV), Btu/scf 170 170
Sulfur, con/day 159 866
Ammonia, ton/day 55 49
Gas yield after supplying plant fuel gas and feedstock to
.the hydrogen plant.
Gas yield after supplying feedstock to the hydrogen plant.
GGas yield after supplying plant fuel gas.
149
-------
FIGURE 2
COED PROCESS
WITH ADDED CHAR GASIFICATION
FMC-OCR
PYROLYSIS GAS
COAL
FLUIDIZING
COAL ~\ GAS FLUIDIZING
PREPARATION^ GAS
FINES
PROCESS FINES
PROCESS LIQUOR — .
-------
The volatile products roleased from the coal in the
fluidized-bed reactors pass to a product recovery
system where oil. liquor (water), and gases are
separated. The pyrolysis oil is tarry and laden with
solids and sulfur. It is filtered to remove solids. The
solids-free oil is hydretreated in a fixed-bed catalytic
reactor operating typically at 750°F and 2,000 psig.
A nickel-molybdenum catalyst is used. Hydrotreating
removes most of the sulur, nitrogen, and oxygen from
the oil and cracks it to produce a lighter, more fluid
synthetic crude oil. Purge gas and purge liquor
streams containing hydrogen sulfide and ammonia are
generated in the hydrotreating section. Both streams
are cleaned and recycled.
The char product may be burned directly in a
boiler if the sulfur content is low enough to meet
emissions standards. Since this is not generally the
case, one of several existing commercial processes was
chosen as the design case to gasify the char. Char is
fed at 1,600°F into a fluidized-bed gasifier blown
with air and steam. The sulfur comes out in the ash
and as HjS in the gas. Fly ash and HaS are scrubbed
from the gas. Gas streams are cleaned of hydrogen
sulfide and carbon dioxide using conventional process
such as hot carbonate or Sulfmol. Because the
pyrolysis gas is the hydrogen source for
hydrotreating, it must be cleaned separately from the
low-Btu gas. The hydrotreating bleed gas which is
hydrocarbon-rich is blended with the pyrolysis gas for
treatment. Part of the cleaned pyrolysis gas is sent to
a reforming plant for conversion to hydrogen. A
portion of the low-Btu gas is used to fire all furnaces
in the plant. The remaining clean pyrolysis gas and
clean low-Btu gas are blended and sold as a fuel for a
power plant. The hydrogen sulfide is recovered as
explained m a subsequent section of this paper.
PRODUCT USES
Synthetic Crude Oil
COED oil is a full-range synthetic crude oil, capable
of being fed to a petroleum refinery and producing a
full product slate. Properties of syncrudes from
Illinois No. 6 and Utah coals are shown in table 3. An
experimental study was carried out by the Atlantic
Richfield Company to define those refinery processes
where syncrude could best be used. A subsequent
study was carried out by Chem Systems, in which
their refinery linear programming model showed
syncrude to have essentially the same value as sweet
domestic crude (ref. 7).
A promising use of the syncrude is to distill it into
naphtha and No. 4 fuel oil cuts. The naphtha can be
reformed into high-octane gasoline. No. 4 fuel oil is
used primarily to fire large boilers, so syncrude was
tested in this application. In November 1973, a
successful test of powering the Navy's destroyer USS
Johnston was made with the COED synthetic crude
oil. About 17,000 gallons of syncrude topped to give
a fuel with 160°F flash point was burned in a 30-hour
shipboard test. Syncrude was also tested as fuel to a
small industrial boiler firing 1.5 million Btu/hr. Stack
gas emissions were monitored and are reported in
table 4. All emissions from syncrude combustion
were significantly lower than those from a typical No.
4 residual fuel.
Fuel Gas
Pyrolysis gas is a medium heating-value gas (510
Btu/scf clean gas). Typical analyses of COED fuel
gases are shown in table 5. A portion of this gas is
used to make hydrogen for hydrotreating. The
remainder can be sold as clean fuel gas or can be
converted to hydrogen for sale.
Additional low-Btu fuel gas (170 Btu/scf) can be
made by gasification of char with air and steam. This
would be sold as boiler fuel. The analysis of
combined pyrolysis gas and gasifier gas product is
given in table 5. Its heating value is 220 Btu/scf.
Char
Properties of chars from Illinois No. 6 and Utah
coals are shown in table 6. Chars contain roughly the
same concentration of sulfur as the coal, and twice
the ash. Most chars must be gasified because they
contain too much sulfur for direct combustion.
Operating a COED plant on a low-sulfur coal, such
as Utah A seam, produces a char with a sulfur content
that is acceptable for combustion in power plants in
some States. To demonstrate that COED char would
be an acceptable fuel for an industrial boiler, a 3-day
test was made in February 1974. An anthracite boiler
with a generating capacity of 175,000 Ibs/hr of steam
was fired with char derived from Utah A seam coal.
Operation and turndown of the boiler on the COED
char were successfully demonstrated.
SULFUR BALANCE
Sulfur balances are shown m table 7 for a 25,000
ton-per-day COED plant processing Utah or Illinois
coal, with or without char gasification. Nearly half
the sulfur in the feed coal comes out in the char for
151
-------
Table 3. Typical syncrude properties*
Coal Source
API, °@60°F
Pour point, °F
Flash point, PMCC, °F
Viscosity, cs . @ 100° F
Ultimate analysis, wt. %
C
H
N
0
S
Ash
Moisture
ASTM distillation
IBP
10%
30%
50%
70%
90%
EP (95%)
Metals, ppm
% Carbon residue, 10% bottoms
Hydrocarbon type analysis ,
liquid vol. %
Paraffins
Olefins
Naphthenes
Aromatics
Utah
A-seam
20
60
75
8
87.2
11.0
0.2
1.4
0.1
<0.01
0.1
280
430
530
660
780
920
950
<10
—
23.7
0
42.2
34.1
Illinois
No . 6-seam
22
0
60
5
87.1
10.9
0.3
1.6
0.1
<0.01
0.1
190
273
390
518
600
684
746
<10
4.6
10.4
0
41.4
48.2
* Properties depend on severity of operation of
hydrotreating unit.
152
-------
Table 4. No. 6 fuel oil specifications
390-EP COED syncrude
Illinois No. 6 coal
Typical No. 4
Test* Result residual fuel
Participates, Ibs./lOO gal. 4.6 19.2
Gaseous contaminants, ppm
S0x
NO
CO
HC
60
53
4.5
3.0
490
95
6.0
7.1
* Test Conditions; Fuel was burned in a small industrial
burner firing a 1.5 million Btu/hr boiler. Stack gas is
controlled at 12.5 percent CO., approximately equivalent to
25 percent excess air and stack temperature Is held at 500°
to 510°F.
fable 5. Typical analyses of product gases from
COED plant with added char gasification
Gas
H
analysis, mole Z
-S, C0,-free gas
N2
CO
H2
CH4
C2H4
C2H6
C3H6
C3H8
V
Pyrolysis
gas
0.6
21.6
55.5
19.3
0.5
1.4
0.3
0.2
0.6
Gasifler
gas
47.1
36.6
15.9
0.4
—
—
—
—
—
Net combined
product gas
39.6
34.6
22.5
2.7
0.10
0.22
0.05
0.01
0.11
Higher heating value,
Btu/scf 510 170 220
Impurities in raw gas,
mole Z
co2
H
H
2
2
S
S
(111.
(Utah
No. 6
coal)
H-S In combined
SO
2
In
stack
gas
20.9 1.6
coal)
1.3 0.6
0.2 0.09
product gas
from
sulfur
plant
—
—
<10 ppm
200 ppm
153
-------
Table 6. Properties of char product
Utah
Proximate analysis
vt Z, drv
Volatile matter
Fixed carbon
Ash
Ultimate analysis
vt t, dry
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
Ash
Chlorine
Iron*
Higher heating value,
Btu/lb. dry
6.1
80.2
13.7
81.5
1.3
1.5
0.5
1.5
13
0
7
006
0.28
Illinois
No. 6
2.7
77.0
20.3
73.
0.
1.0
3.4
1.0
20.3
0.1
12,310 11,040
Table 7. Sulfur balance
25,000 TPD COED plant with added
char gasification
Utah coal
tons/hr of S
Illinois coal
tons/hr of S
COED section
Coal (total input) 6.0
Syncrude 0.1
Elecental sulfur 3.1
S02 emissions* 0.02
Char (to gasifler) 2.8
Total output 6.0
Gasifier section
Char (total input) 2.8
* From sulfur-recovery plants.
41.0
0.2
22.4
0.1
18.3
41.0
18.3
Elemental sulfur
S02 ecissions*
Ash
Total output
2.6
0.01
0.2
2.8
17.8
0.1
0.4
18.3
* Included in "ash" above.
Table 8. Summary of waste streams and treatment methods
Waste stream
Sources
Treatment
Hydrogen sulfide
Process liquors
Process condensate
(weak liquors)
Ash
Fines (dust)
Sulfur dioxide
Raw pyrolys is gas,
raw gasifier gas,
hydrotreating purge gas
Pyrolysis recovery,
hydrotreating recovery
Coal drying
gasifier offgas
Gasification
Coal preparation
char handling
pyrolysis liquor clarifiers
pyrolysis external cyclones
raw-oil filters
Sulfur recovery plant
1. Scrubbing by sulfinol, hot
carbonate, etc.
2. Claus + tailgas or Stretford
1. Oil skimming
2. Clarification (solids removal)
3. Recycle to pyrolysis
1. Clarification (solids removal)
2. Blodegradation and/or recycle
as low-quality process steam
1. Dampen
2. Return to spent mine site
Feed dry fines to gasifier
or into char product;
recycle oily fines to coal feed
Treatment not needed—
within acceptable limits
154
-------
either high- or low-sulfur coal. The char gasifier
releases most of this sulfur as hydrogen sulfide, with
the rest retained in the ash. Over 99 percent of the
HzS is recovered as elemental sulfur. Hydrotreating
removes over 95 percent of the sulfur from Illinois oil
and over 80 percent from the low-sulfur Utah oil.
TREATMENT OF WASTE STREAMS
Treatments of the major waste streams from the
COED process are summarized in table 8 and are
explained below.
Sulfur Scrubbing and Recovery
Offgases from pyrolysis and hydrotreating contain
H2S, which is scrubbed out of the combined gas. Any
of several commercial processes can be used
satisfactorily to scrub the H2S and most of the CO2
out of the product gases. Chemical absorption
processes such as Sulfinol or hot carbonate are
preferred because they can operate at low pressure,
thus minimizing compression cost. Acid gas is
collected in a solvent, then flashed off and sent to the
sulfur recovery plant. All of these processes can leave
as little as 5 to 10 ppm (-(28 in the product gas.
It is likely that the char will be gasified. This
process liberates sulfur from the char as h^S and
possibly as small amounts of COS (car bony I sulfide).
Gasifier offgas passes through an acid-gas scrubbing
plant like the one described above. Carbonyl sulfide is
produced mainly in high-temperature (slagging)
gasifiers. Any of the chemical absorption processes
absorb COS, although it degrades amine solvents. The
Sulfinol solvent is resistant to COS degradation. Gases
containing CO and Ha have been treated successfully
by amine systems, so COED gases present no problem
when applying these systems (refs. 2,3,4).
Elemental sulfur is recovered from the acid-gas
streams using existing commercial processes.
High-sulfur coals, such as Illinois No. 6, yield
concentrated H2S streams (10 to 20 percent H2S)
which are treated in a Claus plant. The tail gas is
further treated by a method such as the Beavon or
SCOT* processes to limit SO2 in effluent gases to
200 ppm. Over 99 percent of the sulfur is recovered
in this manner. Utah coal yields acid-gas containing 5
percent HjS. This stream is treated by the Stretford
process to recover about 99 percent of the sulfur
(refs. 2,5,6).
Process Liquors
Process liquors emerge from three areas of a COED
plant. Typical analyses of these streams are given in
table 9.
A fairly clean condensate liquor comes from the
coal-drying and first-stage pyrolysis section. This
comes primarily from inherent moisture in the coal
feed. Fines are removed in a clarifier, and the liquor is
recycled to generate low-pressure steam for the
process. A fraction of the liquor is taken as boiler
blowdown, and is injected into the char gasifiers. The
pH of this stream is 7 to 8.
Pyrolysis liquor comes from the oil recovery
section of the pyrolysis plant. It contains tars, fines,
phenohcs, ammonia, and hydrogen sulfide. Tars are
removed in an oil separation tank, and fines are
removed in a clarifier. This stream can contain as
much as 1.0 percent dissolved organics. The preferred
treatment is to recycle the material and pyrolyse it.
This is done by partially flashing the liquor and
injecting it as liquid and vapor into either the gasifiers
or the hottest pyrolyser. Total liquor recycle is
possible because more water is consumed in the
hottest pyrolysis vessel than is produced in the
intermediate stages. A biological degradation pond is
provided to handle liquors from process upsets.
Oil hydrotreating produces water, ammonia, and
hydrogen sulfide byproducts, which leave the plant
primarily in a liquor stream. This liquor is
supersaturated with H2S and NHa as it leaves the
Table 9. Properties of process liquors
Coal
First stage pyrolysis liquor
(weight percent)
Carbon
Nitrogen
Sulfur
Phenol
Entzalned oil
Suspended solids
pH
Second stage pyrolysis liquor
Carbon
Nitrogen
Sulfur
Phenol
Entrained oil
Suspended solids
pH
Hydrotreating liquor
Carbon
Nitrogen
Sulfur
pH
Utah
0.17
0.01
0.01
9.2 ppm
0.01
0.03
8.1
2.0
0.88
0.13
0.40
0.2
0.64
9.0
1.7
5.2
4.2
11. 5
Illinois
No. 6
--
o.os
0.07
0.00
—
0.49
3.6
--
0.93
o.ia
0.38
0.0-0.5
1.09
8.8
O.B
5.0
8.7
9.3
•Shell Claus Offgas Treating
155
-------
TAPf.E 10
Project COF.D Technical Reports Available
from the U.S. Covcrnncnt
"Char Oil Energy Development" - Project COED, Final Report
Period Covered: June 1962 - December 1965
R&D Report No. 11
OCR Contract No. 114-01-0001-235
Refer to: FB-169562 (Volume I) - $6.00«
PB-169563 (Volume II) - *6.00»
"Char Oil Energy Development" - Project COED, Amendment No. 3,
Final Report, Period Covered1 January - October 1966
R&D Report No. 11
OCR Contract No. 14-01-0001-235
Refer to: PB-173916 (Final) »6.00*
PB-173917 (Appendix) - $6.00*
"Char Oil Energy Development" - Project COED, Interim Report No. 1,
Period Covered: September 1966 - February 1970
R&D Report No. 56
OCR Contract No. 14-01-0001-1)98
Refer to: Titled report and
GPO Catalog No. l63.10:56/lnt 1
Cost: $2.50"
"Char Oil Energy Developnent" - The Desulfurizatlon or GOED Char,
Part III" - Project COED, Interim Report No. 2,
Period Covered: December 1968 - Hay 1970
R&D Report No. 56
OCR Contract No. 14-01-0001-498
Refer to: Titled report and
GPO Catalog No. I63.10:56/lnt 2
Cost: $1.25"
"Char Oil Energy Development" - Project COED, Final Report,
Period Covered: October 1966 - June 1971
R*D Report No. 56
OCR Contract No. 14-01-0001-498
Refer to: Titled report and
OPO Catalog No. 163.10:56
Cost: $4.00**
"Char Oil Energy Development" - Project COED
Period Covered: July 1971 - June 1972
R&D Report No. 73 - Interim Report No. 1
OCR Contract No. 14-32-0001-1212
Refer to: Titled report and
GPO Catalog No. I63.10:73/int 1
"Char Oil Energy Development" - Project COED
Period Covered: July 1972 - June 1973
R&D Report No. 73 - Interim Report No. 2
OCR Contract No." 14-32-0001-1212
Refer to: Titled report and
GPO Catalog No. (not available at the present time)
Cost: Not established
Instructions for ordering reports. All reports must be prepaid.
•Available from:
U.S. Department of Commerce
National Technical Information Service
5285 Port Royal Road
Springfield, Virginia 22151
Attention: Storage and Dissemination Section
(Hake check payable to: National Technical Information Service)
••Available from:
Superintendent of Documents
U.S. Government Printing Office
North Capitol and H Streets, N.W.
Washington, D.C. 20401
(Make check payable to: Superintendent of Documents)
156
-------
pressure vessels, so it is passed through a stripping
tower in which product gases pick up most of the
H2S and NHa. This gas is recycled to the acid-gas
removal plant. The stripped liquor contains dissolved
organics at a level similar to pyrolysis liquor.
Therefore, the hydrotreating liquor is blended with
oyrolysis liquor and recycled, as previously explained.
A COED plant without char gasifiers needs
biological liquor-treatment facilities. The pyrolysis
and hydrotreating liquors can still be pyrolysed in the
hottest pyrolyser. The drymgsystem liquor stream is
too large to be added to this pyrolyser, so it is
biologically treated. The organic content of this
stream is low. and treatment is not difficult.
Ash
Typically, about 10 percent of the coal feed is ash
which must be disposed of as it emerges from the
gasifiers. Granular ash and flyash streams are
combined and moistened to stop dusting, and are
shipped to the mine as landfill for spent minesites.
The finest flyash is collected by wet scrubbing. The
wet concentrate is used for ash moistening.
A COED plant without char gasifiers puts out all
the ash in the char product. The power plant handles
the ash in this case.
Fines
Dust problems are controlled with cyclones and bag
filters in the coal preparation and char handling
facilities. Fines from the pyrolysis plant are collected
by cyclones, both internal and external to the vessels.
Fines escaping from cyclones are collected by wet
scrubbers and concentrated in a clarifier. Both wet
and dry fines are fed into the gasifiers. Raw-oil
filtration yields a filter cake containing oily fines.
This material is returned to the coal pile for recycle.
Process Cooling
All process cooling is done using wet cooling
towers. The total plant water requirement is about
15.000 acre-feet per year for a plant with added char
gasification. Roughly 10,000 acre-feet per year are
used for cooling. Since low-quality process water is
needed, no water effluents are given off. either from
cooling or from the process itself. Recycle of process
water saves about 9 percent of the total water
requirement.
ACKNOWLEDGMENT
The authors acknowledge the guidance and support
from the Office of Coal Research. Their contributions
of technical support and funding have helped to make
the COED pilot plant a success. A list of technical
reports available from the U.S. Government on
Project COED is attached in table 10.
REFERENCES
1. H. D. Terzian, J. A. Hamshar, N. J. Brunsvold,
and J. F. Jones, "Processing Coal to Produce
Synthetic Crude Oil and a Clean Fuel Gas."
(Presented at meeting of AlChE So. Cal. section,
Los Angeles, April 16, 1974, preprint.)
2. J. Wall, ed., "NG/LNG/SNG Handbook.
Hydrocarbon Proc., Vol. 52, No. 4 (April 1973).
pp. 87-116.
3. C. L. Dunn, E. R. Freitas, E. S. Hill, and J. E. R.
Sheeler, "First Plant Data from Sulfmol
Process." Hydrocarbon Proc., Vol. 44, No. 4,
(April 1965), pp. 137-140.
4. H. E. Benson and J. H. Field, "New Data for Hot
Carbonate Process," Petroleum Refiner, Vol. 39,
No. 4, (April 1960), pp. 127-132.
5. D. K. Beavon and R. P. Vaell, 'The Beavon
Sulfur Removal Process for Purifying Claus Plant
Tail Gas." (Presented at API Division of Refining
Meeting, New York, May 9, 1972, preprint.)
6. J. E. Naber, J. A. Wesselingh, and W.
Groenendal, 'The Shell Claus Offgas Treating
Process." (Presented at AlChE National meeting.
New Orleans, March 15, 1973, preprint.)
7. M. I. Greene, L. J. Scotti, and J. F. Jones, "Low
Sulfur Synthetic Crude Oil from Coal."
(Presented at meeting of ACS Div. of Fuel
Chem., Los Angeles, April 1974, preprint.)
157
-------
158
-------
ENVIRONMENTAL ASPECTS OF THE SRC PROCESS
C. R. Hinder-liter*
Abstract
The Solvent Refined Coal (SRC) Process is being
developed by the Pittsburg & Midway Coal Mining
Co. under the sponsorship of the Office of Coal
Research. In the SRC process, coal is first dissolved
under moderate hydrogen pressure in a heavy
aromatic solvent. The resultant coal solution is
filtered to remove ash and a small amount of
insoluble organic material and is fractionated to
recover the solvent. The product is a heavy residual
fuel that is solid at ambient conditions and that
contains less than 0.8 percent sulfur and less than 0.1
percent ash. The yield of SRC from coal is
approximately 60 percent by weight; in addition,
about 15 percent of the coat is converted into light
liquids and gases.
An SRC plant would have to deal with several
potential sources of pollution. Coal must be handled
and pulverized in a manner designed to minimize
emission of coal dust. The sulfur removed from the
coal by processing is in the form of hydrogen sulfide
which must be absorbed from product gases and
converted to elemental sulfur. The sulfur plant itself
must include tail gas cleanup facilities to reduce
sulfur emissions. Certain fractions of the light liquids
produced will contain substantial amount of
phenoiics and amines. Process water will be
contaminated with these materials and will have to be
treated to prevent water pollution. Problems similar
to these are faced by other industries and are handled
adequately with proven technology. I am confident
that with power design an SRC plant can be built that
will meet environmental standards.
Introduction
This Nation's need to develop new processes to
produce clean fuels from coal has been discussed by
many people. While developing these new processes,
we must insure that the processes themselves are
clean and do not have an adverse effect on the
environment. This paper discusses one such process
called the Solvent Refined Coal Process which is
being developed by The Pittsburg & Midway Coal
•Senior Project Engineer, The Pittsburg & Midway Coal
Mining Company. Merriam, Kansas.
Mining Company (P&M) under the sponsorship of the
Office of Coal Research (OCR). This process has been
under development since 1962, and the construction
of a 50-ton-per-day pilot plant at Fort Lewis.
Washington, was recently completed. Although
definite commercialization plans have not been
finalized for this process, both P&M and OCR are
studying the environmental aspects of the Solvent
Refined Coal Process. Our discussion today will
principally dwell on our concept of a commercial
plant which differs substantially in design from the
pilot plant. The pilot plant does include many
safeguards to protect the environment.
Background
In 1962, the Office of Coal Research awarded a
research contract to Spencer Chemical Company to
study the technical feasibility of a coal deashing
process. This work was concluded in 1965 with the
successful demonstration of the process in a
100-pound-per-hour continuous flow unit. During the
term of this contract. Gulf Oil Corporation acquired
Spencer Chemical Company and. upon
reorganization, reassigned the project to the Research
Department of P&M. This deashing process is now
called the Solvent Refined Coal (SRC) Process. In
1966, a contract was awarded to P&M to further
develop the SRC process through design,
construction, and operation of a pilot plant to
process 50 tons of coal per day. The design for the
pilot plant was completed by Stearns-Roger
Corporation in 1969 but funds were not immediately
available to plan for construction. In late 1971,
sufficient funds became available to plan for
construction and Rust Engineering Company was
selected, through competitive bidding, to complete
the detailed engineering and to construct the pilot
plant at Fort Lewis, Washington. In June 1972. OCR
extended the contract with P&M to meet the
projected needs for construction and operation of the
pilot plant. Construction was started in July 1972
and the total cost of the pilot plant has been
estimated to be about $20 million.
The pilot plant construction progress has been
somewhat slower than scheduled. Completion was
initially scheduled for Novemher 1973, but the
159
-------
necessary addition of biological waste water
treatment facilities and problems encountered in
fabricating the dissolvers delayed completion until
April 1974. The biological treatment facilities will
still not be completed for several months. The pilot
plant will startup using a petroleum-derived solvent, a
cycle oil from an FCC unit, and bituminous coal from
Western Kentucky. Our laboratory had previously
worked almost exclusively with anthracene oil as a
solvent, but due to the limited availability of this
material, the pilot plant will use a petroleum-derived
aromatic oil as startup solvent. To date, work in the
laboratory indicates that petroleum-derived solvents
are not as well suited as anthracene oil for solution of
coal, and different reaction conditions must be used
during startup. Most of the recent laboratory effort
has been directed to defining reaction conditions for
the pilot plant during the startup period. Plans are
being made to obtain different coals for testing and
for making combustion tests on the SRC product.
Process Description
A schematic flow diagram of the SRC process is
shown in figure 1. In the SRC process, coal is
pulverized and mixed with a solvent to form a slurry.
This slurry contains between 25 and 35 weight
percent coal. The slurry is pressurized to
approximately 1.000 psig, mixed with hydrogen, and
heated to approximately 425°C where the coal
solution reactions are completed in about 20 minutes,
during which time nearly all of the organic matter in
the coal dissolves in the solvent. The reaction product
is flashed to separate gases, and the liquid is filtered
to remove the mineral residue which consists of ash
and undissolved coal. The liquid is then fractionated
to recover the solvent which is recycled to slurry
more feed coal. During each pass through the reactor,
a small amount of solvent is converted to light liquids
and gases; however, this loss is more than balanced by
the amount of coal which is converted to solvent with
the net result that the process does not require
solvent feed except during initial startup. The liquid
remaining after the solvent has been recovered is a
heavy residual fuel called "solvent refined coal" that
contains less than 0.8 percent sulfur and less than 0.1
percent ash and that solidifies upon cooling to
ambient conditions. The solvent refined coal has a
melting point of about 350°F and has a heating value
of about 16,000 Btu per pound regardless of the
quality of the coal feedstock. Smaller quantities of
hydrocarbon gases and light distillate liquids are also
produced. The solvent refining process removes all of
the inorganic sulfur and 60 to 70 percent of the
organic sulfur in the coal.
In the present concept of the SRC process, the
mineral residue which may contain more than 6
percent sulfur would be recovered from the filters
and gasified along with additional coal to make the
hydrogen needed for the process. An excess of
hydrogen would be made which along with the
hydrocarbon gases produced would supply the fuel
needed by the process. The sulfur that is removed
from the coal appears as hydrogen sulfide in the SRC
product gases and the gasifier product gas. The
hydrogen sulfide is separated by amine absorption or
a similar process and converted to elemental sulfur.
The ash in the original coal would be processed
eventually through the gasifier and, assuming that a
slagging gasifier would be used, this ash would be
converted to a clean slag.
Environmental Considerations
Carnegie Mellon University recently completed a
study for P&M in which they compiled Federal and
State environmental regulations that may apply to an
SRC plant located in States bordering the Ohio River.
This report has been submitted to the Office of Coal
Research for publication as R&D Report No. 53,
Interim Report No. 5. An SRC plant would have to
meet both Federal and State air quality standards.
There are two types of Federal air
regulations: ambient air quality standards and new
source performance standards. Ambient air quality
standards define the minimum allowable quality of
the air in regard to six different pollutants. These
standards are given in table 1. New source
performance standards have not been enacted for coal
refining plants. In the absence of Federal new source
performance standards, an SRC plant would have to
conform to the State or local regulations that are
applicable.
The Federal Water Pollution Control Act
amendment of 1972 sets forth as a national goal the
complete elimination of all discharges of pollutants
by 1985 with particular emphasis on control of toxic
materials. New source water quality standards have
been proposed for petroleum refineries and for coke
plants but not for coal refineries. These proposed
Federal standards are very stringent, but certain State
regulations are even more limiting. For example,
Pennsylvania regulations forbid the discharge of any
phenol. It is not certain that existing technology can
meet the proposed water quality standards; however,
coal refining should have no unique problem and no
160
-------
SULFUR
COAL
DISSOLVER
SLURRY
PRE-HEATER
HYDROGEN d^S
FILTER
tia
PRODUCT
AND SOLVENT
-------
Table 1. National Anbient Air Quality Standards
Primary standard
Secondary standard
Contaminant
Suspended
particulates
Sulfur
dioxide
Carbon
monoxide
Photochemical
oxidant
Hydrocarbons
(nonmethane)
Nitrogen
dioxide
Averaging
interval
1 year
24 hr
1 year
24 hr
3 hr
8 hr
1 hr
1 hr
3 hr
(6-9 a.m.)
1 year
ug/m3
75
260
80
365
10,000
40,000
160
160
100
ppm
( by vol . )
--
0.03
0.14
9.0
35.0
0.08
0.24
0.05
ug/m3
60
150
1,300
10,000
40,000
160
160
100
ppm
(by vol . )
--
0.5
9.0
35.0
0.08
0.24
0.05
Source: Report by Carnegie Mellon University.
greater difficulty in meeting the water quality
standards than would a petroleum refinery and even
less difficulty meeeting environmental standards than
would a coke plant. Environmental considerations in
the design of an SRC plant would primarily focus on
air and water pollution, but they are not considered
in this paper. In view of the developmental state of
the SRC process, a precise definition cannot be given
for many areas of such a plant, for this reason,
environmental problems are discussed in general
terms.
Coal Preparation. Coal preparation includes
transporting the coal from storage, then pulverizing,
drying, and mixing the coal with solvent to form a
slurry. There are two potential sources of pollution in
these operations. The most obvious is fugitive
particulate matter which will result from handling the
dry coal. The coal dust problem can be controlled by
using covered conveyors and induced draft vents with
the vent gas being filtered to remove particulates. If
the coal must be dried, the off-gas from the drier also
must be filtered to remove particulates. Some water
will be liberated from the coal during pulverizing and
during slurry preparation; if this water is condensed,
it may have to be treated to remove suspended solids
and to adjust acidity before discharge. We would not
anticipate any difficulty in designing the coal
preparation area for an SRC plant since coal
preparation is a well-known operation, and we should
encounter no surprises. Pilot plant operation should
define the slurry preparation operation and determine
the extent of coal drying required for optimum
operations.
Coal Solution. Most of the actual processing will be
conducted in an enclosed, pressurized system with
equipment failure or leakage being the only potential
source of emissions. The coal slurry is pressurized,
mixed with hydrogen, and heated to reaction
temperature where it is retained for a certain amount
' of reaction time. After the coal slurry has undergone
reaction, the solution is reduced somewhat in
temperature and pressure, and the gas is separated
from the liquid slurry product. The gas is then cooled
to condense water and light liquids. This product gas
contains hydrogen sulfide which represents the sulfur
removed from the coal and which must be recovered
to prevent sulfur emission to the atmosphere.
Technology already exists that is adequate to recover
this hydrogen sulfide. e.g., amine and carbonate
scrubbing processes. This product gas contains a
162
-------
substantial amount of unreacted hydrogen, and a part
of the gas may be recycled through the coal solution
processing step. The gas which is not recycled would
be used for process fuel, but part of it could be
reformed to convert the contained hydrocarbon gases
to hydrogen for use in the process. An excess of gas
would always be made, and this excess gas would be
burned to provide heat for the process.
The water that is condensed from the product gas
presents a somewhat more difficult problem, one that
we have not completely defined. This water will be in
contact with the light liquids which contain phenols
and amines, some of which will dissolve in the water.
Due to the presence of phenols, it would not be
possible to directly discharge this water unless it
received extensive treatment such as biological
processing. An alternate approach to the disposal of
this contaminated water would be to use it in the
production of hydrogen either by gasification of the
mineral residue or coal, or by reforming the product
gases. We feel that this alternate is feasible and would
be the preferred approach. It may be necessary to
remove part of the phenolics from the water before
reuse; however, phenolics potentially represent a
valuable byproduct that may be recovered for sale in
any case. The water requirements for hydrogen
manufacture will be greater than the amount of water
made by the process, and fresh water makeup would
be required to supplement the process water.
Mineral Residue Recovery and Hydrogen
Manufacture. After separation of gases, the liquid
slurry product is filtered to remove the ash and
undissolved coal. This solid is referred to as the
mineral residue, and it generally will be about
one-half carbon and one-half ash and may contain
more than 6 percent sulfur. This mineral residue will
be removed from the filter; it may be dried and then
gasified to make hydrogen for the process. If drying is
needed, the dryer must be designed to prevent
fugitive emissions which would pollute the air.
The gasifier would convert the mineral residue,
which is high in sulfur, into a relatively clean slag and
synthesis gas. A slagging gasifier similar in concept to
a Bituminous Coal Research Bi-Gas gasifier would be
preferred for this operation, although any commercial
gasifier could be used. The sulfur in the mineral
residue would be converted into hydrogen sulfide
which would appear in the synthesis gas and which
would be removed by amine or carbonate scrubbing.
It would also be necessary to gasify some coal to
make hydrogen, since gasification of the mineral
residue would not produce enough hydrogen for the
process. An alternate scheme—which could be used if
a reliable gasifier of proven design were not available
or if the cost of gasification were excessive— would
be to re-form part of the product gas to make
hydrogen. In this case, an alternate use must be found
for the mineral residue, or it would have to be
discarded. This scheme would result in a deficiency in
fuel gas for plant fuel, and part of the liquid or solid
product would.be used for plant fuel.
Sulfur Plant. The sulfur liberated from the coal by
processing appears as hydrogen sulfide in various gas
streams. The hydrogen sulfide would be recovered by
an acid gas absorption unit and converted to
elemental sulfur. A Glaus sulfur plant would probably
be used with an appropriate tail gas cleanup unit to
increase the recovery of sulfur to 99 or 99.5 percent
and reduce sulfur emissions to acceptable levels as
dictated by environmental regulations. The spent gas
from the tail gas unit would be incinerated to insure
that any small amount of unrecovered hydrogen
sulfide is converted to sulfur dioxide prior to venting
to the atmosphere. Proven technology exists with
which to build a workable sulfur recovery plant, and
no surprises would be expected.
Process Heaters. An SRC plant will have several fired
heaters which will require substantial quantities of
fuel. The slurry preheater and the solvent recovery
areas will be the major fuel consumers. The SRC
process makes some byproduct gases which would be
recovered and used as fuel for the process heaters, as
discussed earlier. The gases made would be diluted
with unreacted hydrogen and would have a heating
value of about 300 to 400 Btu/SCF. The crude gas
would contain hydrogen sulfide which would have to
be removed by an acid gas absorption unit to a low
concentration, such that the gas could be burned
without exceeding sulfur oxides emission standards.
The fired heaters would also emit some oxides of
nitrogen as byproducts of combustion. The fuel gas
would contain essentially no combined nitrogen, and
the NOx emissions would depend upon the burner
characteristics. It should not be a difficult task to
design the fired heaters to be in compliance with NOx
emission standards. In certain process areas, spillage
or equipment leakage could result in accumulation of
phenolics and other organic materials that could
contaminate ram water runoff. It would be desirable
to separately collect water runoff from these certain
areas of the plant and to use appropriate treatment to
guard against discharge of phenolic pollutants from
the plant. Since phenolic materials would be present
163
-------
which could contaminate the waste water from an
SRC plant, biological waste water treatment facilities
would be needed to destroy phenols and to prevent
their discharge from the plant. Additional waste
treatment facilities would be needed to remove solids
and to neutralize the water prior to discharge.
An SRC plant would require a thermal oxidizer to
insure incineration of any gaseous discharge from the
process. Some process waste streams will contain
minor amounts of hydrogen sulfide or carbon
monoxide that could not be discharged into the
atmosphere without incineration. Certain liquid waste
streams, mainly contaminated water, would also be
incinerated to destroy organic compounds and to
prevent water contamination.
In summation, an SRC plant will have few
environmental problems that cannot be handled
adequately with existing off-the-shelf technology.
The problems that will exist may be presented in a
somewhat unconventional manner, but I am
confident that environmental standards can be met
with foresight and proper design.
164
-------
ENVIRONMENTAL ASPECTS OF SOLVENT REFINING
W. B. Harrison*
Abstract
An effort will be made to analyze the
environmental aspects of solvent refining as a strategy
to enable the electric utility industry to utilize high
sulfur bituminous coal for power generation.
Comparisons will be made with other strategies for
using such coal, including flue-gas processing and
gasification. A brief assessment of the environmental
problems of a solvent refining plant will be made.
In view of the fact that the preceding speaker has
addressed some of the specific environmental aspects
of a representative solvent refining plant, I wish to
discuss environmental aspects from a different point
of view. I shall try to place in perspective the kinds of
questions which an electric utility company would
address in outlining an environmental impact
statement for a plant that is to be fueled with solvent
refined coal. In effect, the exercise will involve
comparing broad issues of environmental interaction
of alternatives for meeting the energy demand with
some reference to the environmental aspects of each
alternative. I presume that there is no need at this
conference to develop a statement on the importance
of coal in the context of our future energy
requirements. From the electric utility viewpoint, it
would appear that coal must remain as a major energy
resource throughout the remainder of this century,
and beyond.
The constraints imposed on the use of coal are
characterized as being legal, logistic, technical, and
economic. Legal constraints are mainly in the form of
State and Federal laws and regulations. In this
discussion, reference is made particularly to the
environmental regulations which apply both to
existing and to new power plants and which govern
both ambient air quality and standards of
performance (emission limitations). Logistic
constraints are best understood by considering the
location and character of coal reserves throughout the
nation with respect to the location and size of
generating plants needing the fuels, the length of
supply lines, and the available transportation modes.
•Vice President. Research. Southern Services, Inc.,
Birmingham, Alabama.
A related topic, logistic in nature, is the ease with
which fuels may be brought into processing plants or
with which byproducts and other wastes from the
plants may be further treated or stored. The technical
constraints are used merely to recognize that any
viable option must be based on reliable and
reasonable technology. And finally, economic
constraints must provide an umbrella over the whole
mix of options because some things which are
technically or logistically feasible may not be
economically feasible.
It is apparent from an examination of the legal
constraints that many existing plants and all future
plants will require major deviations from practices of
the past. The sulfur dioxide regulations provide a
specific example of how regulations will influence the
operating options faced by a generating plant.
Clearly, one option is to select a fuel containing such
small amounts of sulfur that the sulfur dioxide
regulations can be met. It is apparent that low-sulfur
coal is not available in sufficient supply to make this
alternative possible in some locations. Therefore, the
options are reduced to processing high sulfur fuel in
order to remove sulfur before combustion, to
processing the flue gas in order to remove sulfur
dioxide after combustion, or perhaps to using some
combination of the two processes. Sulfur abatement
measures that might take place during combustion
such as in proposed fluidized-bed combustion boilers
are regarded at this point as unproven technology and
are, therefore, not considered as viable alternatives.
The other options being considered are not
necessarily judged to be proven, but at least they are
further developed than fluidized-bed technology, and
comparisons may be made on the assumption that
reliable technology in fuel processing or flue gas
processing will emerge in the course of a few years.
In order to illustrate the point of this discussion, it
is assumed that two fuel processing options will be
available for utility applications: low-Btu gas or
solvent-refined coal. The availability of flue gas
processing is also assumed, but the particular process
is entirely arbitrary for purposes of this discussion. As
we move forward in developing these thoughts, the
next step will be to identify certain of the factors
that would enter into an overall environmental
165
-------
appraisal of the three options-low-Btu gas,
solvent-refined coal, or stack gas processmg-m the
context of achieving adequate sulfur removaj from a
typical Western Kentucky or Southern Illinois-coal
for a power plant application.
Presumably, the total amounts of sulfur to be
removed from either the fuel or the stack gas would
be comparable irrespective of the strategy selected.
The major differences in comparing the three
alternatives will lie in the chemical or physical form
in which that sulfur may be found. For example, it
would appear that the sulfur removed during either
gasification or solvent refining may leave the process
either as concentrated sulfunc acid or elemental
sulfur. The choices are dependent on the potential
markets that might exist for either form, but neither
form is dictated by the features of the fuel
processing. On the other hand, in the stack gas
processing alternative, not only is the chemical form
of the sulfur dictated by the nature of the process,
but also the disposal of the sulfur becomes a problem
at the power plant site. Thus, the nature and chemical
form of the sulfur arising from each of these
alternatives has its own specific environmental
impact, and this could influence the feasibility of
either option for a specific generating site. The
question of location with respect to the generating
site perhaps deserves more elaboration. Clearly from
the point of view of the power plant operator, either
alternative for making clean fuels from coal has
advantages over stack gas cleaning because the
environmental issues pertaining to fuel processing
would likely be the concern of someone else, but the
environmental issues of stack gas cleaning have to
reside with the power plant operator. This also has a
relationship to the question of low-Btu gasification
which, because of the low energy density of the
product gas, must be accomplished adjacent to or
very close to the power plant site. Thus, solvent
refining has the greatest versatility with respect to the
questions of producing the sulfur in a stable,
innocuous form, and the freedom of locating the
processing plant at whatever location appears to be
most feasible with respect to the source of coal, the
existing or most attractive future transportation
network, the markets for byproducts, and so forth.
Another aspect is that transportation savings are in
proportion to the nearness of the processing plant to
the mine. This means that solvent refining could offer
large transportation savings not applicable to
gasification. It also follows that flue gas processing
would create additional transportation expenses in
comparison, since large quantities of processing
materials would have to be shipped in to the power
plant site.
In the context of retrofitting an existing plant in
order to meet some particular sulfur dioxide
abatement goal, there are many plants in which
available space limits the choice. In a sense, this is an
environmental question. I can visualize many existing
power plant sites which simply would not have
sufficient room for the installation of flue gas
cleaning processes or which would not have space
available adjacent to the plant site for the
construction of gasification facilities. In such
situations, solvent refined coal offers an apparent
solution, because retrofitting could be accommodated
with very small modifications to the plant, and
existing storage and handling facilities could be
utilized. Solvent refining offers an alternative to
premature obsolescence for such plants.
Still another factor for consideration has to do with
the interaction of the alternative on the operations of
the power plant itself. For example, flue gas
processing requires of the power plant operating staff
some skills and disciplines which are not customarily
found at such facilities. This would necessarily
enlarge the scope of operator training and the breadth
of skills required in plant operations and control.
Flue gas processing brings also to the plant large
quantities of additional materials, such as lime or
limestone as mentioned above, and the problems of
waste control (like disposal of calcium sulfate/sulfite
sludge) could prove to be formidable.
One other area which is frequently overlooked in
comparing compliance strategies for pollution
abatement goals is how well the strategy chosen
blends with expected future technolgoy. For
example, the electric utility industry is constantly
striving for increases in plant efficiency. One of the
best or most promising options for improving plant
efficiency is referred to as combined-cycle generation.
In this concept, fuel is burned in a combustion
turbine which drives an electric generator. The hot
combustion gas from this turbine is passed to a boiler
where steam is generated to drive a steam turbine,
which drives another electric generator. It would
seem that low-Btu gas is the ideal fuel for
combined-cycle generation; undoubtedly, this should
create bias in favor of low-Btu gas. There is some
possibility that solvent refined coal may prove to be a
suitable fuel for combustion turbines; if so. it would
then qualify for all the advantages now anticipated
for low-Btu gas. In addition, it has the advantage that
it can be readily stored and used as needed. This
feature is in contrast with the low-Btu gas which must
166
-------
be made practically at the rate at which it is utilized,
because storage of large quantities is not feasible.
The influence of the chosen compliance strategy on
plant reliability is another most significant
consideration. In this instance, both the clean fuel
options offer advantages over flue gas cleaning.
Clearly, flue gas processing, however reliable it may
prove to be. must be performed in series with all
other operations in the plant; therefore, the net affect
is necessarily to reduce the overall plant reliability. If
there is any choice at all between low-Btu gas and
solvent refined coal as related to plant reliability, one
would assume that the quality of the fuel would
weigh less in the consideration than the source of
supply. Therefore, since the low-Btu gas plant does
not allow the prospect of fuel storage, my own
judgment is that it offers somewhat higher risk to
reliability than solvent refined coal.
My last item pertains to the sensitivity of the cost
of the alternative to the kind of duty cycle which it
must perform. To be more specific, the electric utility
industry generally classifies facilities in terms of
caseload, intermediate load, or peaking load. I
suppose that the terminology makes it clear that
baseload facilities operate at rated capacity for a large
fraction of the time, whereas the peaking facilities are
called upon intermittently to meet peak demands.
The baseload operation which might be fulfilled in
the future with combined-cycle-power plants
certainly could be met with either of these three
alternatives being discussed, and all three would
function better for baseload operation than for either
intermediate or peaking duty- On the other hand, as
one moves away from baseload operations, it is clear
that solvent refining emerges with an increasing
advantage because the fuel processing facilities could
be operated to give maximum production efficiency
and the product could be stored and used as needed.
This is not true for low-Btu gas production, and it is
presumed that fluctuating demands in flue gas
processing would aggravate operational problems
which otherwise might not appear.
In summary, the points I have raised in this
discussion today are obviously superficial in one
sense, but they suggest a line of thought which the
power plant operator or planner must follow in order
to make rational choices which take into account the
constraints I mentioned in the beginning: legal,
logistic, technical, and economic. It is perhaps too
soon to be very quantitative in analyzing a number of
the features of either of the three alternatives which
have been used in my remarks, because apparently all
three are in their infancy with respect to the
requirements which would be imposed on a large
commercial venture. As complex and as uncertain as
these options may appear, they nevertheless provide a
fertile area for analysis and development of system
strategies which may be of great value not only to the
corporation involved, but to the customers being
served.
167
-------
168
-------
ENVIRONMENTAL FACTORS IN COAL LIQUEFACTION PLANT DESIGN
J. B. O'Hara, S. N. Rippee,
B. I. Loran, and W. J. Mindheim*
Abstract
Environmental factors will play an important role
in the design and operation of coal liquefaction
plants. Such plants are a major national goal. The first
large units could be built during this decade.
Proposed treatment methods are discussed for solid,
liquid, and gaseous effluents based on a preliminary
liquefaction plant design developed for the Office of
Coal Research by The Ralph M. Parsons Company.
An approach to noise control procedures designed to
satisfy requirements of the Occupational Health and
Safety Act is also described.
During the course of future development efforts,
further research is recommended to develop
additional data and information on environmental
factors. Such data will further improve the
effectiveness and economy of plant environmental
control and of the monitoring systems.
INTRODUCTION
Environmental factors were an extremely
important influence on the study—recently
completed by The Ralph M. Parsons Company for the
Office of Coal Research (OCR)—of preliminary design
and estimated cost for a demonstration-scale plant to
produce clean boiler fuels from coal.
The importance of proper environmental safeguards
was considered twofold. First, the design of a
demonstration-scale plant is expected to be a
forerunner of many large plants producing clean fuels
from coal; therefore, the advantages of good
environmental protection elements in the design
could be magnified many times nationwide. Second, a
large body of opinion maintains today that
environmental protection and efficient energy
production are natural enemies. Since both
environmental protection and coal conversion are
major national goals, the validity of this widely held
opinion would pose a suostantial problem to both
national programs.
•All are at The Ralph M. Parsons Company, Pasadena,
California- O'Hara is Manager of the Energy Department;
Rippee is Project Manager; Loran is Senior Environmental
Engineer, Systems Division; and Mindheim is Chief
Environmental Engineer.
In the Parsons role as technical evaluation
contractor to the Office of Coal Research, we found
that the environmental protection objectives, as
presently known or anticipated by pending
legislation, can probably be achieved with appropriate
expenditure of money and effort.
Our approach to a discussion and current
assessment of environmental factors in coal
liquefaction centers on a brief description of the
preliminary design for a complex to liquefy 10,000
tons/day of coal. This paper discusses its expected
effluent streams and the probable methods of treating
them in order to create an environmentally
acceptable facility.
The discussion also includes the best judgment
estimates of quantities and compositions of certain
effluent streams, and our recommendation that coal
liquefaction pilot plants emphasize further
environmental research and development to insure
use of the most effective treatment methods when
commercial plants are built.
The design basis of our presentation uses Illinois
No. 6 coal to produce two grades of boiler fuels, plus
lesser quantities of naphtha and byproduct sulfur.
The design was developed as a part of our assignment
from the OCR. Reports describing the results have
been published by the OCR (ref. 1). Therefore, the
process description presented here is brief, and is
chiefly intended to show principal sections of the
coal conversion complex pertinent to the discussion
of environmental factors.
PROCESS DESCRIPTION
The process configuration is depicted in the block
process flow diagram shown in figure 1. This clean
boiler-fuel facility consists of a coal preparation
section, a coal liquefaction section, and a gasification
section. This complex is designed to produce two
low-sulfur liquid fuels, sufficient to supply a
600-megawatt power plant. Some naphtha and
byproduct sulfur are also produced. The light
hydrocarbons formed are burned as plant fuels.
COAL PREPARATION, DRYING,
AND GRINDING
Run-of-the-mine coal is stockpiled and prepared for
169
-------
uii B|iy« <• v
3S
\ \ */}
...
"Y~
f
•..«
*"'
»
...
,
ion it
Mil
P|»t
11
11
U
I
••fill
II
.<»
IMP 1
.
'
Mf Iff U I
•IIVCII 1
I •"'*"•'
*•• to«o<
PMM nBE
GMItH
•II
* J
BIHI
•
eg
Ml IH
Ml
Mil
mil
u
,
• i
u
1
1
.
•L
11
1
a*
•
'
^
Ml
IM1I
1 '
I1UIVI*
IWVM
••11 II
*
I
H UIIIMIII
UII1 11
=•
_-
•*'• !"» J tuiiu* IIMI ^
•Ml. Uf ...... r «'">
I 1
•III ••! 1
"* u... ,. "F* ••' » * «" »' •»" «J S a
T c*.».^.i i I c :
U «l .•• / 1
II ' 1
dim 1 | iniiu 4 "• "y
/^ "" ' ""'yBIMlT"1 ll— ' *
1 l~""
11 limn ' . .«mi.i m 1 1 ui.ii. mnci T ^ ~T f=^J=-^~
f i r t " -"-" l ' ^-=-
1 1 Ti *"•"•-"
niTun ^ .«„"",.«. DBiiutii fun flu ' wu IID u M'uuan ^T^^^^^^^T- ^, -*a*-
gmut«nM «
-------
plant feed. Preparation of coal feed consists of a
washing plant where a series of jigs, screens,
centrifuges, cyclones, and a roll crusher produces
washed minus 1%-inch coal. Refuse from this
operation is returned to the mine area for burial. Fine
refuse is pumped to settling ponds for further
treatment. The crushed coal is then dried in a flow
dryer and reduced to minus 1/8 inch in pulverizers
for dissolver feed.
LIQUEFACTION PROCESS
Feed to the liquefaction section consists of minus
1/8-inch coal as a 50-percent-by-weight slurry in a
recycle solvent, which is fed to reactors where it is
contacted with reducing gases at about 850°F and
1.000 psig. The gas phase of the reactor discharge is
largely recycled, while the solid phase is separated
from the liquid phase by filtration. The resulting
filter cake serves as feed to the gasification section for
syngas production.
The liquid phase filtrate produced in the filtration
operation is further separated by fractionation into
an overhead naphtha stream, a distillate light boiler
fuel, and a residual fuel oil. Further hydrogenation of
the distillate fuel produces acceptable low-sulfur fuels
for boiler firing.
Gases produced in the various units are combined
and fed to the acid-gas-removal plant, where carbon
dioxide and hydrogen sulfide are removed by
scrubbing. The hydrogen sulfide is converted to sulfur
in sulfur recovery plants. Carbon dioxide is vented to
the atmosphere.
GASIFIER PLANT
Wet filter cake from the liquefaction process is fed
to a slagging, suspension-type gasifier where it reacts
with steam and oxygen at 3,000°F and 200 psig
pressure. The carbonaceous material is gasified and
produces primarily synthesis gas (carbon monoxide
and hydrogen). An onsite oxygen plant supplies the
required oxygen for this operation.
Most of the cooled syngas is treated for hydrogen
sulfide removal and fed directly to the coal
liquefaction section of the plant. Syngas not sent
directly to the liquefaction section undergoes shift
conversion, carbon dioxide removal, and methanation
to produce a high purity, hydrogen-gas stream, which
is used in hydrogenation of the light distillate and
naphtha product streams produced in the liquefaction
section.
An overall material balance is shown in figure 2.
The 10.000 tons of coal feed are converted into five
products. Salable products are 1,440 tons/day of
0.2% sulfur liquid fuel oil, 2,920 tons/day of heavy
liquid fuel at 0.5% sulfur, 270 tons/day of naphtha
with 1 ppm of sulfur, and 320 tons/day of sulfur. The
2,140 tons/day of pi ant-produced fuel gas and a small
amount of heavy liquid fuel oil are burned for plant
operation. The remaining feed streams consist of
1,980 tons/day of oxygen and 21,760 tons/day of
water.
Major process waste streams shown consist of
19.430 tons/day of waste gases. 6,390 tons/day of
waste water, and a solids waste stream consisting
primarily of 710 tons/day of gasifier slag. Each of
these categories is discussed in the following sections.
GASEOUS EFFLUENT
Gaseous process waste streams exhausted to the
atmosphere are generated in various sections of the
plant. These streams are shown in figure 3, which
again depicts the plant process with highlights of
gaseous emission streams. Principal gas streams
leaving the complex are from the oxygen plant, C02
removal unit, sulfur plant stack gas, and the
combustion gases resulting from fired heaters in the
liquefaction and steam generation sections. Off-gases
from the gas turbines utilized for power generation
are also present.
Figure 4 summarizes the exhaust gas streams and
their thermal contents that are expelled from the
plant complex. Combustion gases amount to about
90 percent by volume of the total plant gas emission.
A total of 990 million cubic feet/day of combustion
exhaust gas, containing about 15 billion Btu/day, is
exhausted to the atmosphere. Contaminants will
consist of sulfur dioxide and nitrogen oxides. When
firing with the low-Btu gas produced in the plant,
contaminant concentrations will range from about 4
to 15 ppm of sulfur dioxide and 50 to 100 ppm of
nitrogen oxides. The small amount of fuel oil
required to supplement the low-Btu gas firing for
plant power needs contributes about 2.2 million
cubic feet/hour of combustion gases containing about
80-100 ppm of sulfur dioxide and 100-150 ppm of
nitrogen oxides.
Other waste gases exhausted to the atmosphere
consist of the oxygen plant exhaust, sulfur recovery
plant tail gas, and the carbon dioxide waste stream
from the CO? removal unit. It would be possible to
recover an additional 2,260 tons/day of nitrogen and
171
-------
WASTE GAS
19,430'TONS/DAY
COAL
10,000 TONS/DAY
OXYGEN (FROM AIR)
1980 TONS/DAY
WATER
21.760 TONS/DAY
r
CLEAN
BOILER
FUELS
FROM
COAL
DEMONSTRATION
PLANT
I
SLAG
710 TONS/DAY
PRIMARY PRODUCTS
LIQUID BOILER FUEL (0.2% S)
1440 TONS/DAY
HEAVY LIQUID BOILER FUEL (05%S)
2920 TONS/DAY
PLANT FUEL
2260 TONS/DAY
NAPHTHA (1 PPM S)
270 TONS/DAY
SULFUR
320 TONS/DAY
WASTE WATER
6390 TONS/DAY
Figure 2. Overall Material Balance
172
-------
,
M •.*••»*;
"""""55
A IIUMI •,*••(!
CO
k*i •Mill* 'Q Mill
_icr
=±=i
"P" *
-^£f
ill
„
.X
/
BITfll
(Mil
1
CtM 11
g«il
»!••!
11
{
••TIM
"
lull
IM 1
.
T"T
JJ
••!» 1C
^ MIT
J
/('9:;^o'.'
•iiviti turn
1 1
••it
jm miu mi J
•ITM
>•• unimn
'>*.»otin
Mil*
1
1
nai
ii
HI
•1
II
^
I
ii
• III!
U
1
\
I -Kim
ys%t
Hi«m
T"
7
s
IMtMMt
Ml U
IMIHI
HUH
— ».M«I
^ — « ' ; «.»., "««•-
1 F%K&^ '/^/r-W/l |
^ IIMVH > """ «•»'•>'•• p «l MMVU nn*H1N«
1 """ """' •""• " ,
U ••• It* f |
Ul ^
U 1 111 |Ml |M \ ***•' 'Ml ««
I Xj.'-W'"' I ••» »
| /'WJX'V/J J , | ^
ycuiVwiH' ir "•«» 1 «»«i« m t)l .IMTM pHiwt r "* T ^^*1—
55»ips r r t „„,. Hu m
i i I* *-""•"
utiuii ... .*!«!.•• iniiinii nit MI * IIMIJI uuiritiiL -f "" *^*t- ^°s
•MI 11 """ '* 1 1 "" ••**
1 *
•invi.ii Mima J
^=0-..*^;
N*I>UBIIIUI
%%%%^
Figure 3. Demonstration Plant Clean Boiler Fuels From
Coal Gaseous Process Waste Streams
-------
COAL
10.000 TONS/DAY
OXYGEN (FROM AIR)
1.980 TONS/DAY
WATER
21.700 TONS/DAY
CLEAN
BOILER
FUELS
FROM
COAL
DEMONSTRATION
PLANT
-^-COMBUSTION GASES
OXYGEN PLANT UNIT 24
WASTE GAS
SULFUR RECOVERY PLANT
TAIL GAS
C02 REMOVAL. UNIT 21
WASTE GAS
WASTE GAS STREAM
COMBUSTION GASES
1. FUEL GAS
2. FUEL OIL
OXYGEN PLANT
UNIT 24
SULFUR REMOVAL
PLANT TAIL GAS
C02 REMOVAL
UNIT 21
COMPOSITION
32K02.94KC02.
1 5.6% H20. 71.3V, N2
33%02.I08'/.C02.
12.7XH20.732!.N2
N; AND RARE GASES
72", N2.
REMAINDER C02
9954 C02
OUTPUT,
CUBIC FEET/DAY
(MILLIONS)
93S
54
64
324
143
CONTENT.
BTU/OAY
(MILLIONS)
14.150
850
NIL: AMBIENT
CONDITIONS
NIL. AMBIENT
CONDITIONS
NIL. AMBIENT
CONDITIONS
MAJOR CONTAMINANT
4-15ppmS02
50-100 ppmNOx
80-100ppmS02
100-1 50 ppm NO,
35 ppmP ARTICULATES
NONE
10 ppmmix H2S
NONE
Figure 4. Gaseous Waste Process Streams
174
-------
rare gases from the oxygen facilities if area sales
justify costs for their recovery. The same is true for
the carbon dioxide waste stream from the CO2
removal unit, which amounts to about 14,3 million
cubic feet/day of gas containing about 99 percent
carbon dioxide.
Waste gas effluent from the sulfur recovery plant
would be about 32.4 million cubic feet/day at 93°F.
Hydrogen sulfide content of this stream during
normal operation is expected to be less than 5 ppm.
The main constituent of the gas stream is 72 percent
nitrogen. The remainder is primarily carbon dioxide.
In summary, approximately 1 billion cubic feet/day
of various gas streams from the complex are
exhausted to the atmosphere. All gaseous waste
effluent streams meet applicable standards. Fuel
combustion gases exhausted will meet ambient air
quality standards for nitric oxide (NOX) and sulfur
dioxide (SO2); this is also true for paniculate (fly
ash) entrained in the gases since primarily gaseous
fuels are used. When fuel oil is used to supplement
gaseous fuel, particulates are estimated at about 39
ppm, which meets ambient air quality standards. The
rate of NOX production by various plant fuel sections
is a function of maximum flame temperature and
retention time. Furnace designs shall be such that exit
combustion gases shall meet the nitrogen dioxide
(N02) standards. The gas waste effluent stream from
the sulfur recovery unit is designed to operate
normally at about 5 ppm of hydrogen sulfide, well
within standards.
LIQUID EFFLUENT
Figure 5 is a flow diagram showing the major
aqueous wastewater streams leaving the plant
complex. Approximately 532,000 pounds/hour of
wastewater are discharged from the complex, or
about 1,060 gallons/minute. Cooling tower
blowdown is slightly more than one-half of the total,
or about 600 gallons/minute. Sanitary waste water,
boiler blowdown, treated oily water, and stripped
plant sour water make up the remainder of the plant
complex wastewater stream.
Process means have been provided for stripping
nonphenolic process water, and this stripped water is
returned to process for reuse. Also, stripped waste
phenolic water effluent, which contains the greatest
number of pollutants, will average about 40
gallons/minute. This stream joins the sanitary waste,
treated oily water, cooling tower, boiler blowdown
streams, and backwash water from deminerahzers and
sand filters. This combined stream undergoes final
treatment in the aerated lagoon and biopond before
leaving the complex.
Cooling tower and boiler blowdown streams are
expected to contain not greater than 15 ppm of
phosphate, 10 ppm of chromate, and 5 ppm of zinc.
Table 1 summarizes the estimated wastewater
treatment data and contaminants in the effluent
stream leaving the complex.
The total oil in the process waste stream is
expected to consist of 80 percent by weight of
naphtha and 20 percent acid oil, which amounts to
about 5 ppm TOC feed. The COD feed is estimated at
a level of about 150 ppm with a BOD level of about
40 ppm.
The aerated lagoon operation is expected to
provide reduction of 96 percent of the inlet sulfide
concentration, 94 percent of ammonia, 88 percent of
acid oil, 75 percent of BOD, 75 percent of suspended
solids, 95 percent of phenols, 69 percent of COD, and
99 percent of phosphates. The aerated lagoon is
expected to handle most of the impurities in the
waste streams of the coal conversion complex based
on a flow of water from the phenolic sour water
stripper of 40 gallons/minute into the aerated lagoon.
However, it is possible that phenol and heavy metals
may still exceed local or State standards. In this case,
they will be further reduced by adding an activated
sludge plant prior to final biopond streatment or by
extending the retention time and providing more
aeration to the biopond. The final design decision will
be based upon data obtained from the pilot plants.
Dissolved impurities from the cooling tower and
boiler blowdown streams are stable and will not be
destroyed by either impounding or aeration.
However, it is possible to eliminate chromates by
utilizing organic and biodegradable cooling water
inhibitors. These inhibitors are normally not as
economical or effective as chromates. Provision has
been made for pretreatment of these streams in the
neutralization pit, should it be necessary to
precipitate impurities prior to pumping to the aerated
lagoon.
SOLID WASTES
The block flow diagram of figure 6 shows the types
of waste solids generated by the complex. Major solid
wastes are produced during pretreatment of the
run-of-mme coal and gasification of the liquefaction
filter cake to produce syngas. Additional solids of
lesser quantity also requiring disposal are various
175
-------
o>
RETURN WATER
TO PROCESS
PHENOLIC AND
NONPHENOLIC
SOUR WATER
ACID GAS TO SULFUR
RECOVERY PLANT
ABSORBER
STRIPPER
PROCESS
UNITS
SLOP OIL TO
PROCESS
OILY
WATER
COALESCER
SAND FILTER
UNITS
SANITARY
SEWAGE
SEWAGE
TREATMENT
PLANT
BOILER SLOWDOWN-
COOLING TOWER —
SLOWDOWN
SPENT CAUSTIC —
NONOILY FILTER —
BACKWASH WATER
NEUTRALIZATION
BASIN
AERATION LAGOON
AND BIO-POND
TREATED
EFFLUENT
Figure 5. Demonstration Plant-Clean Boiler Fuels From Coal
Major Aqueous Waste Water Streams
-------
Table 1. Estimated waste bio-pond effluent concentrations for demonstration plant
CONSTITUENTS
SULFIDE
AMMONIA
OIL
TOC
BOOs
SS
PHENOL
COD
PHOSPHATE
PH
CHROMATE
ZINC
COLIFORM
ORGANISM
BIOLOGICAL CHARGE
LB/OAY
1.48
24
72
60
538
660
96
1,920
145
6-9
91
45
PPM
0.12
1.88
5.63
4.69
42
51.6
7.5
150
11.3
6-9
7.1
3.5
15/100 ml
BIOLOGICAL EFFLUENT
•LB/DAY
O.OB
1.45
8.64
-
134.5
165
4.8
576
1.45
6-9
91
45
PPM
0
0.11
0.68
-
10.5
12.9
0.38
45
0.11
6-9
7.1
3.5
15/1 00 ml
STATE REQUIREMENT
PPM
-
2.5
1.0
-
20
25
0.3
-
1.0 as P
5-10
0.05 as Cr04
1.0
400/100 ml
TOTAL ESTIMATED FLOW TO BIO-POND
1060GAL/MIN £ 12.8 MILLION LB/DAY
spent catalysts generated in the hydrogenation, shift In the coal preparation plant, reject material from
reaction, methanation, and tail gas sections. After the primary coal breaker amounts to about 450
being rendered inert, these spent catalysts, which tons/hour. This material is combined with the
have a lifetime of 2 to 3 years, will be disposed of by double-deck screen reject, about 88 tons/hour, and
backhaul and will fill in the mined-out coal areas. conveyed to a truck-loading bin. Trucks transport the
177
-------
COAL
10,000 TONS/DAY
i
COAL
PREPARATION
UNIT 10
I
i
GASIFICATION
UNIT 18
1
i
PROCESS UNITS
REQUIRING
CATALYSTS
BOILER FUEL
PRODUCTS
REJECT SOLIDS
RETURN TO MINE
1788 TONS/DAY
SLAG DISCHARGE
710 TONS/DAY
CATALYST WASTES
0.55 TONS/DAY
NOISE POLLUTION
Figure 7 shows possible plant and equipment areas
suspected of noise pollution. The Occupational
Safety and Health Act of 1970 regulates the amount
of "weighted" noise to which a worker can be
exposed, in order to protect him from ear damage.
Local code usually regulates the amount of noise, in
decibels, that an industrial plant can generate above
the normal ambient background level of the
community, measured at the property line. Noise
control is an integral part of the layout and design of
coal conversion plants. During equipment design and
engineering layout, special attention will be given to
fans and compressors, gasifiers, fired heaters, and gas
turbine areas to minimize noise-source levels and any
excessive noise radiation effect on plant personnel.
Equipment vendors will be requested to show
evidence that installed equipment will meet noise
level requirements. However, noise from equipment
components may not represent the total sound level,
including all equipment items, motor drives, piping or
ductwork, and other associated equipment. Added to
these factors are reverberations from adjacent
equipment, buildings, and sound interferences from
different sound sources. Consequently, total
engineering plant and equipment layout design will
play an important part in lessening plant noise level.
Figure 6. Demonstration plant—clean boiler fuels
from coal major solid waste streams
DEVELOPMENT PROGRAM RECOMMENDATIONS
waste material to the coal mine for burial in
mined-out areas. This solid consists mainly of
low-grade coal and shale and is about minus 3 inches
in size. The thickener underflow, which is a fine
reject material of minus 1/16 inch in size, is pumped
to a tailings-pond for solids recovery and for recycle
of the decanted water to the coal preparation plant
These solids also consist primarily of low-grade coal
and shale.
Gasifier slag produced is approximately 710
tons/day. This material will be dewatered and
conveyed to a truck-loading bin for transport to the
mined-out areas of the coal mine for burial. The
material will probably be utilized later as an inert
additive in the manufacture of cinder blocks.
Past experience and judgment superimposed on the
preceding brief summary and analysis, led us to
recommend that further coal liquefaction and
gasification research is required to determine the
presence or absence of the constituents shown in
table 2. If present, they are expected to occur in
minor concentrations, but will require proper
treatment facilities. Availability of this added
information will further improve reliability of the
plant's environmental control and monitoring
systems.
REFERENCE
1. Demonstration Plant - Clean Boiler Fuels From
Coal • Preliminary Design/Capital Cost Estimate,
R & D Report No. 82, Interim Report No. 1,
Vols. I and II, prepared by The Ralph M. Parsons
Company for the United States Department of
the Interior, Office of Coal Research.
178
-------
lilt • !!••• II «
-J
CD
Jf
7
'tfffifi
'•(ff(<*
f^fflr
»«u
w?^
"!%%
"^
(
Ulln.1
IM tf
I
'
ill it in
MCfCll 1
I-"-"
>.. Cl.lt
!«. .«<
V"T
) 1
f//SS//,
ffa*M
."1
•MB
^
W//tSi
MlJ
•MIR
Mil
• ?
f?^
Of
•
J
iV//
Mil
1
BIIMI 1
x$ r
9
3
1 I.I4IHII
IUI B
I.I1IID
' - -
11"'" "• * I-"'" """
\ 1 1
' »»''•' i'iksd ' •"" 1 — " ,
1 ^^^™ i ^^^^i^taMmt ti ~
J UMiB.il t » nnin. ;
••H FHIIr PVHHII __^^^^<
v «.i "« F 1
r i i ' i
I M t \n \ \ ^ »u 14 *
J I -"".
.XX" _-^
iiuim • ??""'""2% intiiuf>n.i««ct T^"^ ^"~>
r 1 / 4 ^Jjnn^ | | *
1 " 1 I i"" 4«.»— •
IIIIMII ftfZJFSiZSfi'. mini.!! % Ywi MI%^ ' w«inimiyiiiii ^^^ ^^*^.
i *r^ f
•icawiui HnwiHt J
nut fin iu
Figure 7. Demonstration Plant—Clean Boiler Fuels From Coal
Unit Areas Possible Noise Pollution
-------
Table 2. Recommended additional contaminant research program for
coal liquefaction plants
COMPOUND
EXPECTED TO OCCUR IN
REMARKS
AMMONIA (NH3)
HYDROGEN CYANIDE
THIOCYANATES
PHENOLS
ORGANIC ACIDS
ALDEHYDES AND
KETONES
METAL SULFIDES
MERCAPTANS
CARBON DISULFIDE
CARBONYLSULFIDE
COAL TRACE ELEMENTS
(Be. F.As. Hg.ANDPb)
BOTH GASIFICATION AND
LIQUEFACTION
BOTH GASIFICATION AND
LIQUEFACTION
BOTH GASIFICATION AND
LIQUEFACTION
LIQUEFACTION
LIQUEFACTION
LIQUEFACTION
LIQUEFACTION
BOTH GASIFICATION AND
LIQUEFACTION
BOTH GASIFICATION AND
LIQUEFACTION
ASSUME PRESENT; QUANTITY NEEDS
VERIFICATION
ASSUME PRESENT; QUANTITY NEEDS
VERIFICATION
PRESENCE SUSPECTED; NEED DATA
PRESENT; QUANTITY NEEDS VERIFICATION
PRESENT; QUANTITY NEEDS VERIFICATION
PRESENCE SUSPECTED: NEED DATA
PRESENCE SUSPECTED; NEED DATA
PRESENT; REMOVED IN GAS PURIFICATION
STEPS; QUANTITY NEEDS VERIFICATION
GASIFICATION DATA AVAILABLE
INDICATES PRESENCE; LIMITED DATA
AVAILABLE ON LIQUEFACTION PROCESS
180
-------
COLONY
OIL SHALE DEVELOPMENT
PARACHUTE CREEK, COLORADO
Mark T. Atwood*
Abstract
Production of oil from oil shale involves mining.
crushing, retorting (pyrolysis), and product oil
upgrading. The disposal of the processed shale and
vegetation of the exposed surface is a major
environmental consideration. Several years of
intensive investigation have provided satisfactory
solutions to all problem areas.
BACKGROUND
Work on the development of the TOSCO II
oil-shale-retorting-process was begun in 1956 by The
Oil Shale Corporation. A pilot plant was built in 1957
near Littleton. Colorado. All of the early
experimental work was contracted to the Denver
Research Institute.
In 1964, Colony Development Company (Agent)
was formed by Standard Oil Company of Ohio, The
Cleveland-Cliffs Iron Company, and The Oil Shale
Corporation (TOSCO). In the following year, this
group began operation of a 1,000-ton-per-day
semiworks retort and mining operation at a site 17
miles north of Grand Valley, Colorado. The Oil Shale
Corporation continued operations on its own in 1966
and 1967; in 1969, Atlantic Richfield Company
joined Colony as operator.
Semiworks testing was intensified in 1971 and
continued into April 1972. at which time operations
were suspended and the emphasis was shifted to
commercial design and environmental studies. In
1973. TOSCO and Atlantic Richfield selected C. F.
Braun & Co. as managing contractor for a
45.000-barrel-per-day commercial oil shale complex
to be constructed on Colony's Dow property at
Parachute Creek.
On January 5, 1974, Ashland Oil, Inc., joined the
commercialization program. On February 11, 1974.
Shell Oil Company signed a letter of intent to
participate in the preconstruction program. Field
construction is expected to begin in the fall of 1974
or early 1975 if necessary government permits are
received and adequate financial arrangements are
completed in time.
'Manager of Laboratories, The Oil Shale Corporation,
18200 West Highway 72. Golden, Colorado 80401.
THE TOSCO II PROCESS
A schematic of the TOSCO II retort is shown in
figure 1. Raw shale is fed through a surge hopper and
preheated by dilute phase fluid bed techniques. The
preheated feed is then transported to a pyrolysis
drum where it is contacted with heated ceramic
pellets. The solid, processed shale leaves the pyrolysis
drum and passes through the trommel screen; then it
is cooled and goes to storage. The cooled ceramic
pellets pass over the trommel screen and return to the
pellet heater by the ball elevator. Pyrolysis vapors are
condensed in the fractionator. Uncondensed
hydrocarbon gases can be utilized as an inplant fuel,
as indicated in figure 1, or can be processed to
produce hydrogen.
Since the retorting step itself is carried out with an
externally heated transfer medium, the pyrolysis
gases are obtained undiluted with nitrogen and
combustion derived carbon dioxide. A typical
TOSCO II process gas analysis is given in table 1.
Typical shale oil from the TOSCO II process is
described in table 2.
PARACHUTE CREEK
FUTURE COMMERCIAL OPERATIONS
The location of the Dow property and the areas of
major development within it are shown in figure 2. A
mine bench is located at the base of Middle Fork of
Parachute Creek and the latest planned plant site is
on the top of the Roan Plateau. Processed shale
disposal will be as indicated in Davis Gulch.
A schematic diagram of the oil shale processing
operation is shown in figure 3. This diagram
illustrates the consecutive steps of mining, crushing,
stockpiling, final crushing, pyrolysis, and spent shale
disposal. It also shows the facilities for upgrading the
raw shale oil to a final product containing very low
levels of nitrogen and sulfur. This final product would
serve as an environmentally acceptable fuel oil.
Mining will be conducted by conventional room
and pillar techniques, as illustrated by figure 4. Two
30-foot benches will be mined by the sequence of
drilling, emplacement of explosives, blasting, and
mucking. Front end loaders will place the broken
shale rock into trucks for movement to the primary
crusher. The top bench will be extracted before
181
-------
RAW SHALE
FLUE GAS TO ATMOSPHERE
BALLS-
SPENT SHALE
TO DISPOSAL
Figure 1. Topco II Process
-------
Table 1. TOSCO II process typical gas analyses
(33 gallons per ton raw shale)
Component
H2
CO
CH4
C2H6
C2H4
C3H8
C3H6
i-C4H10
n-C4H1Q
Butenes
C5's
C6's
Cy's
Cs's
C8+
C02
H2S
Weight percent
1.53
3.37
8.25
10.53
5.07
6.00
5.25
0.49
2.54
5.11
6.18
4.35
2.81
1.35
0.36
31.84
4.97
100.00
Mole percent
22.44
3.56
15.23
10.31
5.36
4.03
3.71
0.26
1.30
2.70
2.55
1.54
0.83
0.36
0.09
21.43
4.30
100.00
183
-------
Table 2. Typical shale oil from the TOSCO II process
Gravity, °API 22.0
Pour point, (°F) 30.0
Sulfur, (wt %) 0.8
Nitrogen, (wt %) 1.8
Carbon, (wt %) 84.7
Hydrogen, (wt %) 11.3
Carbon to hydrogen,
weight ratio 7.5
Distillation Volume percent
IBPto400°F 18..0
400 to 600°F 24.0
600 to 900°F 34.0
900°F and heavier 24.0
184
-------
DERE CABIN SITE
PLANT SITE
PROCESSED
SHALE DISPOSAL
LATEST
PLANT SITE*-.
PLANT ACCESS ROAD
MINE BENCH
SEMI-WORKS PLANT
MINE BENCH ROAO
VALLEY ACCESS ROAO
<*•*
GRAND ./,
VALLEY ,
'•' :: . ,: ' • / .' j
** ' ••• •-••-.*.'• •'.•'•* V 17 -i
^J^5''= .' .••' >*^/ . i. _1: .!.::_
Figure 2. Location of Dow Property and Areas of Major Development
within the Parachute Creek Basin
185
-------
FINE ORE SILO
COARSE ORE STOCKPILE
FINAL CRUSHING\
\ '
COARSE ORE
PYROLYSIS GAS & OIL
PRIMARY CRUSHING
UPGRADING UNITS
SPREADING 4 REVEGETATING
OIL SHALE MINE
FUEL PRODUCTS
LOW SULFUR FUEL OIL
LPG SPECIAL
BY-PRODUCTS
COKE
AMMONIA & SULFUR
Figure 3. Schematic Diagram — Oil Shale Processing
-------
Figure 4. Room-and-Pillar Mining Concept
-------
mining the lower bench. Approximately 61,000 tons
will be mined per day. About 60 percent of the
inplace shale will be removed with the remainder to
be left in place as pillars to support the overburden.
Eventually, 4,100 acres will be mined in this fashion
on the western portion of the Dow property.
Figure 5 shows the shale-oil-complex site indicating
positions of the mine, processing, and processed shale
disposal areas.
A closeup of the retorting and upgrading units on
the plateau is shown in figure 6. This sketch
illustrates the movement of coarse shale to the
secondary crushing operation and the six pyrolysis
units, each having a capacity of around 11,000 tons
per day. In the foreground is the upgrading or
hydrotreating facilities which produce the final
product oil. Byproducts produced are sulfur, coke,
and ammonia.
Construction of Colony's commercial oil shale
complex at Parachute Creek will require about 40
months and a peak construction force of about 1,200
employees.
PROCESSED SHALE DISPOSAL
The spent shale remaining after pyrolysis in a
TOSCO II retort has been termed "processed shale"
(ref. 1). It is a dark, granular solid which contains
residual carbon but no residual kerogen.
About 400 million tons of this processed shale will
be disposed of in Davis Gulch during 20 years of
commercial operation. This particular small valley has
a very limited watershed and low stream flow, and
the flooding hazard will be minimal. The moistened
processed shale will be deposited initially in side
draws of Davis Gulch to eliminate contact with
natural aquifers. Eventually, 800 acres will be covered
with the processed shale.
After compaction, the processed shale is nearly
impermeable and will not permit leaching or
percolation of water into surrounding aquifers.
Engineering studies indicate that a 1:3 slope
(vertical:horizontal) on the face is adequate from a
safety point of view, and Colony plans to use a slope
of less than 1:4 as an additional safety factor. Due to
the possibility of surface erosion from the action of
rain and melting snow, the surface will be benched at
regular intervals. This will reduce surface water flow
velocities and allow any sediment being carried to
settle out. This configuration is illustrated in figure 7.
As indicated in figure 7, a detention structure will
be built upstream of the processed shale pile to
prevent ground water from reaching the pile, and a
catchment dam will be placed downstream of the pile
to collect any surface runoff. The surface runoff will
be returned to the processed shale moisturizer and
thus eventually returned to the processed shale pile.
As permanent surfaces are created in the processed
shale placement operation, revegetation will begin at
the first available planning time in order to control
wind and water erosion. Prior to commencement of
revegetation, water spraying will be utilized to
control any dusting.
PROCESSED SHALE REVEGETATION
Work has been conducted at Colony Development
since 1965 with two major goals: (1) to establish a
long-lasting cover as soon as possible, and (2) to
obtain an ecosystem which closely resembles that
presently existing on the plateau (ref. 2).
The characteristics of freshly processed shale, as
compacted in the disposal area, which will govern
revegetation are as follows:
1. Low amount of available nutrients;
2. High soluble salt content;
S.Structural characteristics which, after
compaction, render it essentially
impermeable to precipitation.
The initial low fertility will be improved by the
application of fertilizers. Current plans are to add 600
pounds of phosphorus and 70 pounds of nitrogen per
acre in initial applications. Later, it may be desirable
to add organic matter, such as sewage sludge and
garbage, to stimulate microbial activity.
The soluble salt content can be gradually leached
down into the processed shale by the application of
water, thus taking advantage of the limited
permeability of the surface after treatment. This
procedure also lowers the pH of the processed shale
to a range which is normally encountered in soils in
the Parachute Creek Basin.
The structural characteristics of the processed shale
can be improved to allow infiltration of water by
addition of organic materials which would, as
indicated, lower the pH, lighten the color, and raise
the level of available nutrients. Such things as
sawdust, peat moss, sewage sludge, manure, and
ground garbage are being considered for this
application. All of these would stimulate the growth
of soil bacteria.
The dark color of the surface of the processed shale
absorbs heat, and temperatures as high as 140° to
150°F have been observed in the top one-half inch of
the compacted processed shale. This high temperature
would, of course, inhibit germination. The addition
188
-------
1 PLANT ACCESS ROAD 3 LOWER SEGMENT OF DAVIS GULCH 3 CATCHMENT DAM 4 MIDDLE FORK OF PARACHUTE CREEK
5 PROCESSED SHALE DISPOSAL IN DAVIS GULCH 6 REVEGETATED PROCESSED SHALE BENCHED EMBANKMENT 7 MINE BENCH
8 COARSE ORE CONVEYOR THROUGH TUNNEL FROM MINE BENCH 9 COARSE ORE CONVEYOR FROM TUNNEL TO FINAL CRUSHING
10 PROCESSED SHALE CONVEYOR 11 RETORTING 81 UPGRADING UNITS - PLATEAU SITE
FIGURE 5. SHALE OIL COMPLEX - COMPOSITE AERIAL VIEW
-------
1234
:-wi-^*SS S»J^8ffi^8S
:OARSE ORE CONVEYOR 2 PLANT ACCESS ROAD 3 COARSE ORE STORAGE 4 PROCESSED SHALE CONVEYOR 3 PYROLYSIS UNIT 6 FINE ORE SILO
7 FINAL CRUSHING UNIT 6 UPGRADING UNITS 9 ROAD TO PROCESSED SHALE DISPOSAL 1O STORAGE TANKS 11 CATCHMENT BASINS
Figure 6. Retorting and Upgrading Units — Plateau Site
-------
FINAL SHAPE OF PILE
FRESH PROCESSED SHALE
CATCHMENT 0AM
SURFACE RUNOFF FROM
PILE RETURNED TO
PLANT BY PIPELINE
VEGETATION
/ DETENTION
TURE
COMPACTED PROCESSED SHALE
PERMANENT STREAM DIVERSION
UNDER PILE
Figure 7. Cross Section of Processed Shale Disposal
in Shallow Canyon or Valley (in 8" width)
-------
of svaw has been found to be most suitable in
lightening the color and in helping to hold moisture
near the surface, thus aiding germination. The
addition of straw also reduces evaporation and aids
the mechanical stabilization of the surface. And. of
course, it eventually produces decayed organic
material.
Investigations are under way to determine the
suitability of placing a 6-mch cover of native soil on
the processed shale embankment. This would be
expected to provide for gradual water infiltration into
the processed shale, resulting in an even more
complete reduction of soluble salts. Revegetation
would be more straightforward than with the
processed shale itself.
The revegetation process will involve seeding with
various grass and forb species, followed by watering
and fertilizing. Plans are to fence out livestock and
natural herbivores during the initial establishment
phases. Even though investigations are still under way
to determine the best species mixture and intensity of
seeding, the following selection has been proposed by
Dr. William Berg of Colorado State University:
Seeding Intensity
(Ib/acre)
Common Name
of Vegetation
Western Wheatgrass 10
Sodar Streambank Wheatgrass 10
Crested Wheatgrass 6
Indian Ricegrass 2
Sand Dropseed 2
Fourwing Saltbush 9
Russian Wildrye 6
All species listed above are Colorado natives found
in the Parachute Creek area.
The final goal of the processed shale disposal and
revegetation is the formation of a plant community
similar to that which naturally occurs in the Davis
Gulch area. After leaching is completed and a sound
grass cover is obtained, there are plans to plant a 2- to
4-year-old stock of native shrubs including Gambel
oak. mountain mahogany, snowberry, serviceberry,
and sagebrush. The ultimate combination of grasses
and shrubs will blend in with the surrounding existing
vegetation.
In the first 10 years of operation, there will be a
need to revegetate about 9 to 14 acres per year. After
10 years of operation, there will be a need to vegetate
over 100 acres per year. Using 1973 cost figures, the
revegetation expenses will run about $1,600 per acre.
This cost may be as high as $2,500 per acre if a 6-inch
soil cover is applied.
WATER QUALITY AND CONSUMPTION
The commercial plant planned by the Colony
Development Operation will be located on the mesa
top west of Middle Fork of Parachute Creek. A map
of the Parachute Creek drainage system is shown in
figure 8. The quality of water at the various sampling
stations, shown in figure 8. illustrates the increase in
salinity from upper reaches of the drainage to the
point below Grand Valley. Sampling at Middle Fork
(Station No. 551) gives a total dissolved solids of 461
parts per million, and at Davis Gulch (Sampling
Station No. 552) the value is 446 parts per million.
At Parachute Creek below Grand Valley, the total
dissolved solids has increased to 791 parts per million.
This increase in total dissolved solids is believed to be
due to continual erosion of the soil and to the
percolation of water through the underlying soil
resulting in additional leaching of soluble salts. The
net result is that Parachute Creek, below Grand
Valley has a higher salt content than that of the
Colorado River. This information illustrates the
tendency toward increased salinity in this stream in
the absence of industrial activity.
The Colony shale oil complex, designed to process
66,000 tons per day of oil shale, will require 3 to 4
barrels of water per barrel of produced oil. More than
half of this water requirement will be used for
moisturizing processed shale and for controlling dust,
and will either become a permanent part of the
processed shale or will be evaporated. This part of the
water requirement can be obtained from impure
water sources, such as highly saline aquifers and
processed water from the oil shale complex. The
remainder of the water requirement, needed for the
production of steam, must be of higher quality and
will be discharged into the atmosphere as water
vapor. The upshot of this is that the processing
complex will not require discharge of any water
except as vapor. Thus, water use will be totally
consumptive.
As previously discussed, the processed shale storage
facility will be protected by a catchment dam
designed to retain runoff from the maximum
probable 1-hour thunderstorm. Therefore, almost all
runoff from the surface of the processed shale
embankment will be contained and reused. With no
water discharge occurring from Davis Gulch, the
Colony plant can then be considered a "zero
discharge facility."
If under highly abnormal precipitation
circumstances there is a discharge from the Davis
Gulch catchment dam and spillway, it would be
192
-------
*"* -->*' \
r" V' ^
/DAVIS ' "figfX
'GULCH \ F0RK V^
6.4 sq. mi. \ / 5.6sq.mi. /
X A ,-'
\ \ \ ••' >
{ \)Jp*lS 34.7 sq. ml.
1 ^s$plmt
V I /
E. MIDDLE FORK
EAST FORK
39.6 sq. mi.
SAMPLE LOCATIONS
STREAMFLOW STATIONS
Figure 8. Location of Stream Flow and Water Quality Stations
(from Skogerboe 1973)
193
-------
expected that the effect on base water quality would
be insignificant for the following reasons:
1. Any precipitation associated with flood
conditions would run off of the processed shale quite
rapidly and would have minimum contact with the
salt content of the processed shale, and thus not
produce an abnormally high total dissolved solids
content. During these periods of extremely heavy
precipitation, any leachate from the embankment
would be diluted with large volumes of natural runoff
from other areas in Davis Gulch.
2. Conditions requiring spillway discharge
from Davis Gulch dam will probably generate flood
conditions in all portions of the Parachute Creek
Basin, and these catchment dam discharges would be
insignificant in their effect on the aquatic ecosystem.
3. It is generally agreed that long-term
exposures to abnormally high concentrations of total
dissolved solids and other pollutants would be
required before plants and animals would begin to
show observable adverse effects. Spillway discharges,
if they occur at all. will not last for more than a brief
period of time.
SUMMARY
The Colony project on Parachute Creek is entering
the plant construction phase with proven process and
mining technology. Preservation of the environment
has been a prime consideration in the development
stages of this project and will contine to receive major
attention during commercialization.
REFERENCES
1. Paul D. Kilburn, Colony Development
Operation, 'The Environmental Analyses by a
New Energy-Producing Industry," American
Institute of Chemical Engineers 74th National
Meeting, Paper No. 6A, New Orleans, Louisiana,
March 11-15, 1973.
2. "An Environmental Impact Analysis for a Shale
Oil Complex at Parachute Creek, Colorado,"
submitted to the Bureau of Land Management
by Colony Development Operation, 1974.
194
-------
15 May 1974
Session IV:
FUEL UTILIZATION AND
TOTAL ENVIRONMENTAL ASSESSMENT
Paul Spaite
Session Chairman
195
-------
196
-------
OVERALL ENVIRONMENTAL CONSIDERATIONS
OF CONVERSION TECHNOLOGY
C. E. Jahnig, E. M. Magee,
and C. D. Kalfadelis*
Abstract
In view of the energy shortage, major efforts are
underway to make better use of our coal and shale
resources and to apply conversion technology to
upgrade fuels. This paper discusses environmental
considerations that result from the application of
conversion technology, describes the work underway
in this area, and gives some of the results to date.
Specific examples include:
(1) Cleanup and waste heat recovery on the raw
gas from gasification.
(2) Considerations on ash disposal, teachability,
and trace metals.
(3) Modifications in coal preparation and drying
to improve fuel efficiency, dust recovery,
and control of sulfur in the vent gas.
(4) The need for a coal-fired utility boiler and
alternatives available to control emissions
from it.
Objectives of the studies will be discussed as well as
the approach and methods used.
INTRODUCTION
A major effort is underway to make better use of
our coal and shale resources in order to alleviate the
energy shortage. This work -necessarily involves
conversion technology to upgrade these solid fuels to
gas or liquid fuels which will cause less pollution and
which will be easier to use. Environmental
considerations of the conversion process are discussed
below, together with some of the background on
objectives and approaches used in analyzing
environmental aspects of various processes.
A primary objective of this work, which is being
carried out under contract with the Environmental
Protection Agency,t is to recognize and point out
potential problems before the processes reach a
commercial stage, so that practical solutions can be
developed in a well-planned approach, rather than
waiting for the problem to reach a stage of urgency.
In analyzing various conversion processes, it also
becomes apparent that some areas are not yet
adequately defined and that further information, and
perhaps additional experimental work, is needed to
provide a suitable basis for evaluation. Some of the
problems are common to more than one conversion
process, such as-coal drying. In such cases, a
coordinated program can work out the solutions for
general use instead of each developer having to do all
of the work himself. One desirable objective,
therefore, is to define common problems that can
benefit from a coordinated effort.
ENVIRONMENTAL CONSIDERATIONS
Aspects of a process that may affect the
environment are listed in table 1. Each of these must
be examined carefully for every specific case.
Consideration of effluents to the air will include
sulfur and nitrogent oxides, hydrocarbons, odors
from phenols and ammonia, particulates, etc. Water
effluents may contain sulfur compounds, ammonia,
cyanides, phenols, oil, particulates, etc. Cleaning up
water for reuse so that there is no wastewater effluent
from the plant except for that used to slurry the ash
being disposed of is desirable and is generally
practical as well.
The ash may be returned to the mine or used for
landfill, which raises the question concerning
leachables such as calcium chloride, magnesium
sulfate, fluorides, etc. It is apparent that further
information is needed in this area.
Table 1. Environmental
considerations
•The authors are in the Government Research Laboratory
of Exxon Research and Engineering Company, Linden, New
Jersey.
tThis work was carried out under Contract No. 68-02-0629
with the Environmental Protection Agency.
Air effluents
Water effluents
Ash disposal
Trace elements
Water consumption
Thermal effluent
Odor and taste
Noise
Visual
Land use
197
-------
Trace elements are also part of this consideration
(ref. 1). Most of the heavy metals in the coal feed
remain with the ash during gasification or
liquefaction. However, some of the trace elements
volatilize to a moderate or large extent during
gasification. These elements probably do not remain
in the product gas but rather are rejected in some
other effluent stream. Therefore, we need to find out
about the composition and teachability to see if
corrective measures are needed. Of the various
elements so far designated as toxic, it is known that
all of them volatilize to a moderate or large extent
during gasification. They may then build up in the
recirculated water used to scrub the raw gas or
possibly interfere with the amine or other system
used to remove sulfur.
Water consumption is a growing concern, especially
at Western locations. The major consumption is
usually from evaporation in the cooling tower.
Reducing the cooling water requirement will
therefore cut the makeup water consumption.
Application of air-fin cooling can help, together with
heat exchange between streams to increase thermal
efficiency.
Thermal efficiency is important in that essentially
all of the unrecovered heat is taken up by air or water
in the environment. It also reflects how much raw
material is consumed in making a given amount of
clean fuel.
OBJECTIVES AND APPROACH
In analyzing a process from the environmental
standpoint, the objectives and approach that we have
used are shown in table 2. First, all streams entering
and leaving the plant are carefully defined, insofar as
possible, as to amount and composition. For many of
the streams, exact information is not available and
reasonable assumptions have to be made. Also, the
entire heat balance is worked out thoroughly to
determine the overall thermal efficiency of the
process, to see where the major losses are, and to
determine where potential improvement may be
possible. The major pollution problems are then
pinpointed. The next step is to see to what extent
these can be alleviated or eliminated by simple
engineering-type modifications—for example,
recycling wastewater rather than discharging it to a
river. Where the problem cannot be avoided,
additional control facilities are added, as in the case
of coal drying where bag filters, a scrubber, or
electrostatic precipitator may be needed to control
dust.
Table 2. Objectives
(1) Define all streams in and out--
amount, composition, and energy
balance.
(2) Add pollution control facili-
ties as needed, indicate alter-
natives.
(3) Point out simple modifications
and potential improvements to
decrease emissions or increase
efficiency.
(4) Identify areas where specific
additional information is
needed well before commercial
use.
(5) Determine technology needs for
pollution abatement.
One specific objective of analysis is to point out
where further work is necessary or desirable to
resolve environmental questions, or where significant
improvements in the operation may be possible.
Some of these will be described later in this paper,
and in a subsequent paper (ref. 2). Of particular
interest are areas that are common to more than one
process, such as coal preparation, storage, drying, and
grinding.
The system for cleaning up the raw gas from coal
gasification has common features for most of the
processes as outlined in table 3. High-energy water
scrubbing is generally needed to remove dust. This
necessarily means that the gas has been cooled to the
water dewpomt. It is important to recover as much of
this heat as possible in order to minimize the amount
of heat taken out by air-fins or cooling water. The
scrubber water will pick up large amounts of
hydrogen sulfide and ammonia. Techniques are
available for sour water stripping in order to produce
separate streams of hydrogen sulfide and ammonia
that are relatively pure. Ammonia may constitute a
byproduct for sale while hydrogen sulfide can go to
the sulfur recovery plant.
Some processes also produce significant amounts of
tar, naphtha, cresols, phenol, etc., in which case they
will have to be recovered effectively. They might be
sold, burned as fuel, or recycled to the conversion
process. Cleanup of the water layer will involve most
of the steps indicated on the slide, depending on what
198
-------
Table 3. Typical raw gas cleanup
Cooling: Steam, C.W., Air-fins
Dust Removal: Scrub, Bags, Elect.
Precip.
Tar, Oil, Naphtha
Phenols, Cresols, etc.
NH3, CN, SCN, Compounds
H2S, COS, Mercaptan, Thiophene
Other: Carbonyls, Arsine, Fluoride
Water Layer: Strip, Extraction,
Biox, Filter, Activated Car-
bon, Sludge Incin. (Chemical
Additions).
materials are present and on how the water is
disposed of.
EMISSIONS CONTROL
A single sulfur removal system that would take out
all forms of sulfur present in the raw gas would be
desirable, but such a system is not available today.
Characteristics of sulfur removal techniques are
shown in table 4. H2S is readily removed, but not
carbonyl sulfide, carbon disulfide, or thiophene.
Moreover, the usual amine scrubbing systems take out
much of the carbon dioxide present along with H2S
Unfortunately, this gives a low concentration of H2S
going to the sulfur recovery plant; where a Claus
Plant is used, it results in lower sulfur recovery and
higher cost. Hot carbonate will remove much of the
carbonyl sulfide but is limited in that it also takes out
much of the carbon dioxide, resulting in a low
concentration of H2S going to the sulfur recovery
plant.
Various processes are available for cleaning up tail
gas from a Claus unit including the Beavon, Clean-Air,
SCOT, IFP. and Wellman-Lord (ref. 3}. The first three
of these depend on reducing sulfur compounds to
H2S which is then removed. IFP uses a liquid phase
Claus-type reaction but does not remove carbonyl
sulfide or carbon disulfide. Wellman-Lord uses a
sulfite solution to scrub out S03, thus making
sulfuric acid as a byproduct.
Consideration should also be given in gas cleanup to
using one of the absorption/oxidation type of
processes as offered by Stretford, IFP, Tackahax, and
others. These make sulfur directly and can reduce
H2S to a very low level even in the presence of
considerable CO2, but they do not remove carbonyl
sulfide.
Many gasification processes generate other chemical
compounds such as phenol, cyanides, and tars.
Although these should be removed in the gas cleanup
section, some may remain and interfere with the
operation of the other parts of the process. For
example, cyanides interfere with the Stretford-type
sulfur removal, while in the case of amines,
thiocyanates will accumulate and have to be purged.
There is a universal need for plant utilities.
Generally, a power plant is included to make high
pressure steam either for the process or for generating
electric power. Using purchased power does not avoid
this question but only transfers it to a different area.
Utilities are a large fuel consumer. They often
consume 15 to 25 percent of the total coal used by a
process. If the fuel fired to this utility boiler is
high-quality product gas, then it reduces thermal
efficiency and is expensive. However, gas may be used
to the extent needed to control sulfur emission. One
route is to make low-Btu fuel gas in a separate
gasification system using air instead of oxygen. An
alternative to consider carefully is burning coal or
char in this utility boiler and adding stack gas cleanup
to control sulfur and dust emission. For those
processes which necessarily produce byproduct char,
this may be the only alternative to gasifying the char.
A number of commercial processes are offered for
stack gas cleanup and it becomes a choice for the
particular application as to what system is actually
used.
Comparisons are needed between the emission
Table 4. Sulfur recovery
MEA - High H?S capacity, also re-
moves C02, not COS.
Higher Amines - More selective H2S
vs. C02 but low capac.
Carbonates - Remove COS but low
selective H2S vs. C02.
Claus Plant - Inefficient if less
than 20-25% H2S in feed.
Absorp./Oxid. - Selective for H2S,
not good on COS.
Sulfur Guard - Need reheat to 600°F.
199
-------
Table 5. Emission standards
Fuel
Gas
Liquid
Solid
Dust
0.1
0.1
0.1
Ib/MM Btu
S02
__
0.8
1.2
N02
0.2
0.3
0.7
Water:
Current - all cyanides, compounds of
Hg. Cd.
Potential - As, Se, Cr, Zn, Pb, Be,
Ni, Sb.
standards and actual plant effluents, many of which
are not completely defined at this time. Some of the
standards are shown in table 5. The upper part applies
to large stationary power plants firing various fuels.
The lower part of the table indicates some of the
water contaminants that now have limits and others
for which emission standards may be expected in the
future.
ALTERNATIVES TO CONSIDER
Examples of some engineering-type modifications
and improvements will now be given. Some of these
examples are shown in table 6.
One alternative is in the type of coal-drying. It is
common to operate a coal dryer with a large amount
of excess air such that the oxygen level is around 10
to 11 percent. This makes for efficient drying in that
the gas volume is very large so that the evaporated
moisture contributes less to the humidity level.
However, it also means that a large volume of gas
must be handled and cleaned up. Serious
consideration should be given to reducing the gas
volume as much as possible and allowing its moisture
Table 6.
Examples of alternatives to be con-
sidered:
(1) Type of coal-drying
(2) Type of fuel to coal dryer
(3) Hydrogen production
content to increase. While this will tend to make the
drying less efficient, it may not be an overriding
factor in that the coal will eventually be neated to
much higher temperatures which will drive off any
residual moisture. In fact, the trend appears to be to
preheating the coal to higher temperatures, such as
500°F, so as to reduce the heat load in gasification or
liquefaction, but not to drive off volatiles in the
drying or preheating operation. In effect, what is
proposed is simply to run the coal dryer firing
minimum practical excess air. This will reduce the gas
volume and also increase the fuel efficiency. Whereas
a typical fuel efficiency in drying may be 60 percent,
it then becomes possible to achieve 80 percent fuel
efficiency. This is no small item since the amount of
fuel used in the coal preparation may be 10 percent
of the total coal input. For the operation at low
excess air, it may become very desirable to recover
water from the dryer vent gas in order to reduce the
overall water consumption of the process. Again, this
is a significant item in that with western lignite of say
33 percent moisture content the water recovered
could cut in half the overall makeup water required.
Another place where alternatives must be
considered as in the fuel to be fired in the coal dryer.
This could be high quality gas to give minimum sulfur
emission. It is more efficient to burn coal in the
dryer, and where this is done it can add about 1
percent to thermal efficiency. Some processes cannot
use the fines produced in grinding so a convenient
place to use them efficiently is in the coal dryer. For
sulfur control, part of the fuel may be low sulfur,
low-Btu gas drawn off before methanation. Vent gas
from the dryer must be cleaned up to remove dust or
coal fines, so it is possible that sulfur control might
be included in the dust removal system, particularly if
it involves scrubbing. One possibility is the addition
of limestone to the scrubber water. This of course
will depend on the amount of dust reaching the
scrubber, its combustible content, and whether it
needs to be reused.
In many conversion processes, hydrogen
manufacture is required to supply hydrogen for coal
conversion or for product treating. The hydrogen
might be made by gasification of char or heavy
liquids. In the case of coal liquefaction there may be
sufficient byproduct hydrocarbon gas to provide
hydrogen by conventional steam reforming of the gas.
In any event these operations must be included in the
overall balances.
As has been pointed out. the utilities system and
coal preparation are both major factors in the
200
-------
environmental aspects of a process. They are common
to a large number of conversion processes and it is
desirable to define simple alternative systems that can
use coal as fuel and still provide adequate
environmental controls.
STATUS OF WORK
The status of our work at the present time is that
detailed analyses of a number of coal gasification
processes have been made. One of these has been
published (ref. 4). Others will be published shortly.
Several other analyses are underway, including
retorting and liquefaction processes. Other studies
will be made as needed, for example, on retorting oil
shale and on liquid hydrocarbon gasification. These
will provide a framework to use in accessing the
environmental impact of various conversion processes
to upgrade fossil fuels.
REFERENCES
1. H. J. Hall, G. M. Varga, and E. M. Magee, 'Trace
Elements and Potential Toxic Effects in Fossil
Symposium.
2. E. M. Magee and H. Shaw. 'Technology Needs
for Pollution Abatement in Fossil Fuel
Conversion Processes,"This Symposium.
3. W. 0. Beers, "Characterization of Claus Plant
Emissions," EPA Report No. EPA-R2-73-188.
April 1973.
4. E. M. Magee, C. E. Jahnig, and H. Shaw.
"Evaluation of Pollution Control in Fossil Fuel
Conversion Processes • Gasification, Section 1.
Koppers-Totzek Process," EPA Report No.
EPA-650/2-74-009a, January 1974.
201
-------
202
-------
WEIGHING ENVIRONMENTAL COSTS AND BENEFITS
E. H. Hall, R. H. Cherry, Jr., and
G. R. Smithson, Jr.*
Abstract
A methodology has been developed to assess the
environmental factors related to a selected number of
fuel/energy systems. This methodology involves the
compilation and organization of effluent data, the
evaluation of the combined effects of extraction,
transportation, processing, and utilization of fuel to
produce energy. It also provides a technique for
ranking the fuel/energy systems from an
environmental standpoint. The principal objective in
the development of the methodology was to provide
a basis for making judgments regarding economic and
environmental tradeoffs.
The utilization of this methodology has led to the
conclusion that air emissions associated with coal
utilization can be decreased to approximately the
equivalent of those being emitted from systems using
natural gas. However, there is an attendant increase in
the environmental burdens imposed on the water and
land media. This improvement can be accomplished
through the use of the advanced control technology
expected to be available during the early part of the
1975-1990 time period. Later in that period,
additional technological advances will lead to
procedures and systems for minimizing the burdens
imposed on the water and land media by the
utilization of coal.
INTRODUCTION
The desire to obtain the benefits of pollution
control is reflected in the establishment of laws,
programs, and policies designed to improve the
quality of the environment by controlling emissions
at the expense of economic impacts upon society. It
is not easy to estimate the benefits which may derive
from these expenditures, although estimates based
upon the data available and on certain assumptions
are available.
The fact that certain benefits have not been
quantified or valued in economic terms does not
The authors are with the Battelle Columbus Laboratories,
Columbus, Ohio; E. H. Hall is Associate Manager, Energy
Systems and Economics Section, R. H. Cherry, Jr., is
Manager, Applied Metallurgy Section; and G. R Smithson is
Assistant Manager, Energy /Environmental Programs Office.
mean that these benefits are unimportant. On the
contrary, this importance is revealed by the fact that
most of the goals usually stated tend to deal with
benefits that are typically not measured. All benefits
(both measured and unmeasured) must be considered
in any decision, when analysis involves comparing the
costs of proposed actions with desired or expected
benefits.
A formal procedure for assessing the tradeoff
between benefits to society and costs does not exist.
Currently such tradeoff analysis is done on a
judgment basis, often in the political arena.
The benefits of pollution abatement are obtained in
two ways. One is to reduce the existing pollution
level to some target level by controlling emissions to
reduce the level of pollution costs. The second way is
to prevent pollution levels from becoming worse in
order to avoid incurring additional pollution costs. In
evaluating the effectiveness of current or proposed
programs, the abatement costs should be compared to
the sum of the reduced pollution costs and the
avoided pollution costs.
In order to understand better the benefits of
pollution control, it may help to distinguish among
three types of costs: (1) damage costs, (2) psychic
costs, and (3) avoidance costs. The psychic costs
imposed by pollution are distinguished from damage
and avoidance costs in that no out-of-pocket expenses
are involved; people simply tolerate:
(1) the mental discomfort or anguish persons
feel because they perceive a threat in
pollution becoming worse;
(2) the discomfort resulting from direct
exposure to the pollutants like smarting eyes.
shortness of breath, and physical weakness;
(3) the toss in pleasure because there is reduced
sunlight, restricted visibility, increased
discoloration of buildings, and damaged or
discolored vegetation;
(4) the mental discomfort or anguish that some
persons feel because they believe nature is
being assaulted and the esthetic quality of
life is being degraded.
When empirical estimates of pollution costs are made.
it is not always possible to identify which categories
of pollution costs are being measured. For example,
property value estimates may include some of all
three kinds of pollution costs.
203
-------
Methods of Assessing Pollution Costs
What are the methods that can be used to measure
society's willingness to pay for improved air quality7
There are six basic methods that can be used: (1)
valuing physical (dose-response) relationships; (2)
market studies; (3) opinion surveys of air pollution
sufferers; (4) litigation surveys; (5) political
expressions of social choice, (6) the delphi method.
Each method has been used under different
circumstances with varying degrees of success.
The most widely used technique is that of
determining a physical (dose-response) relationship
between a pollutant and an object or living thing.
These relationships are determined either by designed
experiments or by analysis of many observations of
natural events. The physical relationship is then
transformed into economic terms by determining
values for the effects. The aggregate or national
damage estimate is obtained by determining the
population exposed to various levels of the pollutant.
In the market study approach, pollution damages
are judged on the basis of human behavior as
reflected in specified markets. This approach
completely circumvents the need to know the
physical or biological damage function. If people are
willing to pay to avoid the effects of pollution, then
property values and local environmental quality will
vary inversely. A significant problem in using the
market study approach is that all the factors that
explain consumer preferences and behavior must be
included in the analysis.
The use of the opinion survey is closest to the
classical economic approach in that it focuses on
estimating utility and demand functions. Investigators
employing this method have attempted to ascertain
what people do and do not perceive as pollution
effect Opinion surveys have shown particular
usefulness in understanding how attitudes about air
pollution are formed and then affected by changes in
air quality.
Litigation surveys could be used to determine the
extent to which people have turned to the courts for
redress for pollution damages; the use of this method
is limited.
An investigator may try to gauge political
expressions, representations, and exhortations in the
hope that their intensity somehow corresponds to the
intensity of preference for one outcome over another.
In the delphi method, the knowledge and abilities
of a diverse group of experts are pooled for the task
of quantifying variables which are either intangible or
shrouded in uncertainty. The use of this method
provides an efficient way to obtain best judgments
from the knowledge and opinions of experts, even
though these judgments and decisions may be
essentially subjective. This approach may be
broadened to include actual technical estimates.
Of these methods, valuing dose-response
relationships, and a particular market study
application—called the property value method—have
yielded the most promising insights into the true
nature of air pollution damages. With effective
abatement, these damages become the benefits of
control. Yet, even the application of these methods
has been fraught with many problems. It is difficult
to allocate the observed damages among a number of
synergistically interacting multiple stresses to the
environment. The damages themselves cannot be
easily measured and reduced to economic terms.
An Example: Air Pollution Cost Estimates
The benefit to be expected from controlling air
pollutant emissions to meet the established or
assumed ambient air quality standard should only be
compared to the increment of abatement costs
incurred to reduce pollution to this level. In table 1
are presented estimates of the reduction in some of
the pollution costs that could result from reducing
the 1970 level of certain air pollutants to meet the
current standards. Not all of the costs have been
estimated; for example, the damages to animals and
the natural environment have not been obtained. This
does not imply that such pollution costs do not exist,
but only that there is not enough information to
make an estimate. The wide range of these estimates
implies that little confidence can be placed on the
best estimate.
The estimate of esthetic and soiling costs was
obtained from a study of property values which
provided a measure of the psychic costs, damage
costs, and avoidance (including adjustment) costs that
people suffer because of sulfur oxides and
particulates. This value was obtained from original
study values by adjustment to avoid the double
counting of health and materials damage effects.
The estimates for health costs measure the value of
damages resulting from air pollution effects-reduced
productivity because of ill health or premature death,
and out-of-pocket health care expenses. Data
concerning the effects of oxidants (primarily
hydrocarbons and oxides of nitrogen) and of carbon
monoxide did not allow for the estimation of the
value of damages by these pollutants. Psychic and
avoidance costs are also omitted from these health
estimates.
The materials estimates measure the value of
204
-------
Table 1. National Estimates of Air Pollution Costs, by Pollutant and Effect, 1970
($ billion)
01
Ff frcr*
Aesthetics & Sollingb'C
Human Health
Materials0
Vegetation
Animals
Natural Environment
Total
Also measures losses
Sulfur Oxides Partlculatcs Oxlclants
Low IHr.h Bont Low HlRh Bf^t Low Hir.n Host
1.7 4.1 2.9 1.7 4.1 2.9 7 7 ,7
0.7 3.1 1.9 0.9 4.5 2.7 777
0.4 0.8 0.6 0.1 0.3 0.2 0.5 1.3 0.9
* * * * * * 0.1 0.3 0.2
777 777 77?
777 777 777
2.8 8.0 5.4 2.7 8.9 5.8 0.6 1.6 1/1
attributable to oxides of nitrogen
Carbon
Monoxide
Bout
*
7
*
*
*
7
7
Total
Low HfRh Br*t
3.4 8.4 5.8
1.6 7.6 4.6
1.0 2.4 1.7
0.1 0.3 0.2
77?
777
6.1 18.5 12.3
Property value estimator
Adjusted to minimize
Unknown
Probably negligible
double -count Ing
Sources: Waddell, Thomas E., "The Economic Damages of Air Pollution: Unpublished Report, EPA National
Environmental Research Center, Research Triangle Park, March, 1974.
-------
damages and some of the avoidance costs resulting
from air pollution damage to manmade materials. It is
impossible to say what portion of avoidance costs are
accounted for. Estimates of the value of air pollution
effects on plants mostly represent the direct damages
and generally ignore the avoidance costs and psychic
costs.
The damage to animals caused by air pollution has
generally been localized, and its economic
consequences have probably been relatively
unimportant. Little is known about the effects of air
pollution on domestic animals and wildlife. Also.
little is known about how these problems interface
with the natural environment.
The natural environment category includes the
pollution costs of: disruption or destruction of
ecological systems, the destruction of species, the
disruption of social systems or social patterns, and
the disruption of a man-nature balance. Many of
these pollution costs affect man as psychic cost,
particularly fear of man's inadvertently destroying
life on earth. Because they are mostly psychic costs,
there is great difficulty in quantifying them, and no
estimates are yet available.
The Cost/Benefit Comparison
It is desirable for any control program, policy, or
action, that the benefits of reduced pollution costs be
greater than the abatement costs; otherwise society
will be made worse off. In fact, it is very difficult to
obtain accurate enough cost and benefit values for a
given program, policy, or action to make an accurate
determination of the value of the action to society.
The available data do not provide an adequate basis
for accurate comparison of the cost and the benefit.
A comparison of national costs and benefits would
not be sufficient to judge the merit of pollution
control programs for individual regions of the
country or for individual pollutants.
FOSSIL-FUEL ENERGY SYSTEMS
The attempts to assess the costs and benefits of
pollution control and the difficulties encountered
have been described in the preceding sections of this
paper. An alternate and perhaps simpler approach is
to analyze the various systems which can be used in
the generation of a product required by society and
to attempt to determine which system imposes the
least burden on the environmental media. An
example of such an analysis is a study which
Battelle-Columbus conducted for the Environmental
Protection Agency a little more than a year ago. This
was done in order to provide a basis for
recommending environmentally preferred energy
policy initiatives which may be required to meet
future energy demands. The overall objective of
Battelle's efforts was to provide EPA with the
necessary information regarding the environmental
emissions of alternative energy cycles so as to permit
explicit judgments regarding economic and
environmental tradeoffs. This will permit the
formulation and execution of sound policy in this
critical area.
The first task was concerned with a projection of
the environmental burden of baseline fuel-supply
projections during the period of 1975 to 1990. This
effort was based on a comparative analysis of
published long-term fuel supply and demand
projections. This was accomplished for both existing
and developmental technologies involved in the
various segments of the energy systems. Task 1 thus
included the identification and quantification of the
environmental emissions of alternative fuel supplies
commercially available in the 1975 to 1990 time
period. The sources of energy under consideration in
this portion of the study included coal, oil, natural
gas, and nuclear fission. Because of the short time
available for this study, the impacts were quantified
in terms of effluent quantities but not in terms of
effluent effects. It further was specified that the
utilization segment of the energy cycle would be
concerned only with the generation of electrical
power and with space heating.
The second task included a quantification to the
maximum extent possible of the effectiveness and
economic costs of pollution control for each
alternative energy supply and technology considered
in Task 1. These were considered in terms of common
indices to permit comparison of alternatives.
Wherever possible, pollution control was considered
as that necessary to achieve existing standards or new
standards which are anticipated as a result of Federal
or environmental legislation. Alternatively, pollution
control would apply the "best available" technology.
The third task was the ranking of all alternative
energy supplies and technologies from best to worst,
so far as environmental burden is concerned. The
environmental effects of each phase of the energy
cycle were considered, and separate rankings made
for the commercially available energy supplies and for
the development technologies.
For each of the tasks, the information analyzed by
Battelle was drawn from published literature, from
experience of Battelle staff members in various fields,
and from members of the EPA staff.
206
-------
The very broad scope of the subject and the short
time available for the preliminary study limited the
effort to an overview. A data base of environmental
emissions was compiled from readily available
information, and a preliminary methodology was
developed for ranking the fuel/energy systems on the
basis of environmental burden. These elements are
extant and can serve as a framework for more
detailed analysis and for the addition of new data on
emissions and technologies as it is developed, if the
program is extended and expanded.
For purposes of this symposium, only the fossil
fuel segment of the electrical energy industry will be
considered in detail. However, nuclear energy systems
will be included in the overall ranking.
It is anticipated that in the time period of concern
to the study-1972 to 1990- fossil fuels will
continue to be the dominant source of energy in the
United States. For this reason, considerable attention
has been given to the analysis of the many and varied
energy systems currently in use or under development
which utilize fossil fuels.
The complexity of the environmental factors
associated with the utilization of fossil fuels requires
that the environmental impact of alternative energy
sources must be analyzed for the entire energy system
from extraction through utilization. This, in turn,
requires a systematic approach which will
accommodate the large number of variables involved
and which will result in an evaluation of energy
systems which reflects all of the variables. The
modular approach chosen for this study permits such
a systematic evaluation. Because of the limitations in
the data base, the environmental impact of each
module has been evaluated on the basis of emissions.
but not in terms of effects, as ultimately should be
done to permit development of a more meaningful
ranking methodology.
Modular Approach
The pathways by which various fossil fuels are
utilized or processed and converted to other forms of
energy are many and varied. In order to assess the
efficiency of energy utilization and the environmental
burden for the various optional energy systems which
utilize fossil fuels, a modular approach has been used.
In general, the modules, defined as a distinct phase in
a fuel/energy system, fall within one of the five
categories: the extraction or procurement of the fuel
from its source, the processing of the fuel, the
conversion of the fuel to a different form of energy,
the transportation, or the utilization of the fuel. This
approach allows ready identification of those phases
of the fuel/energy system which contribute a major
share of the environmental burden. It also provides a
data base for extensive analysis of a large number of
possible system options. A list of the important
modules to be considered is given in table 2.
A very large number of possible pathways from the
extraction of a fuel to utilization of the fuel exist. A
conceptual view of the modular relationships of
importance are presented for coal, oil, and gas in
figures 1 through 5. From these diagrams, a list of
systems composed of from two to five modules was
constructed and is presented in table 3. The list does
not represent all possible combinations of modules
but rather those considered to be of major
importance.
Fifty selected modules were analyzed for energy
efficiency and environmental burden during the
course of the first segment of the study. A list of
these modules is given in table 4.
System Description and Assessment
The modules described in the foregoing section
were used as building blocks for the various potential
energy systems. In the study of electric power
generation systems, 15 selected coal systems. 2
mixed-fuel (coal and municipal refuse) systems, 6 oil
systems, and 2 gas systems have been described and
analyzed. These include the important options open
to the Nation for meeting the projected energy
deficit. In addition, 5 systems have been analyzed in
which the end use of the energy is space heating. The
overall environmental burden for each energy system
has been obtained through the summation of the
estimated environmental burden for each module
making up the system, and modified by the efficiency
of energy utilization for these modules. Weighting
factors were applied to permit a summation of
burdens.
In addition to the summation of environmental
burdens, costs of energy conversion for each of the
systems were estimated so that the systems could be
compared economically, as well as environmentally.
The cost of pollution control for specific modules has
been developed for those modules for which this
information is available.* In addition, the overall cost
of energy production has been derived for each
system.
•Report referred to in "Acknowledgment" at end of this
paper.
207
-------
Table 2. Modules of Significance in the Analysis
of Environmental Impacts
Gas Extraction, Processing,
Transportation, and Utilization Options
EXTRACTION AND CLEANING
Gas Extraction and Cleaning/Continental (North American Exclusive of
Arctic Regions)
Gas Extraction and Cleaning/Off-Shore STORAGE
Gas Extraction and Cleaning/Arctic Storage/Domestic
Gas Extraction and Cleaning/Overseas Storage/Tanker
TRANSPORT
Gas Pipeline (Conventional)
Gas Pipeline (Arctic)
Cryogenic Tanker
UTILIZATION
Conventional Boiler
Combined Cycle
Space Heating
Oil Extraction, Conversion,
Secondary Processing, Transportation,
and Utilization Options
EXTRACTION
Oil-Gas Well/Continental
Oil-Gas Well/Off-Shore
Oil-Gas Well/Overseas
TRANSPORT OF CRUDE
Oil Pipeline (Conventional)
Oil Pipeline (Arctic)
Tanker
CONVERSION OF CRUDE
U. S. Refinery
Topping Operations (Overseas)
Topping Operations (Domestic)
PROCESSING OF FRACTIONS
Residual Desulfunzacion
Naphtha No. 2 Fuel Production
Heavy Oil Gasification
Light Oil Gasification
Blending Fuel Oil
TRANSPORT OF PRODUCTS
Barge
Tanker
Pipeline
UTILIZATION
Conventional Boiler
Conventional Boiler/Flue Gaa Cleaning
Combined Cycle
Fluid Bed Combustor
Space Heating
Coal Extraction, Processing,
Transportation, and Utilization Options
EXTRACTION
Surface Mine (Eastern Coal)
Surface Mine (Western Coal)
Underground Mine (Eastern Coal)
TRANSPORT OPTIONS (Before Processing)
Rail
Barge
TREATMENT OR CONVERSION PROCESSES
Physical Coal Cleaning
Chemical Leaching
Solvent Refining
Gasification (Low Btu)
Gasification (High Btu)
TRANSPORT OPTION (After Processing)
Rail
Barge
Coal Slurry Pipeline
Gas Pipeline
UTILIZATION PROCESSES
Conventional Boilers
Combined Cycle
Fluid Bed Combustor
Conventional Boiler/Flue Gaa Cleaning
Space Heating
208
-------
Conventional
Boiler/
Flue Gas Clng
Physical
Coal
Cleaning
Fluid Bed
Combuscor
Chemical
Leaching
ndergroun
Mine
Solvent
Refining/ None
Conventional
Boiler
Combined
Cycle
/Gasification
(Low Btu)
Figure 1. Schematic Representation of Modular Relationships--
High Sulfur Eastern Coal
209
-------
Conventional Boiler
Lone Transmission
Surface
Mine
Conventional
Boiler
Gasification
(Low Btu)
Combined
Cycle
Gasification
(High Btu)
Space
Heating
Figure 2. Schematic Representation of Modular
Relationships — Low Sulfur Western Coal
210
-------
Flue Gas
Cleaning
Oil/Gas Well
(Continental)
Fluid Bed
Combustio
Crude Pipeline
Oil/Gas Well
(Offshore)
U.S. Refinery
Space
• Heating
(Terminal)
Naphtha, No. 2
Fuel Production
No. 2, Naphtha
Pipeline,
Barge, Tanker
Oil/Gas Well
(Foreign)
Res id.
Deaulfurization
Conventional
Lo S Resid.
Barge, Tanker
Figure 3. Schematic Representation of Modular Relationships -- Oil
-------
Table 3. Summary of the More Important Systems Options
Extraction
Process
(1) Surface Mine
(2) (Eastern Coal)
(3) Surface Mine
(Eastern Coal)
(4) Surface Mine
(Eastern Coal)
(5) Surface Mine
(6) (Eastern Coal)
(7)
(8) Surface Nine
(9) (Eastern Coal)
(10)
(11) Surface Mine
(12) (Eastern Coal)
(13)
(14) Surface Mine
(IS) (Eastern Coal)
(16)
(17) Surface Mine
(18) (Eastern Coal)
(19)
Transport
Hone
Hone
Hone
Rail, Barge.
None
Rail. Barge.
None
Rail. Barge.
None
Rail. Barge,
None
Rail. Barge.
None
(20) through (38) Repeat above options
(39) Surface Mine
(Western Coal)
(40) Surface Mine
(Western Coal)
(41) Surface Mine
(Western Coal)
(42) Surface Mine
(Western Coal)
(1) Gas Well
(2) (Continental)
0)
(4) Gas Well
(5) (Offshore U.S)
(«)
(7) Gas Well
(8) (Arctic)
W)
(10) Gas Well
(11) (Overseas)
(12)
None
Rail
Rone
Rail
Rone
Hone
Hone
Hone
Processing of Secondary
Raw Fuel Processing
Fuel/Energy Svstcms - Coal
Physical Coal None
Cleaning
Chemical None
Lrachlng
Solvent None
Refining
Gasify None
(Low Btu)
Cas 1 f y None
(Low Btu)
Gasify None
(High Btu)
None None
None None
Transport
& Storage
Rail. Barge
Slurry
Pipeline
None
None
None
Pipeline
Gas
None
None
Utilization
Conventional
Boiler
Conventional
Boiler
Conventional
Boiler
Conventional
Boiler
Combined
Cycle
Space
Heating
Conv. Boiler
vith Flue Cas
Cleaning
Fluid Bed
Combustion
System
with underground mined Eastern Coal
None None
None None
Cas 1 f y None
(High Btu)
Gasify None
(Low Ecu)
Fuel/Energy Systems - Gas
Desulfurlzatlon None
Desulfurlzatlon None
Desulfurlzatlon None
Desulfurlzatlon Nope
None
None
Pipeline
Gas
None
Gas Pipeline
Gas Pipeline
Arctic Cos
Pipeline
Cryogenic
Tanker & Stg.
Conv. Boiler
& Long Disc.
Transmission
Conventional
Boiler
Space Keating
Conventional
Boiler
Conv. Boiler,
Space Heating,
Combined Cycle
Conv. Boiler,
Space Heating,
Combined Cycle
Conv. Boiler,
Space Heating,
Combined Cycle
Conv. Boiler
Space Heat Ing
Combined Cycle
212
-------
Table 3. (Continued)
Extract Ion
Process
(1) Oll/Cas Well
(2) (Continental)
(3) Oll/Cas Well
(4) (Offshore)
(i) Oll/Cas Well
(6) (Overseas)
(7) Oil/Gas Well
(Continental)
(8) (Offshore)
(9) Oil/Gas Well
(Foreign)
(10) Oll/Cas Well
(Continental)
(11) (Offshore)
(12) Oll/Cas Well
(Continental)
(13) (Offshore)
(14) Oll/Cas Well
(15) (Foreign)
(16) Oll/Cas Well
(17) (Foreign)
(18) Oll/Cas Well
(19) (Foreign)
(20) Oll/Cas Well
(Foreign)
(21) Oll/Cas Well
(22) (Foreign)
(23) Oll/Cas Well
(24) (Foreign)
(25) Oll/Cas Well
(26) (Foreign)
(27) Oll/Cas Well
(28) (Foreign)
(29) Oll/Cas Well
(30) (Foreign)
(31) Oll/Cas Well
(Foreign)
Trans port
Oil
Pipeline
Oil
Pipeline
Tanker
Oil
Pipeline
Tanker
Oil
Pipeline
Oil
Pipeline
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Processing of Secondary
Raw Fuel Processing
Fuel/Energy
U.S. Refinery
U.S. Refinery
U.S. Refinery
U.S. Refinery
U.S. Refinery
U.S. Refinery
U.S. Refinery
U.S. Refinery
Topping
Refinery
Topping
Be finery
Topping
Refinery
Topping
Refinery
Topping
Refinery
Topping
Be finery
Topping
Be finery
Topping
Refinery
Topping
Refinery
Systems - Oil
Res Id. Desulf.
Res id. Desulf.
Res Id. Desulf.
Ho. 2 Oil
No. 2 Oil
Res Id. Desulf.
Res id. Desulf.
Resld. Desulf.
No. 2 Oil
No. 2 Oil
Light Oil
Gasification
Naphtha
Production
Reald. Desulf.
Blend Ing
Hone - HI S
Resid.
Hone - HI S
Reald.
Heavy Oil
Gasification
Transport
& Storage
Barge, Tanker
Barge, Tanker
Barge, Tanker
Pipeline
Pipeline
Barge, Tanker
Barge, Tanker
Barge, Tanker
Barge, Tanker
Barge, Tanker
Gas
Pipeline
Barge, Tanker
Barge, Tanker
Barge, Tanker
Barge, Tanker
Barge, Tanker
Caa
Pipeline
Utilization
Convenclonal
Boiler
Convent iona 1
Boiler
Conventional
Boiler
Space Heating
Space Heating
Fluid Bed
Combustion
Conv. Boiler
with Flue Gas
Cleaning
Fluid Bed
Combustion
Space Heating
Combined Cycle
Space Beating
Combined Cycle
Conventional
Boiler
Convent iona 1
Boiler
Conv. & Flue
Gaa Cleaning
Fluid Bed
Combustor
Space Heating
213
-------
Table 3. (Continued)
Extraction
Process
(1) Oil/Gas Well
(2) (Continental)
(3) Oil/Gas Well
(4) (Offshore)
(5) Oil/Cas Well
(6) (Overseas)
(7) Oil/Cas Well
(Continental)
(8) (Offshore)
(9) Oil/Gas Well
(Foreign)
(10) Oil/Gas Well
(Continental)
(11) (Offshore)
(12) Oil/Gas Well
(Continental)
(13) (Offshore)
(14) Oil/Gas Well
(15) (Foreign)
(16) Oil/Gas Well
(17) (Foreign)
(IB) Oil/Gas Well
(19) (Foreign)
(20> Oll/Cai Well
(Foreign)
(21) Oil/Gas Well
(22) (Foreign)
(23) Oil/Gas Well
(24) (Foreign)
(25) Oil/Gas Well
(26) (Foreign)
(27) Oil/Gas Well
(28) (Foreign)
(29) Oil/Gas Well
(30) (Foreign)
(31) 011/Cas Well
(Foreign)
Transport
Oil
Pipeline
Oil
Pipeline
Tanker
Oil
Pipeline
Tanker
Oil
Pipeline
Oil
Pipeline
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Processing of
Raw Fuel
Secondary
Processing
Fuel/Knergy Systems - Oil
U.S. Refinery Res Id. Deiulf.
U.S. Refinery
U.S. Refinery
U.S. Refinery
U.S. Refinery
O.S. Refinery
D.S. Refinery
U.S. Refinery
Topping
Refinery
Topping
Be finery
Topping
Refinery
Topping
Refinery
Topping
Refine r»
Topping
Refinery
Topp Ing
Refinery
Topping
Refinery
Topping
Refinery
Resld. Desulf:
Resid. Desulf.
No. 2 Oil
No. 2 Oil
Resld. Desulf.
Res id. Desulf.
Resid. Desulf.
No. 2 Oil
No. 2 Oil
Light Oil
Gasification
Naphtha
Production
Resld. Desulf.
Blending
None - Hi S
Resld.
None - Hi S
Resld.
Heavy Oil
Gasification
Transport
fc Storage
Barge, Tanker
Barge, Tanker
Barge. Tanker
Pipeline
Pipeline
Barge, Tanker
Barge, Tanker
Barge, Tanker
Barge. Tanker
Barge, Tanker
Gas
Pipeline
Barge, Tanker
Barge, Tanker
Barge, Tanker
Barge, Tanker
Barge, Tanker
Gas
Pipeline
Utilization
Convent lone i
Boiler
Conventional
Boiler
Conventional
Boiler
Space Heating
Space Heating
Fluid Bed
Combustion
Conv. Boiler
with Flue Gas
Cleaning
Fluid Bed
Combustion
Space Heating
Combined Cycle
Space Heating
Combined Cycle
Conventional
Boiler
Conventional
Boiler
Conv. & Flue
Gas Cleaning
Fluid Bed
Coobustor
Space Heating
214
-------
Table 4. Selected Modules Analyzed
Strip Mining of Eastern Coal
Strip Mining of Western Coal
Deep Mining of Coal
Physical Cleaning of Coal
Chemical Cleaning of Coal
Liquefaction of Coal (Solvent Refining)
Rail Transport of Coal
Conventional Boiler, Eastern Coal
Conventional Boiler, Western Coal
Conventional Boiler, Physically Cleaned Eastern Coal
Conventional Boiler, Chemically Cleaned Eastern Coal
Conventional Boiler, Liquefied Coal
Conventional Boiler (Limestone Scrubber), Eastern Coal
Conventional Boiler (MgO Scrubber), Eastern Coal
Conventional Boiler (Limestone Scrubber), Western Coal
Conventional Boiler (Limestone Scrubber), Physically Clean Eastern Coal
Gasification (Low Btu) Eastern Coal - Lurgi
Gasification (High Btu) Eastern Coal - Hygas
Gasification (High Btu) Lignite - CO. Acceptor
Gasification (Low Btu) Eastern Coal - Molten Iron Combustion
Gasification of Crude Oil
High Pressure Fluidized Bed
Chemically Active Fluidized Bed
Gas Well
Gas Desulfurization
Gas Pipeline
Conventional Boiler, Natural Gas
Underground Gas Storage
LNG Tanker
LNG Port Facilities
LNG Storage
LNG Distribution
LNG Gasification
Oil Shale Extraction and Processing
Oil/Gas Well - On Shore
Oil/Gas Well - Off Shore
Oil Tanker Transport
Oil Pipeline
Oil Barge
Refinery - Domestic Crude
Refinery - Imported Crude
Topping Refinery
Conventional Boiler, Domestic Residual
Conventional Boiler, Topping Residual
Municipal Refuse Processing (St. Louis Method)
Municipal Refuse Burning, Conventional Boiler, Limestone Scrubber
Space Heating - Electrical, gas, oil, coal and synthetic gas from coal
Nuclear Fission
215
-------
Derivation of Emission Values
DATA ANALYSIS
The pollutant emissions resulting from the
operation involved within each module were derived
from various sources. These values were then reduced
to a common basis, namely, emission per million Btu.
This reference energy was taken as the heat value of
the primary fuel produced by the module, except in
the case of electric power generation, for which the
input energy to the power plant was taken as
reference. Thus, in general, the emissions are given in
pounds per million Btu. The land-use burden includes
the land area involved and a time factor. For the
processing and utilization modules, the proper unit
arises from the fact that a certain land area is
associated with a plant with a stated throughput, say
tons of coal per hour or the equivalent heating value
(Btu per hour). When the area in acres is divided by
this energy rate, the resulting units are acre-hour/106
Btu. For the extraction modules, the area is
associated with a total energy (e.g., tons of coal per
acre). The resulting burden in acres/106 Btu is
converted to consistent units by multiplying the
burden by the length of time assumed for the
operation.
Environmental Burden of Modules
The unit-basis pollutant emissions, land-use
burdens, and efficiencies for 50 modules were
compiled and analyzed. From this extensive data
base, a summary was prepared and is given in table 5.
The values are stated in pounds per million Btu for air
emissions of NOX, SO2, and particulates, for water
emissions of suspended solids and organic materials,
and for solid wastes produced. The land-use burden is
expressed in acre-hour per million Btu. Data are given
in table 5 for selected gas, oil, and coal modules
which include extraction, transportation, conversion
or treatment, and utilization.
The data presented in table 5 illustrate the
differences in burdens that exist among the various
modules. These burdens arise from the different steps
in the fuel-energy cycle, and the various components
of the environment can be affected. It is difficult to
evaluate alternative energy systems directly on the
basis of emissions data as presented in table 5.
Therefore, it was believed that it was desirable to
aggregate these complex emissions at various levels
and to compile them into a single number which will
Crude
Tanker
Barge. Tanker
Figure 4. Schematic Representation of Modular Relationships - Oil, Modified
2T6
-------
Gas
Extraction &
Cleaning
(Continental)
Space
Heating
Storage/Domestic
(Optional)
Gas
Extraction &
Cleaning
(Offshore)
Conventional
Boiler
Storage/Tanker
Gas
Extraction &
Cleaning
(Arctic)
Combined
Cycle
Gas
Extraction &
Cleaning
(Overseas)
Figure 5. Schematic Representation of Modular Relationships -- Gas
-------
Table 5. Summary of Principal Environmental Burdens
for Some Selected Modules
Air Emissions,
lb/106 Btu
Selected Modules
Extraction Modules
Scrip mining- Eastern
(E.) coal
Strip mining-Western
(W.) coal
Onshore oil well
Natural gas well
Transportation Modules
Rail-coal
Pipeline-oil
Pipeline-gas
Conversion or Treatment
Modules
Physical coal cleaning
Chemical coal cleaning
Solvent refining of coal
Refining of oil-domestic
crude
Natural gas desulfurlza-
tlon
Utilization Modules
Conventional boiler (CB)-
W. coal
C.B. vith limestone
scrubber (LSS)-W. coal
Fluid Izcd-bed combustion
plus combined cycle-
E. coal
Gasification (molten Iron
combustion}' plus C.B.-
E. coal
C.B. with MgO scrubber-
E. coal
C.B. -physically cleaned
E. coal
C.B. with LSS-physically
cleaned E. coal
C.B. -chemically cleaned
E. coal
C.B. -solvent refined
E. coal
Chemically active flui-
dlzed-bcd plus combined
residual oil
C.B. -residual oil from
domestic crude
C.B. -natural gas
NO,
0.0002
0.00008
-A
8 x 10 6
0.23
0.02
0.009
0.304
0.006
0.04
0.21
0.025
0
0.98
0.78
0.14
0.39
0.60
0.68
0.55
0.75
0.56
0.16
0.70
0.39
SO. Particulates
Neg
Neg
C
6 x 10
Neg
0.0014
0.016
0
0.004
0.1
0.003
0.135
0.0183
1.65
0.16
0.7
0.017
0.50
2.02
0.2
1.93
0.71
0.45
1.83
0.0006
0.14
0.07
-&
3 x 10
Neg
0.0014
0.002
0
0.01
0.005
0.27
0.002
0
0.07
0.07
0.02
0.034
0.1
0.044
0.044
0.1
0.0003
0.01
0.05
0.015
Water Emissions,
lb/106 Btu
Suspended
Solid
0.55
0.28
0
0
Neg
0
0
Neg
Neg
0
0.004
Neg
0.025
0.025
0
0
0.025
0.025
0.025
0.025
0.025
0
0
0.016
Organic
Neg
Neg
0.008
Neg
0
0
Neg
Neg
Neg
0.002
Neg
0.011
0.011
0
0
0.011
0.011
0.011
0.011
0.011
0
0
0
Solid Waste,
lb/106 Btu
Ash
0
0
0
0
0.083
0
0
0
0
16.
0
Reg
9.
Sludge
0.24
0
0
0
Neg
0
0
0.3
0
0
0.026
Neg
0
1.8 13.4
17.3
10.
2.4
5.4
1.1
11.9
0.031
3.0
0
0
0
0
10.4
0
11.9
0
0
0
0
0
Land Use,
acre-hour
per 10 Btu
0.3
0.16
0.06
0.06
0.29
0.3
1.0
0.003
0.08
0.08
0.009
0.005
0.1
M
0.1
0.12
0.12
0.1
0.1
0.1
0.1
0.09
0.06
0.04
0.02
218
-------
reflect all of the emissions, thus aiding in comparing
the environmer*al aspects of various energy systems.
A method for accomplishing the aggregation of
emissions, based upon methodology developed for
the Bureau of Reclamation, U.S. Department of the
Interior, was employed (ref. 1). The details of the
ranking methodology are presented in the Appendix.
During this brief study, no attempt was made to
detail the analysis on a regional basis. The results thus
represent a national overview which can be useful in
the evaluation of national priorities. Ultimate
implementation of energy policy should include
consideration of regional factors.
The first level of aggregation of the emission data is
the summation of the weighted parameters for each
environmental component within the module. The
resulting totals for the air, water, solid, and land-use
burdens are compiled for each module in table 6.
Since the actual emissions have been weighted in the
calculation of the totals given, units are not assigned
to the totals. Examination of table 6 shows the range
of values which occurs for a given type of burden.
Some general points regarding control technology
associated with the modules given in table 6 should
be noted:
• Mine modules assume land restoration (80
percent coverage, no bare areas greater than V*
acre, and 600 living stems per acre), and
treatment of acid mine drainage;
• Physical coal cleaning assumes restoration of land
used for refuse piles (all pyritic material covered
with nonreactive soil) and treatment of
acid-bearing runoff;
• Boiler modules assume 99 percent efficiency for
paniculate removal;
• Stack gas cleaning modules assume 90 percent
reduction in SO2 and 20 percent reduction in
NOX;
• Cooling towers are assumed for all modules
discharging heat in water effluents. The heat
discharged to air is not included in the burden
totals.
The compilation of table 6 also shows the
cross-media effects of alternate pollution control
approaches. For example. Modules 8 through 16 are
all conventional boilers burning several different
kinds of coal, either with or without stack-gas
cleaning. Comparison of Module 8 with Module 13
shows an 80 percent reduction in air burden when a
limestone scrubbing system is employed, with an
attendant increase in solid burden due to the gypsum
sludge produced. Module 14 shows the same
reduction in air burden, but it does not have the
increase in solid waste, since the MgO scrubber is a
regenerative system. Module 22, high-pressure
fluidized-bed combustion, also is a coal utilization
module which exhibits yet an even smaller air burden
with an intermediate solid impact.
Thus, table 6 can be used to compare alternative
processes on a burden-by-burden basis.
Environmental Burden of Systems
The second level of aggregation of the emission
data is the summation of the weighted totals for each
environmental component over all of the modules in
each chosen system. Again, weighting factors
reflecting the relative importance of each module are
employed in the summation. The result is a separate
total for air, water, solid waste, and land-use burdens
which reflect the individual contributions of all of the
burdens.
The final aggregation of the emission data is the
summation of the environmental component totals to
give a single-system environmental index. The results
obtained by this approach are described in the
following paragraphs. It should be noted that this is
simply one method of aggregating the complex
emission data, and the results are not a unique
representation of that data. The method includes the
flexibility to allow any system evaluator to select
weighting factors at each level of aggregation to
reflect his understanding of the relative importance of
each factor involved. The computer program readily
allows recalculation of the system environmental
indices on the basis of refined weighting factors.
During this short study, a group of 26 systems for
producing electric power and a group of 5 systems for
space heating were selected for analysis. The electric
power group included 15 coal, 2 mixed fuel (coal plus
municipal refuse), 6 oil, 1 nuclear fission, and 2
natural gas systems. These include the important
options which must be considered in arriving at an
energy policy. The group of space heating systems
include electricity, natural gas, oil, and coal.
Electric Power Systems
All of the systems which have been analyzed are
listed in table 7. For each electric power system and
appropriate modules, burdens given in table 6 were
employed to derive an overall system environmental
index. Since the module burdens are stated on a unit
basis, the efficiencies must be factored in. The
weighted sums in each module were first adjusted by
dividing each of the four values by the product of the
efficiencies of each module following it in the system
sequence. The impacts for electric-power-generation
219
-------
Table 6. Summary of Module Impacts
Module
Number
1
2
3
4
5
6
7
8
9
8 10
Impacts,
Weighted Sums (EWpQp) for Each Environmental Component
Module
Eastern Coal, Strip Mine
Western Coal, Strip Mine
Eastern Coal, Deep Mine
Physical Cleaning of Coal
Chemical Cleaning of Coal
Liquefaction of Coal (Solvent
Rail Transport of Coal
Conv. Boiler, Eastern Coal
Air
0.186
0.0933
0.0005
0.0218
0.212
Refining)0.222
0.0247
7.040
Conv. Boiler, Western Coal 3.150
Conv. Boiler, Physically Cleaned 3.338
Water
0.0038
0.0013
0.045
0
0
0
0
0.0039
0.0039
0.0039
Solid
0.240
0.040
9.60
0.06
0
16.0
0.083
12.0
9.0
5.41
Land Use
0.34
0.17
0.20
0.003
0.002
0.027
0.29
0.10
0.13
0.10
Eastern Coal
11 Conv. Boiler, Chemically Cleaned 4.215 0.0039 11.41 0.10
Eastern Coal
12 Conv. Boiler, Liquefied Coal 1.585 0.0039 0.074 0.09
13 Conv. Boiler, Limestone Scrubber, 1.396 0.0039 29.8 0.10
Eastern Coal
14 Conv. Boiler, MgO Scrubber, 1.394 0.0039 12.16 0.10
Eastern Coal
15 Conv. Boiler, Limestone Scrubber, 1.453 0.0039 21.05 0.10
Western Coal
16 Conv. Boiler, Limestone Scrubber, 0.922 0.0039 13.80 0.10
Physically Cleaned Eastern Coal
-------
Table 6. (Continued)
Module
Number
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
Impacts ,
Weighted Sums (EWpQp) for Each Environmental Component
Module
Gasification, Eastern Coal, Lurgi
(Low Btu) plus Conv. Boiler
Gasification, Eastern Coal, Hygas
(High Btu)
Gasification, Lignite, C0_ Acceptor
(High Btu)
Gasification, Eastern Coal, Molten
Iron Combustion (Low Btu) plus C. B.
Gasification of Crude Oil
High Pressure Fluid ized Bed plus C. C.
Chemically Active Fluidized Bed
plus C. C.
Natural Gas Well
Natural Gas Desulfurization
Gas Pipeline
Underground Gas Storage
Conv. Boiler, Natural Gas
LNG Tanker
LNG Port Facilities
LNG Storage
LNG Gasification
Oil Shale Extraction and Processing
Air
1.624
1.79
0.027
0.449
0.17
1.042
0.761
0.845
0.0229
0.304
0.60
0.446
0
0
0
0.0026
0.484
Water
0.0046
0.0023
0.0023
0
0.0002
0.
0
0.0031
0
0
0
0.0002
0
0
0
0
0.001
Solid
9.75
31.9
39.2
10.0
0.18
17.40
3.0
0
0
0
0
0
0
0
0
0
>400
Land Use
0.12
0.02
0.02
0.12
0.04
0.10
0.12
0.05
0.005
1.00
Neg.
0.02
0
Neg.
0.00005
O.OOOC4
N.D.
-------
Table 6. (Continued)
Module
Number
34
35
36
37
38
39
40
41
K 42
M
43
44
45
46
47
48
49
50
Module
Oil/Gas Well - On Shore
Oil/Gas Well - Off Shore
Oil Tanker Transport
Oil Pipeline
Oil Barge
Refinery, Domestic Crude
Refinery, Imported (Arabic) Crude
Topping Refinery
Conv. Boiler, Domestic Resid.
Conv. Boiler, Topping Resid.
Municipal Refuse Processing
(St. Louis Method)
Municipal Refuse Burning, Conv.
Boiler, Limestone Scrubbing
Space Heating, Electricity
Space Heating, Gas
Space Heating, Oil
Space Heating, Coal
Nuclear Fission
Weighted Sums
Air
0.00008
0.00016
0.1416
0.157
0.0143
0.214
0.225
0.155
3.161
1.811
0
0.717
0
0.572
1.13
10.5
0.0032
Impacts ,
(EWpQp) for Each Environmental Component
Water
0.0223
0.0023
0.0495
0.00495
0.00512
0.0068
0.0068
0.00425
0
0
0
0
0
0
0
0
0.022
Solid
0
0
0
0
0
0.026
0.026
0.026
0
0
0
-132.0
0
0
0
0
4.0
Land Use
0.05
0.05
0
0.31
0
0.009
0.009
0.009
0.04
0.04
0.034
0.1
0
0
0
0
0.3
-------
modules are stated on a unit input basis; therefore,
the efficiency factor is applied to those impacts as
Well, in order to put all systems on a common output
basis. The adjusted burdens of all modules in a given
system were then added to give total air. water, solid.
and land-use burdens. These totals are given for each
system in table 7. Again, the burden data in table 7
are useful in comparing the tradeoffs which are
involved in the consideration of various system
options.
The total air, water, solid, and land-use values were
normalized and then summed to give the overall
system environmental index. The systems are
arranged in ranked order in table 7 according to the
value of the derived system index.
Three additional elements are included in table 7;
the overall system efficiency (the product of the
efficiencies of each module in the system), the
estimated overall cost to produce electricity, and the
approximate year of availability of each system.
It should be emphasized that the system index as
given in table 7 was derived with equal weight being
given to the burdens from each module in the system
and also to the air, water, solid, and land-use burdens.
With these assumptions, three of the four systems
which include limestone scrubbing are ranked below
the corresponding system without scrubbing. This
occurs because the SO? and sludge produced (16 Ib
sludge per Ib of S02 removed) are given equal
environmental importance. In view of the fact that air
emissions are, in general, more likely to produce
adverse health effects than are solid wastes, it would
be reasonable to assign a lesser weight to solid waste
in the system analysis. Based on this premise, a
second calculation was carried out in which the solid
burdens were assigned a weighting factor of 0.3 while
keeping the remaining media weights equal to unity.
The results of this calculation are given in table 8 in
which the systems are ordered according to their
revised ranking. For comparison, the rank of each
system obtained previously with equal media weights
also is given. The revised order shows the expected
changes. Systems with relatively large solid burdens
moved up in rank. For example, the systems which
include limestone scrubbing are ranked above the
corresponding systems without scrubbing.
DISCUSSION OF THE RESULTS
Systems Relationships
Inspection of tables 7 and 8 reveals a number of
interesting features. A few of these may be noted as
illustrative of the comparisons which may be drawn:
• Natural gas and LNG systems predictably rank
high environmentally;
• Among the currently available systems, nuclear
fission, western coal, and imported oil-topping
refinery systems are highly ranked;
• MgO scrubbing systems and. given the
assumption of lesser weight for solid waste,
limestone scrubbing systems are favorably
ranked;
• Various coal cleaning and processing options
show significant environmental gains over the use
of untreated coal;
• The developmental technologies: chemically
active fluidized-bed combustion of oil, molten
iron gasification of coal, and high-pressure
fluidized-bed combustion of coal, are highly
promising from the environmental standpoint;
• Systems, including strip-mining of coal, are
environmentally acceptable if land restoration
and treatment of acid-mine drainage is practiced;
• The oil systems are intermediate in rank due to
higher than average air and water emissions.
One of the most striking results is the high ranking
of the coal-municipal refuse, mixed-fuel systems. This
option is highly promising from a number of
viewpoints. The modules (processing and burning of
municipal refuse) are based on the St. Louis approach
(arbitrarily selected for illustration), and the system
burdens were derived by combining the appropriate
fraction of the burdens from the modules involved.
This option consumes the combustible portion of the
municipal refuse which obviates the need for an
alternate means of disposal and, in turn, results in a
negative value (a credit) for the solid waste burden of
the module. In addition, the prepared refuse replaces
a portion, 10 to 20 percent in the cases included, of
the coal required by the power plant, thus reducing
the coal system burden by that fraction.
Systems A variability
An approximate picture of the estimated
availability time frame may be drawn by listing the
systems as follows:
(1) Currently available
LNG
Nuclear fission
Natural gas
Oil-conventional boiler
Coal-physical cleaning
(2) Available by 1975
Mixed fuel-coal-municipal refuse
Topping of imported crude oil
Limestone scrubbing of flue gas
223
-------
Table 7. Summary of Ranked Systems, with Media Impacts, Efficiencies, and Costs
(Weighting Factors for Air. Water. Solid, and Land Uses=1)
Rank
1
2
1
4
>
6
7
t
9
10
11
12
1)
U
1}
16
17
ia
If
20
21
22
J3
2*
2}
26
Svatm
Environ.
Index
1.5
J.J
11.2
12.*
16.7
19.7
22.6
2).)
21.7
U. 9
24.6
24.6
2S.O
27.1
27.3
29.3
30.7
30.8
31.2
34.4
36.3
37.7
61.3
61.6
4). I
S3. 3
Extraction
None
None
Svltrn
Tranaportatlon Proceailng
Transportation
LNC Tinker/StotaBe/DIllrlbutlon/Cailflcatlon
laportejd relld Fl. bed ccabuit.
101 E. CM 1-201 Prepared Pun. Rafale
Nat. |M mil
Ealt coal. 3 H.
Welt CMl. S.M.
Eait eul. S.M.
Nuclaar Flialon - Total Syltem"
Delulf nat. gal
Kail Callfy, low Bcu
Bolt. Iron combuac.
Rail None
Rill Fl bad coabuit.
Vat. gai plpellni
None
None
Hone
901 E. cool-101 Prepared Hun. Refuae
Eait CMl. S.M.
Rani
Eait coal
Eait coal
Wot coal. S.M.
Oil will, onahore
Eait coal. S.M.
Eait coal. S.H.
Oil well, onahora
Eau coal, S.M.
Oil veil, of(-
•here
tail coal, S.M.
bit coal. S.H.
Oil wall, mihon
Eait coal, D.H.
Can coal, D.M.
E«l coal, D.M.
Rail None
Oil taakar Topping refinery
Rail Phyllcal coal clean
Rail Phyalcal coal clean,
Rail None
Oil plpallna Refinery doonatlc
kail Coal liquefaction
Rail Chemical coal clean
Oil plpallna Crude oil saalflcailra
Rail Cailt. lew Blu lur|l.
Oil pipeline Refinery deceit Ic
Rill None
Rill None
Oil pipeline ID finery dooeetlc
Rail Phyalcal coal clean
Rail Phyilcal coal clean
Rail lone
Hone
Oil b*r|a
None
None
Dene
Oil bars*
None
NOM
Hal. |ii pipeline
None
Oil tanker
Hone
Done
Oil tankar
None
None
None
VI 1 Illation
Conv boiler
Cociblned cycle
fonv boiler
line icrub
Conv boiler
Conv. boiler
Conv boiler
Conblned cycle
Cotiv boiler
lloe acrub
Conv boiler
Vg0 1C rub
Conv boiler
topp resld.
Conv. boiler
Conv. boiler
lime acrub
Conv bolUr
line ic rub
Conv. boiler
den. reild.
Conv. boiler
Conv. boiler
Conv. boiler
Conv. boiler
Conv. boiler
don relld.
Conv. boiler
line iccub
Conv. boiler
Conv. boiler
doa. reild.
Conv. toller
Conv boiler
line acrub
Conv. boiler
Total
fllr
Iriplc:
1 21
2 00
t 08
0 0032
t 47
I 00
a 83
3 00
4 34
4.S9
5 75
9 7)
3.38
4 49
9.64
1.66
12 57
3 09
7.49
9 99
4.59
19.6
9 99
9.16
2. 78
19 09
Total Total
Water Solid
IrpJcl Impact
0 0004 0
0 7.89
0 018 -6.5S
0.022 4.
0 0092 0
0 011S 31.26
0 0140 24.66
0 0100 46.64
0.02 39 7
0.0220 35.67
0 163 0.0701
0.0221 11.76
0 0234 40.63
0 0-.18 60.4f
0. 1161 00703
0.0242 46.61
0 0213 31.76
0.1016 0.307
0.0142 41.11
0.174 0.071
0.0221 66.0
0.0207 31.31
0.237 0.071
0.168 44.49
0 1)7 71.04
0.1216 31.60
Total
Land
lepiet
0 054
0 Hi
1 75
0 1
2 91
2 27
I 59
I 92
1 52
2 09
0 132
2.21
2.34
I. So
1 24
2.S8
2.07
4.20
3.06
1.23
2.09
1.97
1.2}
1.78
1.69
1.S9
Overall
Sri tea
Eff
321
.330
348
100
341
329
.369
.373
.348
.349
.324
.126
.301
.149
.122
.276
.330
.270
.244
.321
.148
.169
.321
.124
.307
.169
Overall Eit Ynr
Colt, o!
mill/to1! Appl.tat'on
11 3
11 5
11.0
9.1
11 S
10.6
u.s
11 S
10 0
12.6
13.3
11.2
11.2
10. S
11.2
11.)
9.1
11.2
10.0
12.4
9.1
Curr^pt
I'M
1«75
Curren*
Current
1931
Current
1961
1975
1980
1975
Current
197S
1975
Current
1985
1980
1«80
193}
Current
1973
Current
Current
Current
197}
Cu-rrnt
Appronlcala-ayaten coita nay vary by » 2.3 Bllll/kUlir Cor apcclflc CUM.
•• Include! only_ onvlronneniil inpacti reiultlng Iron nornal controlled operation at (Me tine. Analyaii of nuclear accident probability and effect la 101 cocplete.
-------
Table 8. Alternate Ranking of Systems
Weighting Factor for Solid Waste = 0.3
Weighting Factors for Air, Water, and Land Use = 1
01
Rank
(or
W. - 0.1
1
2
1
4
1
6
7
a
Sylten
Rank
Environmental for Svnttm
Indom
1.1
3. a
12.2
12.1
14.4
11.1
16.7
16.7
All W - 1
n
1
2
4
3
6
a
1
14
Extraction
Non»
Nona
East
East
Nat.
Vest
Transportstlan Proceisln(
Transportation
UiC/T>nl>er/Slorage/3lltrlbutlon/Caslflcatlon
BOX E.
coal. S.H.
coal. S.H.
(aa vail
coal. S.H.
Imported resld Fl. bed combust.
Nuclear Fission - Total System*
coal-201> Propared Hun. Refuse
Rail Caslfy. low Btu
molt, iron combust.
Rail Fl. bad combual.
Desulf. nat. (aa
(all Nona
Nona
Nona
Nat. gaa pipeline
Moo*
Utilisation
Conv. boiler
Combined cycle
Conv. boiler
lime acrub
Conv. boiler
Combined cycle
Conv. boiler
Conv. boiler
6
7
a
9
10
11
12
11
U
11
16
17
IS
19
20
21
22
21
24
2}
26
11.3
16.7
16.7
16.9
17.7
18.0
IB. 4
21.1
21.6
II. 9
24.1
21.1
26.2
27.1
30.7
32.0
32.9
34.4
31.9
41.1
41.2
a
1
14
9
10
13
7
21
16
12
11
17
19
U
IB
22
25
20
24
21
26
Ealt coal. S.H.
Nat. (aa vail
West coal. S.H.
901 I.
Bait coal. S.H.
Eait coal
Wtat coal. S.H.
bit coal. S.H.
Eaat coal. S.M.
Eaic coal
Nona
Eaac coal, S.H.
Bait coal, S.H.
Oil we 1 1 onitior •
Oil «ell, on. her.
Eaat coal, S.H.
Caat coal. D.M.
Oil wall, oifshora
Caat coal, D.H.
Oil well, onshore
Eaat coal, D H.
Rail
(all
Coa 1-101 Prepared
Rail
Rail
Rail
Rail
Rail
Rail
Oil tanker
Rail
Rail
Oil plpallna
Kail
Rail
Oil pipeline
Rail
Oil pipe Una
Rail
Fl. bad combust.
DeiuH. nat. (aa
Nona
Hun. Refuse
Nona
Physical coal clean
None
Nona
Coal liquefaction
Physical coal alcan
Topping refinery
Chealcal coal claan
Cailf. lo» Itu lurgl.
Crude oil gasification
None
Phyalcal coal clean
Reflnerj deaaatie
Physical coal claan
Refinery domestic
Nona
Nona
Nat. gaa pipeline
Moo*
Nona
Nona
Nona
Nona
Nona
Nona
Oil berga
Nona
None
01 1 h*VB«
ui i oargo
hat. gaa plpallna
Nona
Nona
Oil tanker
Nona
Oil lankar
Nona
Combined cycle
Conv. boiler
Conv. boiler
lime aerub
Conv. boiler
llna ic rub
Conv. boiler
MfiO scrub
Conv. boiler
lima ic rub
Conv. bollsr
Conv boiler
line scrub
Conv. boiler
Conv. boiler
Conv. boiler
topp res Id.
Conv. boiler
Conv boiler
Conv. boiler
don rmld
Cenv. boiler
Conv. boiler
Conv. boiler
line scrub
Conv. boiler
don. res Id.
Conv. boiler
Conv. boiler
dan. reild.
Conv. boiler
Includes only environmental Impacts
and affect la not eoaalcta.
resulting froo normal controlled operation at this tine. Analysis of nuclaar accident probability
-------
(3) Available by 1980
MgO scrubbing of flue gas
Chemical coal cleaning
Crude oil gasification
(4) Available by 1985
Fluidized-bed combustion of coal and oil
Gasification of coal
Liquefaction of coal (solvent refining).
Cost of Pollution Control
The costs associated with the various mechanisms
for the control of emissions from different phases in
the fuel-energy cycle have been developed.* A
summary of the ranges of control costs in terms of
medium, fuel, and module is given in table 9.
Conclusions
(1) The major results of this study and the
conclusions which have been drawn may be
summarized as follows:
{a) A preliminary compilation of effluent data
has been developed for those energy sources
considered commercially viable in the 1975 to
1990 time period. These data represent readily
available information within EPA and private
industry concerning the quantity of residual
pollutants produced during the extraction,
conversion, transportation, and stationary use of
fuels to produce electricity or direct heating
under best available conditions of environmental
control. The incremental cost of control and the
overall cost of electricity produced also have
been compiled.
(b) A preliminary methodology has been
developed for organizing the effluent data
collected and for combining the emission data for
each module into a single environmental index
for each energy system. The value of such an
index is that it provides a tool for making explicit
the value judgments of any system evaluator with
respect to the relative environmental impact of
energy systems. This methodology has been
applied in the context of this study to develop a
gross environmental ranking of the energy
systems. This methodology has been applied in
the context of this study to develop a gross
environmental ranking of the energy systems
considered. Ultimately, such a ranking of energy
systems must be done on the basis of specific and
•Report referred to in "Acknowledgment" at end of this
paper
local environmental impacts which may vary
considerably the weighting factor associated with
each module and pollutant.
(c) From the data compiled in this study, it is
clear that natural gas systems produce electrical
energy with the least associated environmental
burdens. Moderate air emissions occur in the
extraction and combustion phases, but other
burdens are small or negligible. Electrical energy
produced by residual fuel oil systems gives rise to
greater environmental burdens. Significant air
emissions occur in the refining and combustion
phases, and water pollutants are produced in the
refining phase. Eastern coal-based systems, which
employ current technology, produce still greater
environmental burdens, chiefly in the form of
solid waste from extraction and combustion, and
air emissions from combustion.
(d) The application of improved technology in
the areas of fuel conversion and pollution control
can be expected to achieve substantial reduction
in the overall environmental burdens. The control
of SO2 emissions from coal and oil combustion
needed to achieve ambient air quality standards
can be technically achieved in the 1975 to 1990
time period. Similar conclusions may be drawn
regarding coal conversion technologies such as
liquefaction and gasification. However, such
treatment or control technologies must transfer
the inherent fuel sulfur, plus chemical reactant,
to another media creating water pollutants or
solid waste products. Near the end of the 1975 to
1990 time period, regenerative stack-gas-cleaning
technologies, such as MgO scrubbing, and
advanced combustion techniques, such as
fluidized-bed combustion of coal and oil, can be
made available which will achieve equivalent
reduction of air emissions with only a moderate
increase in the production of solid waste. This
conclusion can be illustrated by comparing the
approximate total annual air emissions associated
with the extraction, transportation, and
combustion of eastern coal to produce 1,000 MW
of electricity: for coal burned in a conventional
boiler, 235,000 tons; for conventional boiler plus
wet limestone scrubbing, 60,000 tons; for
conventional boiler plus MgO scrubbing. 60,000
tons; and for fluidized-bed combustion of coal
plus combined cycle, 40,000 tons. The
corresponding approximate total annual
production of solid waste for the same four
systems is: 500,000; 1,300.000; 530,000; and
700,000 tons; respectively. By comparison, the
226
-------
Table 9. Summary of Control Costs
Medium
Control Cost
per 10 Btu
Module
Air
Coal
Gas
Oil
Water
Coal
Gas
Oil
Solid
Coal
Gas
Oil
Total
Total
$0.10
0.01
0.05
$0.35
0.05
0.25
$0.16 - $0.65
$0.005 - $0.01
0.005 -
0.005 - 0.01
$0.015 - $0.02
$0.01 - $0.10
0
0
0
0.03
Total
$0.01 - $0.13
Processing, power plant
Extraction, power plant
Processing, power plant
Extraction
Extraction
Extraction, processing
Extraction, processing,
power plant
Processing
227
-------
total of the air emissions associated with the
extraction, transportation, and combustion of
natural gas is about 80,000 tons. The solid waste
production for the natural gas system is
negligible. Similarly, the approximate total
annual air emissions from the extraction,
transporation, refining, and combustion of oil
could be reduced by wet limestone scrubbing of
the power plant stack gas from about 120,000
tons to about 75,000 tons with an associated
increased production of 322,500 tons of solid
waste. Application of MgO scrubbing would
achieve the same level of air emission with
minimal increase of solid waste production above
no scrubbing;
(e) Based on this evaluation, the air emissions
from coal-based systems can be reduced by
application of advanced technology to less than
those of natural gas, while minimizing the
attendant increase in solid waste.
(f) The data bank and computer program for the
ranking procedure are extant. The computerized
methodology makes it simple to test the
preferred weighting factors of any energy-system
evaluator.
(g) The pertinent environmental factors have
been identified for those advanced energy sources
considered to be developmental during the 1975
to 1990 time period. The qualitative
environmental relationships have been evaluated
by a panel through value judgments and
subjective considerations. Advanced energy
sources judged to exhibit major potential for
supplying significant portions of future energy
demand with reduced environmental impact are
geothermal, solar, and nuclear fusion.
(2) The very broad scope of the project and the short
time available for this preliminary study
necessarily limited the effort to an overview.
Nevertheless, the assembled data represent a
unique compilation of emission inventories which
can serve as a foundation and point of departure
for both technical investigators and
policymakers.
(3) Emission data for hazardous trace materials are
grossly inaccurate or not available.
APPENDIX
METHODOLOGY FOR RANKING
OF ENERGY SYSTEMS
Approach
The evaluation of alternative systems for the
production of useful energy, and the modules
contained within these systems, required the
comparison of a variety of environmental burdens.
These burdens can arise through different steps in the
process, and various components of the environment
can be affected. Some system of ranking which
attempts to collect these complex burdens into a
single number or set of numbers is desirable as part of
the evaluation scheme. An attempt has been made
during this phase of the study to develop a method
for the initial ranking of energy systems.
In concept, the ranking system used is based upon
methodology developed for the Bureau of
Reclamation, U.S. Department of the Interior (ref.
1). This concept involves a hierarchy of
environmental burdens under four major
environmental components, which in turn can be
separated into environmental parameters. An
environmental parameter is a single measurement or a
series of measurements of the burden. If the
environmental burden for the system or activity
under consideration is to be derived properly, then it
is necessary to combine the environmental burdens at
each level of this hierarchy. Weighting factors are
assigned as a measure of the importance of a burden
at any particular level of the hierarchy and can be
used to accommodate the different units used in the
measurement of the various burdens.
Due to the limited time for the study, a complete
hierarchy of environmental burdens was not
developed. An attempt has been made to develop a
quantitative system utilizing five environmental
components. The components assumed to be of
significance to the evaluation of energy systems are:
(1) Air,
(2) Water.
(3) Sol id waste,
(4) Land use,
(5) Radiation.
Various parameters within each component were
quantified as appropriate to each module. The goal of
the ranking procedure used was to derive a single
environmental index for the energy system under
consideration. This index is represented as follows:
'
W
W
Qp
where I- = Environmental index for energy sys-
tem i,
W = Weight of module m in system i.
WL =
WP =
QP =
Weight of environmental component
n.
Weight of parameter p,
Quantity of p produced per unit of
energy.
228
-------
A computer code was written to facilitate the
calculation of the environmental indices for the
relatively large numbers of modules and for the
combination of these modules into systems. The
computer code also permitted the performance of
sensitivity calculations to gain an appreciation of the
dependence of the environmental index on
uncertainties in input data. The assignment of
weighting factors, the development of the computer
code, and the sensitivity calculations are discussed in
the following sections.
Derivation of Weighting Factors
Weighting Factors for Air Parameters
The air pollution index is based on the primary
emission standards and pollutant levels in terms of
emissions in pounds per million Btu. The following
primary standard values were employed:
SOX 80 jug/m3
NOX 100 jig/m3
Paniculate 75 jug/m3
CO 1000 Aig/m3
Hydrocarbons
160 /Lig/m3
Trace metals
Be 0.1 /Lig/m3
Hg 1.0 jug/m3
Pb 2.0
annual average value
annual average value
extrapolation from
10.000 mg/m3/8 hr
1 hr—used as annual
average value
Fine particles «1jL() and thermal emissions also
should be included in the consideration of air
emissions. Standard values, which could be used in
the same manner as the values above, were not
identified for these pollutants in this study, so these
emissions were not included in the calculations of the
environmental index. Their omission from the current
assessment is not meant to minimize their
importance, however.
The above values were referenced to the NOX value.
The resulting weighting factors are:
Pollutant
NOX
S°x
TSP
CO
HC
Trace metals
Be
Hg
Pb
Factor (W )
1 (reference)
100
80
100
75
100
1000
160
10
10
50
= 1.25
= 1.33
= 0.10
= 0.63
Babcock's factors
(normalized)
514/514 = 1.00
514/1,430 = 0.36
514/375 = 1.37
514/40,000= 0.01
514/19,300 = 0.03
Thus, the assumption is made that an increase of 1
Atg/m3 of SOX is as detrimental as 1.25 jug/m3 of NOX
and an increase of 1 ;ig/m3 of CO is as undesirable as
0.1 mg/m3 of NOX, etc.
A similar type of normalizing approach for the
development of a combined index for the
measurement of air pollution has been suggested by
Babcock (ref. 2). His factors which were based upon
California air quality standard are shown for
comparison and have been normalized to NOX.
Weighting Factors for Water Parameters
The procedure used to derive the weighting factors
for the parameters within the water component is
based upon the same concept as that used for the air
factors, i.e., based upon water quality standards.
Credence to this approach is given in the work of
Brown (ref. 3) and Morton (ref. 4). In addition to
these references, Wolman (ref. 5) has also identified
important indicators of water quality. The water
quality parameters used in the present study are:
Importance Weighting factor
Stable solid, leaching not
important 1
Environmental pollution
potential if leached
or eroded 2
Hazardous if leached or
eroded 3
Directly hazardous
(contact, proximity
etc.) 4
229
-------
The weighting factors were derived by normalizing to
the value of dissolved oxygen.
Weighting Factors for Solid Waste
Many module produce some solid waste.
Consideration of the quantity of this waste also can
be assessed as part of the environmental impact. The
weighting factors were assigned on the basis of a gross
scale of importance based on the composition of the
solid waste.
Land-Use Parameters
The land-use parameter includes the land area
involved and a time factor. For the processing and
utilization modules, the proper unit arises from the
fact that a certain land area is associated with a plant
with a stated throughput, as in tons of coal per hour
or the equivalent heating value (Btu per hour). When
the area in acres is divided by this energy rate, the
resulting units are acre-hour/106 Btu. For the
extraction modules, the area is associated with a total
energy (e.g., tons of coal per acre). The resulting
value in acres/106 Btu is converted to consistent units
by multiplying the value by the length of time
assumed for the operation.
Different weighting factors could be applied to
reflect geographical location, compatibility with
surroundings, dedicated or temporary use, and other
related factors. However, weighting factors for land
use have been taken as unit for all calculations
performed to date.
Weighting Factors for Radioactivity
A rigorous comparison of the environmental effects
of material emissions and radioactive emissions from
energy generation was beyond the scope of this
study. One of the major difficulties is the need to
consider both somatic and genetic effects for
radioactivity against only somatic effects of material
emissions. While lethal levels of radioactive and
nonradioactive pollutants are reasonably well known,
the exposures to the public encountered in energy
generation are well below these lethal values.
Dose-effects relationships down to the near
background or natural concentrations are not known
with certainty for either type of pollutant and the
comparability between the assumed relationships of
both types of pollutants is strictly hypothetical.
Nevertheless, in this attempt to compare the
environmental burden of a number of energy systems,
it was desirable to develop some appreciation of
magnitudes of the relative effects and to apply an
internally consistent set of weighting factors to the
emissions. Several approaches to derive a factor which
would permit a comparison of nuclear and fossil fuel
systems based upon effects were examined, and a
method to include radioactive emissions under the air
and water components was derived.
Health Costs Data. According to the Council on
Environmental Quality (ref. 6), the total annual
health costs due to air pollution is $6 billion. For a
population of 200 million, the cost is $30 per person
per year.
Not all air pollution, however, is attributable to
stationary sources. A simple estimate of the fraction
of air pollution from stationary sources can be
derived on a weight basis. The total air emissions in
1970 are (ref. 7):
Emissions. Millions of Tons Per Year
CO
Particles
SOX
HC
NOX
As Reported
Fuel Combustion
in Stationary
Sources(a)
0.8
6.8
26.5
0.6
10.0
44.7
Total
147.2
25.4
33.9
34.7
22.7
263.9
Normalized to NOX
Fuel Combustion
in Stationary
Sources(a)
0.08
8.9
33.1
0.4
10.0
52.48
Totaj
14.7
33.8
42.4
21 8
22.7
135.4
(a) Although stationary sources include more than the energy generation systems under consideration,
there is little to be gained in this order-of-magnitude estimate of weighting factors to further
subdivide the emissions.
230
-------
The weight fraction due to stationary sources is
(44.7)/(263.9) = 0.17 if the as reported data are used.
and is (52.5)/(135.4) = 0.39 if the data are
normalized to the NOX values.
By applying the weight fraction data to the health
costs, the annual costs are $5 to $12 per person due
to energy generation (stationary sources). The electric
utilities used 13.750 X 1012 Btu of fossil fuel in
1970 (ref. 8). Annual health costs per person for the
burning of fossil fuels to produce electricity are
between $0.36 to $0.87 X 10"' per 106 Btu.
Sagan (ref. 9) has analyzed the risk to the U.S.
population from all steps of the nuclear fuel
cycle-occupational exposures in uranium mining and
milling, manufacturing, reactor operation, fuel
reprocessing, and exposure to the public near an
operating reactor. His cost data are based upon the
assumption that 1 rem produces 100 cases of cancer
per million persons exposed and that the cost per
human life is $300.000. This places the risk-cost per
rem per person at $30. The annual cost for all
activities is $0.11 per person.
For 10.300 megawatts of nuclear power produced
by plants now operating in the United States, the
human costs for the entire U.S. population of
generating that electric power are derived to be about
0.026 mill per kilowatt hour. This is equal to $1.1 X
10"'' per 106 Btu per person.
If health and human economic costs are used as the
basis of comparison of emissions from nuclear
systems and fossil systems, then emissions from the
fossil fuel systems are about 100 to 300 times greater
in importance than emissions from nuclear systems.
Lethality Data. For accidental or occupational
exposures to NO2, death within 3 to 5 weeks
following exposure from broncheolites fibrosis
obliterons results from concentrations in the range of
282 to 376 mg per m3 (ref. 10). The primary ambient
NOX standard is 100 micrograms per m3 on an annual
basis. If a breathing rate of 20 m3 per day is used, the
annual dose from an exposure to NO? at the allowed
maximum ambient level is 730 mg/yr. If a midrange
lethal exposure value of 327 mg per m3 is selected,
then the ratio of an instantaneous lethal
concentration to allowable ambient concentrations is
about 0.4.
For acute exposure to radiation, a value of 300 to
600 rads is considered lethal (ref. 11). The maximum
acceptable permissible dose to the general population
from manmade sources is 170 mrem on an annual
basis. If a midrange lethal dose of 450 rads is selected,
then the ratio of lethal dose to allowable ambient
doses is about 2,600.
Thus, if the assumptions are made that the ambient
or general population exposure standards are set to
limit health effects, that the effects they are set to
limit are equally severe, and that dose and dose-rate
relationships can be extrapolated to ambient levels
with the same degree of comparability, then, using
this lethality approach, fossil-fuel emissions are about
6500 times more important than emissions from
nuclear systems. The validity of these assumptions is
not known.
Comparison of Nuclear and Oil-Fired Power Plants.
An analysis has been performed by Starr et al. (ref.
12) to compare emissions from nuclear and oil-fired
power plants m the Los Angeles basin. The analysis
was restricted to the comparative public health
aspects of oil-fired and nuclear power plants and their
associated activities in a typical urban setting.
Operation of these plants, under conditions up to the
present Federal regulatory limits, was estimated to
cause 60 times more respiratory deaths due to fossil
fuel pollution than cancer deaths due to nuclear plant
effluents. In normal practice, neither plant would be
expected to expose the public to these limits,
primarily because the routine effluents must be
reduced below regulatory levels to meet a variety of
conditions, and would thus be expected to be
substantially less (by a factor of 10 or more) under
average circumstances.
In both cases the integrated accident risk (averaged
over time and all episodic events) is about 10~s of the
continuous exposure, for either the nuclear plant or
the oil-fired plant. For the analyzed accident with
equal probability of occurrence, the oil-fired plant
has a substantially worse public health impact than
the nuclear. For example, the one-m-a-m ill ion-years
event for the oil-fired plant would lead to
approximately 700 respiratory deaths in a population
center of 10 million people; while the
one-in-a-million-years event for the nuclear plant
would result in approximately one death in the same
population.
Data from Los Angeles are not directly applicable
to other regions of the country. However, the analysis
by Starr is useful in establishing the relative
significance of nuclear power and fossil fuel power
emissions. The factor of 60 which he derived is of the
same order of magnitude as the factor of 100 derived
from health cost effect.
Derivation of Weighting Factor (Wp) for
Radioactivity. In order to compare the emissions
from nuclear power systems (derived in units of
curies) to the emissions from fossil fuel systems
(derived in units of pounds), it was necessary to
231
-------
develop a conversion factor which both converts the
units to the same basis and relates comparable effects.
The previous discussion of health costs and lethality
data gives an estimate of the relative importance of
exposure to fossil fuel emissions and to radioactivity.
It would appear that fossil fuel emissions are at least
100 times more important than nuclear emissions on
an effect basis. In light of the uncertainties in the
analysis and the limited consideration of accidents in
nuclear power systems, it has been assumed that
emissions from fossil fuel systems and emissions from
nuclear systems have equal importance. For normal
operations, this will tend to overstate the importance
of the environmental impact of nuclear power.
Comparison of emissions from the two types of
systems would require a detailed analysis of each
specific pollutant or radionuclide emitted. For the
purposes of this study, several approximations were
made. During reactor operations and fuel
reprocessing, it is assumed that the air emissions are
predominantly the noble gases. MFC values (10 CFR,
Part 20) for the noble gases are 3 X 10~7 /uCi/ml. This
value will be taken as the standard for the air
emissions calculations. Several radionuclides can be
present in the waste water, and MPC values (10 CFR,
Part 20) in water for some typical radionuclides are:
3H. 3 X 10~3 /LiCi/ml; I37Cs, 2 X 10~5 *iCi/ml; and
*°Sr, 3 X 10~7 juCi/ml. For purposes of the water
effluent calculations, a midrange value of 3 X 10~5
jitCi/ml has been used for the "standard" MPC water
value.
To reduce the radioactivity to the same units as the
fossil fuel emissions, the following relationships are
applied.
Air emissions.
Radioactivity
in NOX
equ ivalents
NC-
*r,air X
Ambient
standard
NOX
"Standard*
MPC air
where Qr = quantity of radioactivity in curies
NO
*
I
Ambient
standard,
NOX
Factors which relates the importance
of fossil fuel emissions to radio-
activity in units of Ib/Ci. For this
analysis it is assumed to be 1.
100*ig/m3 = 0.23 X I0~6 Ib/m3
"Standard"
(MPC) air
Radioactivity
inNOx
equivalents
3 X 10"' Ci/mJ
Qr X 0.7, Ib.
Water effluents. To derive a similar factor for
water, radioactivity has been compared to trace
metals. As noted earlier, the water quality standard
values, based primarily on drinking water standards,
are in the range of 0.1 to 0.3 ppm with the
Hg-standard set of 0.5 ppb. For the purpose of
comparison, a water quality value of 0.1 ppm will be
used.
Radioactivity
in trace metal
equivalents
trace
", water *
Water quality
standard
trace metals
"Standard"
(MPC) air
As in the case of air, lfrace metals/'r 's a
which relates the importance of trace metals to
radioactivity. It is assumed to be 1 pound per curie
for this analysis.
Water quality
standard,
trace metals
"Standard"
(MPC) water
Radioactivity
in trace metal
equivalents
0.1 ppm = 2.2 X 10~« Ibs/m*
3 X 10* Ci/m3
Qr X 7,Ib
Since the water impacts are normalized in terms of
dissolved oxygen, an additional factor of 50 has been
applied to the preceding expression. Thus, in order to
calculate the burden to the water from radioactivity,
the radioactive effluents in curies is to be multiplied
by 3.5 X 1CT2 to obtain a comparable unit.
Ecology. Weighting factors for ecological impacts
to energy systems have not been estimated for the
current study. Concepts to be used, however, could
follow the general approach outlined in the study for
the Bureau of Reclamation (ref. 1). The ecological
impacts are not included in the current environmental
index.
232
-------
Human Factors. A combination of parameters is
involved in the impact of energy systems directly
upon man's environment. Data needed to derive
quantitative weighting factors are often missing, and
only a subjective approach is possible at this time.
For this report, only the occupational health and
safety sections have been considered. These have been
derived primarily of data from the Bureau of Labor
Statistics (ref. 13). Weighting factors have not been
derived, and the human factor impacts are not
included in the current environmental index.
Computer Program for Environmental Index Calculation
The computer program for the calculation of the
environmental index for the energy systems evaluated
encompasses seven steps listed below:
(1) Read-in Data
The data read-in consists of:
(a) Emission values for the components air,
water, solid, and land for each module;
(b) The weighting factor for each emission value
within the component;
(c) Weighting factors for the relative importance
of air, water, solid, and land;
(d) Weighting factors for module type,
extraction, transportation, processing, and
utilization;
(e) The modules comprising each system.
(2) Calculate Weighted Component Totals for Each
Module
This calculation is performed by multiplying the
emission values within each component by the
appropriate weighting factor (read in 1-b). The
result is four numbers per module representing
the sum of impacts for each component, air,
water, solid, and land.
(3) Efficiency Correction
The weighted component totals for each module
are divided by the product of the efficiencies of
all subsequent modules in the system. This
calculation is necessary since the module data are
expressed on a basis of a million Btu. The output,
and thus the associated emissions, of, say, an
extraction module, must be increased in
proportion to the inefficiency of the power
plant.
(4) Calculate Normalizing Factors
The modules are arranged into systems
(according to data read in 1-e), and the air, water,
solid, and land totals are summed up. For the
number of systems chosen, this procedure results
in a total of four sums: air, water, solid, and land.
The normalizing factor is then calculated as the
ratio of the air sum to each of these sums.
(5) Calculate the Module Index
For each module in a system, the four
normalized numbers (air, water, solid, land) are
weighted with respect to component weighting
factors (read in 1-c) and summed. This
calculation results in a single impact number for
each module in a given system.
(6) Calculate the System Index
For each system, consisting of several modules,
the system index is calculated by multiplying
each module impact number by the module
weighting factor (read in 1-d). The sum of these
results within a given system gives the system
index.
(7) Rank the System
Finally, ranking of the systems is performed by
ordering by system index.
Sensitivity Analyses
The procedures used in deriving an environmental
index for various energy systems incorporated a
number of assumptions; in many cases, estimates have
been made of the quantities of pollutants emitted in
the modules. A series of analyses were performed,
using the computer code previously described, to test
the sensitivity of the ranking of the systems to
variations in the input and the assumptions that have
been made. The results of these sensitivity analyses
given an indication of the validity of the overall
procedure and an appreciation of the reliability of the
final ranking.
The results of three sets of calculations are shown
in table A-l to illustrate the changes in rank ordering
of systems that occur with changes in weighting
factors. The base case for comparison is the ranking
systems where all components and modules were
equally weighted. These rankings are compared to a
case where the solid waste component was weighted
at 30 percent of the other component weighting
factors; i.e., burdens as a result of solid wastes are less
important than burdens in air, water, and land
utilization components. In the third case, all of the
components were equally weighted, but the
utilization module was weighted 3 times as great as
the other modules.
In general, the overall rankings remained similar;
the systems that rank high in the base case tend to
rank high in the comparison case. Where the
importance of solid waste component is diminished,
the system using Eastern coal and a limestone
233
-------
Table A-1. Sensitivity of Ranking to Variations in Weighting Factors
All Componenta and Modules
Weighted Equally
VW1-00'
All Modules Weighted Equally
All Components Weighted Equally
Utilisation Modules WeighLed
3 Times Greater Than Others
ro
CO
LNG
Fluidi?ed bed-oil
Cai
E coal-molten iron
W coal-conv boll
E coal-prei fluid bed
E coul-MgO scrubber
Import otl-topplng-CB
E coal-PC-CB
E coal-PC-CB+LSS
W cojl-CB-H-SS
On oll-plpe-re£-barge-CB
SRC-CD
CCC-CB
On oil-oil pipe-crude gas-gas pipe-gas CB
E coal-Lurgl
E conl-CB+LSS
Off oil-oil pipe-ref-OT-CB
E co.il-CB
On oil-oil pipe-ref-OT-CB
DMT.C-PC-CB
DMliC-PC-CB+LSS
DMEC-CB
LNG
Fluldizcd bed-oil
E coul-molten iron
E coal-pros fluid bed
N gas-GP-CB
W coal-CB+LSS
E coal-CB4MeO
E coal-PC-CB+LSS
W coal-CB
E coal-CIHLSS
E co£il-SKC-CB
E cool-PC-CB
Imp oil-topping-CB
E coal-CCC-CB
E coal-Lurgl
On oil-pipe-ref-barge-CB
On oil-pipe-crude gas-pipe-CB
E coal-CB
DMEC-PC-CBH-LSS
Off oil-pipe-ref-OT-CB
D^D•:c-PC-CI^
On oil-pipe-ref-OT-CB
DMliC-CB
LNG
Fluid laed bed-oil
ImporL oil-Lopplng-C13
Gn*
E coal-SRC-CB
E coal-molten iron
Off coi-pii>e-ref-OT-CB
E co.il-prcs fluid bed
E coal-PC-CIHLSS
On oll-pipe-rcf-bargc-CB
On oll-plpe-crude gns-pipe-gas CB
W coal-CB
E coal-PC-CB
E co.il-MgO scrubber
CCC-CB
W conl-CB=LSS
E cojil-CBfLSS
E coal-Lurgl
On oil-pipe-ref-OT-CB
DM1'.C-PC-CB
DHLC-PC-CB+LSS
E coal-CB
DMEC-CB
-------
scrubber ranks considerably higher than in the base
case. The large quantities of solid waste produced in
this system have relatively less influence on the
ranking of this system. The imported oil system
moves high in the ranking when greater weight is
given to the utilization module. Its utilization module
has a relatively low burden where compared to other
systems. The changes in the order of the systems are
in the direction anticipated by the changes in
weighting of components or models.
The sensitivity analyses performed to date are not
sufficient to determine the significance of small
differences in environmental indices. Until additional
analyses are performed and the results evaluated, care
must be taken in the interpretation of the ranking
and the values assigned to the environmental index.
References
1. "Environmental Evaluation System for Water
Resources Planning," report to Bureau of
Reclamation, U.S. Department of the Interior, by
Battelle Columbus Laboratories, January 1972.
2. L. R. Babcock, Jr., "A Combined Pollution Index
for Measurement of Total Air Pollution," J. Air
Pollution Control Association, Vol. 20. No. 10
(October 1970), p. 653.
3. R. M. Brown, N. I. McClelland, R. A. Oeminger,
and R. G. Tozer, "A Water Quality Index-Do We
Dare?" Water and Sewage Works, Vol. 17
(October 1970), pp. 339-343.
4. Robert K. Morton, "An Index-Number System
for Rating Water Quality." Water Pollution
Control Federation Journal, Vol. 37, (March
1965), pp. 300-306.
5. M. G. Wolman, 'The Nation's Rivers." Science
Vol. 174 (November 1971), pp. 905-918.
6. "Environmental Quality," The Second Annual
Report of the Council on Environmental Quality,
August 1971, p. 106.
7. "Environmental Quality." The Third Annual
Report of the Council on Environmental Quality,
August 1972, p. 6.
8. "U.S. Energy Outlook," A Summary Report of
the National Petroleum Council, Washington.
D.C., December 1972).
9. L. A. Sagan, "Human Costs of Nuclear Power,"
Science Vol. 177 (Ausgust 11,1972), pp. 587-93.
10. "Air Quality Criteria for Nitrogen Oxides,"
AP-84.
11. "Background Material for the Development of
Radiation Protection Standards," Report No. 1.
Federal Radiation Council, May 15, 1960.
12. C. M. Starr, M. A. Greenfield, and D. F.
Hausknecht, "A Comparison of Public Health
Risks: Nuclear vs. Oil-Fired Power Plants,"
Nuclear News. Vol. 15. No. 10 (October 1972).
pp. 37-45.
13. U.S. Department of Labor, Bureau of Labor
Statistics, Handbook of Labor Statistics, 1971,
Bulletin 1705, Washington, D.C.
Acknowledgmen t
This paper is based upon the results of two studies
conducted at Battelle-Cotumbus Laboratories for the
U.S. Environmental Protection Agency. These studies
were: "Energy Considerations in Future Energy
Growth" (Contract No. 68-01-0470) and 'The Cost
of Clean Air, 1974" (Contract No. 68-01-1538).
Battelle-Columbus Laboratories is grateful to the U.S.
Environmental Protection Agency for the financial
support and assistance during the conduct of those
studies and for the opportunity to summarize the
results in this symposium.
235
-------
236
-------
THE ENVIRONMENTAL IMPACT OF COAL-BASED
ADVANCED POWER GENERATING SYSTEMS
Fred L. Robson and
Albert J. Giramonti*
INTRODUCTION
The electric utility industry in the United States is
currently faced with a multitude of problems. The
near-term necessity of meeting promulgated
environmental regulations has been exacerbated by
the shortage of low-sulfur fuels and, where available.
by their very high costs. A combination of events
culminated in a very tight money market at the very
time that utilities had to raise large sums to finance
the more costly conventional and nuclear stations
now being ordered. Thus, it is apparent that there
exists a pressing need for an efficient, low-cost power
generating system that could utilize high-sulfur fuel.
One such system that has the potential of
generating power efficiently while using less costly
equipment is the COmbined Gas And Steam
(COGAS) power system. This advanced power
generating scheme, shown in figure 1 in its simplest
form, has a gas turbine exhausting into a waste heat
recovery boiler which raises steam for use in a steam
turbogenerator. Combined-cycle systems, as with
other advanced technology gas turbine-based power
systems, require fuels of utmost cleanliness;
cleanliness that is usually well beyond that required
by environmental regulations.
When considering the use of coal as fuel for such
power systems, it is apparent that considerable
processing and cleanup must precede its introduction
into the engine. The following paper discusses the
factors affecting the performance of combined-cycle
power systems and the compromises in the system
that result when this system is integrated with a coal
gasif ler and fuel gas cleanup process.
PERFORMANCE OF COGAS SYSTEMS
The performance of the simple waste-heat
recovery-type COGAS system shown in figure 1 can
be approximated by:
•H1-i?gt)7?s
' T-
Tc
(1)
•Both authors are at United Aircraft Research
Laboratories, East Hartford, Connecticut; Dr Robson is
Chief, Utility Power Systems, and Mr Giramonti is Senior
Systems Engineer
where
Tfc = COGAS efficiency
ifet = gas turbine efficiency
Tfc = steam cycle efficiency
Tex = temperature of gas turbine exhaust
Ts = temperature of stack
TC = temperature of ambient conditions.
The most important factor in the above equation is
T7gt, the efficiency of the gas turbine.
Gas Turbine Performance
The key to gas turbine performance is turbine inlet
temperature. Currently, the newer turbines bemc
used in utility applications operate at temperature:
ranging from 1,800°F to near 2,000°F, with
efficiencies of 28 percent to over 35 percent. A
second significant parameter, the pressure ratio
(compressor discharge pressure/ambient pressure),
varies from around 8:1 to nearly 151 in these
machines. The relationship between efficiency, inlet
temperature, and the pressure ratio is shown in figure
2. The parameter specific power in this figure is a
measure of the amount of work which can be done
by a given size machine and is, indirectly, a guide to
cost, i.e., a machine with a high specific power will
generally have a lower cost in $/kW than a machine of
lower specific power. Prior studies (refs. 1,2) indicate
that turbine inlet temperatures over 2,000°F could be
expected during the 1970 decade.
Steam System
Although the efficiency term for the steam cycle in
eq. 1 is modified by several coefficients, it is apparent
that it is desirable to achieve as high an efficiency as
practicable. There are, however, constraints on the
steam cycle conditions which are external to the
steam power system. These are gas temperature to the
boiler (gas turbine exit temperature) and the stack
temperature. The latter is set by dew point
237
-------
ro
u
93
AIF
COAL-
COAL GASIFIER
COMPRESSOR
STEAM
BOILER
TO STACK
BURNER
COMPRESSOR TURBINE
POWER
TURBINE
STEAM TURBINE
CONDENSER
ELECTRIC GENERATOR
ELECTRIC GENERATOR
Figure 1. Combined Gas-Steam Turbine System
-------
40
DISTILLATE FUEL OIL
CONVENTIONAL AIR COOLING
35
I
I
i
u
z
UJ
u
UJ
LU
Z
m
oc
(D
30
25
20
COMPRESSOR
PRESSURE RATIO
24
— ••• J^?L_~~ """ ">GnrT ^ oorm
2200
2400
2600
2900
TURBINE INLET TEMPERATURE. F
I
80
100 120 140 160
NET POWER PER UNIT AIRFLOW - KW/LB/SEC
Figure 2. Gas Turbine Performance
180
considerations and is usually not much below 300°F,
even when a clean fuel is used. It has been found (ref.
2) that a pinch temperature difference of 100°F
results in the most acceptable heat exchanger design.
Thus, for systems utilizing waste-heat recovery
boilers, the maximum steam temperature is 100°F
less than the gas turbine exhaust temperature.
For COGAS systems operating with conventional
distillate or natural gas fuels, the most attractive
steam system would have a quite simple cycle
configuration. Regenerative feedwater heating would
be limited to a single deaeratmg feedwater heater.
The generation of steam would be at a single pressure
level, and essentially all the steam would pass through
the turbogenerator. As will be discussed in a
subsequent section, the presence of a coal gasification
system alters the makeup of the steam system.
COGAS Performance
The potential performance of the COGAS system is
one of its most attractive attributes. When referring
to a system using conventional distillate-type fuels,
performance levels as shown in figure 3 could be
attained. At 2.200°F turbine inlet temperature, a
level which should be attainable in base-load turbines
in the mid-to-late 1970's, an efficiency of 43.5
percent could be realized. As turbine inlet
239
-------
DISTILLATE FUEL OIL
CONVENTIONAL AIR COOLING
52
48
a?
i
o
UL
LU
z
o
I
C/J
<
13
44
40
36
COMPRESSOR PRESSURE RATIO
20
^ 2400
__ —18
2600 2900
2200
TURBINE INLET TEMPERATURE, F
I
I
100
150 200 250
NET POWER PER UNIT AIRFLOW - KW/LB/SEC
Figure 3. COGAS Station Performance
300
temperatures increase, the efficiencies also increase,
and it should be possible to approach 50 percent
efficiency at inlet temperatures of approximately
3,000°F. The values in figures 2 and 3 are based on
conventional turbine cooling techniques. The use of
advanced cooling techniques or advanced materials
could significantly increase these values. Results in
reference 3 indicate COGAS efficiencies of about 55
percental 2,900° F.
Figure 3 also shows the effect of pressure ratio on
performance. It is interesting to note that the COGAS
system efficiency is not particularly sensitive to
pressure ratio, whereas specific power is sensitive to
pressure ratio. Therefore, tradeoffs between high
efficiency and high specific power can be considered
without undue performance penalty.
COGAS efficiency is replotted in figure 4, this time
against the parameter fraction of the fuel utilized in
the gas turbine. As the fraction of fuel utilized in the
gas turbine decreases (more fuel burned in boiler to
raise steam), the efficiency also tends to decrease.
The steam conditions in figure 4 have been adjusted
to take into account the additional firing. Thus, the
steam cycle efficiency is increasing as more fuel is
burned. At the lower turbine inlet temperature, the
point of maximum efficiency occurs with very slight
firing, but the small increase in efficiency would be
more than offset by the additional cost of the more
efficient steam system. At the higher turbine inlet
temperatures, the point of maximum efficiency
occurs when steam is being raised by exhaust heat
alone and all the heat added to the cycle is used at
combined-cycle efficiency. As more steam is
generated, additional fuel must be burned. This
240
-------
DISTILLATE FUEL OIL
CONVENTIONAL AIR COOLING
50
I
o
z
HI
u
u.
45
40
30
TURBINE INLET TEMPERATURE. F
2900
I
I
I
I
20 40 60 80
FUEL FLOW TO GAS TURBINE - % OF TOTAL
Figure 4. COGAS Station Performance With Fired Boiler
100
additional fuel increment is used only at steam-cycle
efficiency resulting in a degradation of the overall
system efficiency. This point is quite important in
understanding the overall performance of integrated
gasification, cleanup process, and COGAS systems.
Having established some base-line performance
estimates for COGAS systems using conventional
fuels, let us examine some representative processes
that produce low-Btu gas from coal and also some
processes that clean the low-Btu gas to meet
standards for both environmental and engine
requirements.
COAL GASIFICATION PROCESSES
Production of low-Btu fuel gas from coal is
achieved by gasification with air and steam at
elevated temperatures. The overall gasification
process is endothermic, primarily due to the
steam-carbon reaction which requires about 5,000
Btu per pound of carbon:
C + H2O -»• CO + H2
(2)
This heat requirement is satisfied by burning a
portion of the coal feed with air.
Gasification systems are commonly classified into
three categories according to the characteristics of the
coal bed, i.e., fixed, fluidized, or entrained. Generally
speaking, fixed-bed systems operate with
countercurrent flow of coal and gas at temperatures
below the ash-fusion point. Consequently, these
systems are characterized by relatively low
gasification rates and substantial tar formation.
High-temperature gasification under ash slagging
conditions affords higher gasification rates and
provides essentially a tar-free producer gas.
Cocurrent, entrained-flow gasifiers typically operate
under the latter conditions. However, at higher
temperatures, the fraction of the coal heating value
represented by sensible heat of the product gas is
substantially greater than for fixed-bed gasifiers, and
either high-temperature cleanup systems or heat
241
-------
recovery systems must be employed to achieve
comparable thermal efficiencies.
For use in advanced-cycle power systems, the
product gas must be at an elevated pressure. Since the
volume of the product gas is roughly twice that of the
air required for gasification, it is generally
advantageous to employ pressure gasification rather
than product gas compression to obtain a given
delivery pressure. Moreover, the specific gasification
rate (gas produced per unit of reactor volume) is
greater at higher pressure.
Gasification System Characteristics
Present-day technology for pressure gasification of
coal is limited to the fixed-bed type gasifier. Second
generation technology, judged to become available in
the 1980 decade, will probably evolve from current
developmental efforts on entrained-flow and
fluid-bed gasifiers. In the current study being carried
out by UARL and Foster Wheeler, the BCR
two-stage, entrained-flow-type gasifier was selected as
representing advanced coal gasification technology.
Typical operating characteristics of fixed-bed and
entrained-flow gasifiers are given in table 1.
The prominent differences in the performance of
these gasifiers are directly related to operating
temperature:
(a) The relatively low carbon conversion for the
fixed-bed system and the formation of
byproduct tar,
(b) The ratio of sensible heat of product gas to
coal heating value is twice as great for the
entrained-flow gasifier.
In the case of the fixed-bed gasifier, the presence of
tarry material in the gas complicates downstream heat
recovery and subsequent gas purification. For
low-temperature purification of the raw gas, direct
quenching is the preferred method thereby degrading
the level for sensible heat recovery. However, the
recovered tar product could be recycled to the
gasifier, thereby increasing the overall carbon
gasification. If a high-temperature purification system
is integrated with the fixed-bed gasifier such that no
tar is allowed to condense, then the tar represents a
component in the delivered product gas. This may
present a problem from a pollution standpoint in that
the tarry material typically contains 1.5 to 3.0
percent sulfur and about 1.0 percent nitrogen, most
of which would convert to SO2 and NOX during
combustion.
The large sensible-heat content of the gas from an
entrained-flow gasifier makes it imperative, from an
efficiency standpoint, to use heat recovery techniques
when used in conjunction with low-temperature
purification. Fortunately, the absence of condensible
tars facilitates indirect heat exchange and affords the
possibility for reheating the fuel gas feed to a gas
turbine. Because of the high effluent temperature, the
entrained-flow gasifier is particularly amenable for
integration with high-temperature purification
systems operating in the range of 1,600° to 1,700°F.
FUEL GAS CLEANUP PROCESSES
The fuel gas leaving the gasification system contains
sulfur- and nitrogen-bearing compounds and
particulates which must be removed to meet
constraints set by environmental concern and by gas
turbine requirements. The extent of the latter
requirements are noted in table 2 where the fuel
contaminant constraints are compared to values of
contaminants in the raw fuel gas. The necessity for
some sort of cleanup is apparent.
Cleanup systems can be categorized in many ways;
however, when mated with gasification and power
systems, it is useful to consider processes as operating
either at a low temperature or at a high temperature.
The dividing line between the two is somewhat
arbitrary but, for convenience, can be considered as
250°F.
Low-Temperature Cleanup Process
Characteristics
Low-temperature cleanup systems fordesulfurizing
raw producer gas are commercially available and have
been widely used for natural gas sweetening and in
treating synthesis gas for petrochemicals, e.g.,
ammonia, methanol, and oxo-alcohols. Commonly,
these are liquid scrubbing systems which operate
below 250°F. They are usually classified according to
the mode of acid gas absorption by the solvent, i.e.,
either physical or chemical absorption. Table 3 lists
several typical low-temperature sulfur removal
processes, together with the type of absorbent and
approximate operating temperatures.
Physical solvent processes generally employ an
organic solvent which absorbs the acid gas
components in accordance with their partial pressures
in the gas phase. Chemical systems usually employ
aqueous solutions of inorganic or organic compounds
which chemically react with the acid gas components.
These systems are relatively insensitive to partial
pressure effects. In both types of systems, the
absorbent can be regenerated either by heat, pressure
reduction, or a combination of these, thereby
producing a gas stream rich in sour gas components.
242
-------
Table 1. Operating characteristics for tvo representative gasification processes
Gasifier Type:
Temperature , F
Pressure, psia
Coal
Air/Coal, Ib/lb
Stean/Coal, Ib/lb
% Carbon Gasified*
Producer Gas
Vol. %
H2
CO
co2
H2
CHU
H2S
COS
""3
V
Tar, Ib/lb coal
HHV, Btu/SCF (Tar Free)
Sensible Heat/Coal EEV, J
Fixed-Bed
1000
500
Western Kentucky
2.69
0.3U9
81*
1*7.61
20.55
5.88
13.83
2.76
0.60
0.10
0.25
8.1*2
100.00
0.11
139
12.2
Tvo-Stage
Entrained-Fljv
1800
500
Illinois No. 6
3>2
0.567
99
U7.70
16. 7«*
8.8U
11.98
3.H*
0.1*6
0.10
0.38
10.66
100.00
0.0
125
21*. 6
•Ho tar recycle
243
-------
Table 2. Coal-based gaseous fuels
Impurity
Solids
Condensable
Hydrocarbons
Sulfur
Metals
Cone entrat ion
0.1 g /ft3
0-100 lb/106 ft3
Variable
Vn
Na + K
Ca
Pb
Cn
10 ppm
NA
NA
3 ppm
NA
Max Allowable
0.8 lb/106 ft3
0.5 lb/106 ft3
0.185S Mol (H2S)
0.1-0.2 ppm wt
0.2-0.6 ppm wt
0.1 ppm wt
0.1 ppm wt
0.02 ppm wt
Table 3. Representative low-temperature sulfur removal processes
Type
Chemical
Chemical
Chemical
Chemical &
Physical
Physical
Physical
Physical
Absorbent
Aqueous
Potassium Di-Methyl
Amino Acetate
Alkanol Amine
Sulfolane +
Di-Isopropanolamine
Polyethylene Glycol
Ether
Methanol
N-Methyl
Pyrrolidone
Temp., F
160-230
85
100
Status
Commercial
Commercial
Commercial
120
50
-UO
80
Commercial
Commercial
Commercial
Commercial
244
-------
Selection of those systems most attractive for
treating coal-derived fuel gas must take into
consideration the following:
1. Sulfur removal capabilities, not only with
respect to H2S, but also other sulfur
compounds such as COS and CS2;
2. Selective absorption of sulfur compounds
over carbon dioxide; since CO2 need not be
removed from fuel gas intended for use in
advanced power cycles, the CO2 absorption
represents an increased operating load on the
system in terms of solvent circulation,
regenerative heat requirements, and
equipment sizes;
3. Type of absorbent insofar as the purified gas
may be contaminated by entrained or
volatilized solvent;
4. The system tolerance to trace contaminants
in the raw producer gas such as HCN,
phenols, tars;
5. Overall energy requirements and capital cost.
Generally speaking, liquid scrubbing systems are
capable of reducing the sulfur content m the treated
gas to 100 ppm or less. These systems are also capable
of removing the particulates from the fuel gas stream
to levels compatible with the gas turbine
requirements.
High-Temperature Cleanup Process
Characteristics
High-temperature systems for sulfur removal are
not commercially available, although there are several
in various stages of development. Most of the active
work presently involves use of limestone and
dolomite, which have potential in the range of 1,500°
to 2,000°F. Other systems receiving attention employ
iron oxides, molten salts, and liquid metals. To date,
none of these systems have been demonstrated on the
pilot plant level.
Table 4 lists several processes currently under
development which may prove viable for use with
second generation gasification systems. These systems
operate by chemical reaction of the absorbent with
sulfur compounds in the gas yielding the
corresponding metal sulfides. As with
low-temperature systems, economics require that the
spent absorbent be regenerated for reuse. Depending
upon the chemical system, regeneration is conducted
with either air or steam plus carbon dioxide, e.g.:
CaS • MgO + H20 + CO2 -" CaCO3 • MgO + H2S;
2 FeS + 3%O2 -»• 2 SO2 + Fe2O3.
Selection of potentially attractive high-temperature
systems should consider the following factors:
1. Capability for removing sulfur compounds,
COS as well as H2S. The residual
concentration of sulfur in the treated gas is
determined by chemical equilibria for each
system. In general, high-temperature systems
do not appear to be as versatile as wet
scrubbing systems in terms of reducing
residual sulfur to 100 ppm or less.
2. The form in which absorbed sulfur is
Table U. Representative high-temperature sulfur removal processes
Process-Type
Half-calcined dolomite
Fully-calcined dolomite
Sintered iron oxide
Iron oxide
Molten carbonate salt
Absorbent
CaCOj ' MgO
CaO • MgO
Fe203 + Fly Ash
CaC03
Temp. F
1500-1800
1600-2000
800-1500
700-1200
1100-1700
Status
Pilot
Pilot
Pilot
Experimental
Pilot
245
-------
regenerated, HhS, SO2. or elemental sulfur.
Elemental sulfur is the preferred form, since
it can be stockpiled without presenting
significant pollution problems.
3. Ability to regenerate the absorbent without
substantial loss in activity.
4. Overall energy requirements and projected
capital costs.
At this time, it is not apparent that the
high-temperature cleanup processes would remove
particulates effectively. Additional paniculate
removal devices might have to be used, but such
devices have not yet been identified.
PERFORMANCE OF INTEGRATED SYSTEMS
The characteristics of the three major systems
which make up the integrated powerplant have been
described. The combinations of these systems give
rise to a very large number of possible configurations,
especially when the necessary auxiliaries such as heat
exchangers, booster compressors, etc., are taken into
account. In order to investigate these many
combinations, a computer model was developed at
UARL under corporate sponsorship which allows
great flexibility in analyzing the integrated systems.
The basic model is shown schematically in figure 5; in
actual use, there are many more modules.
The three columns in figure 5 represent the COGAS
system, the gasifier and cleanup stream, and an air
preheater fired by the product gas. This latter
equipment is but one of several ways of preheating air
before its use in the gasifier.
While the following is applicable to nearly all
gasification processes, for the purpose of this
discussion, only the high-temperature entrained-flow
process will be considered.
In the integrated power system, air for the gasifier
is bled from the gas turbine compressor. In order to
overcome the various pressure drops in the gasifier,
cleanup, and gas turbine fuel controls, the gasifier
must operate at a pressure above that of the gas
turbine; thus, a booster compressor is required. One
method of driving this compressor is by use of a
steam turbine using high-pressure steam from the
main steam boiler (see fig. 6 for a simplified flow
chart of one of the many possible configurations).
After gasification, the hot fuel gas must be purified.
If a high-temperature method were used, the only
box appearing after the gasifier in figure 5 would be
that for the cleanup system. If a low-temperature
system were used, the hot fuel gas would pass
through one or more waste-heat boilers to drop its
temperature from roughly 1,750 F to a level
acceptable for the cleanup system. Alternatively, the
hot gas could be cooled by regeneration against the
cooler, purified fuel gas; or, a combination of the two
could be used. Yet another alternative is shown in
figure 6 where a waste heat boiler is used in
conjunction with a heat exchanger in which the cool.
purified fuel gas is heated against the hot bleed air
from the compressor prior to recompression in the
booster compressor. The attractiveness of such a
system is somewhat doubtful, however, because
leakage in this heat exchanger could produce a
potential explosion hazard.
The reasoning behind all of these schemes is to
recover the sensible heat in the fuel gas, which, in the
two-stage entrained-flow-type gasifier, can be as much
as 25 percent of the total fuel heating value. With
high-temperature cleanup, nearly all the sensible heat
would be used in the gas turbine combustion at
combined-cycle efficiency, and very little steam
would be raised by burning fuel. (Steam raised in the
gasifier waste-heat boiler is, of course, generated by
heat obtained by burning coal in the gasifier.)
In low-temperature systems, the sensible heat
would be recovered in a waste-heat boiler or in a fuel
gas regenerator. As was pointed out in figure 4, the
generation of steam by burning fuel is generally
undesirable. This may be seen best by examining
figure 7, which compares distillate-fired and
gasified-coal-fired COGAS system performance. In
this figure, the normalized efficiency of a
conventional distillate-fired COGAS system is shown
as a function of the fraction of the fuel input used to
raise steam. The normalized efficiency would be
unity when all the fuel used is burned in the gas
turbine and would be about 0.85 when 25 percent of
the total fuel used is burned in the boiler (unlike fig.
4, the steam conditions remain constant in fig. 7).
The values of efficiency for gasified-coal-fired systems
using several different cleanup processes, for both
high and low temperatures, have also been normalized
against the distillate-fired system.
The use of a high-temperature, half-calcined
dolomite cleanup process would result in a
normalized efficiency of 0.85 at a fuel gas delivery
temperature to the gas turbine of 1,610°F. About 4.5
percent of the coal heating value would be used to
raise steam as the gas is cooled from 1.750°F, the
gasifier exit temperature, to the best temperature for
sulfur retention (1,610°F). Three low-temperature
processes would use about 16.5 percent of the coal
heating value to raise steam, if a fuel gas regenerator
were used to raise the fuel delivery temperature to
246
-------
AIR
ELEC.GEN I POWER TURBINE
I
COAL
STEAM CYCLE , MAIN BOILER
LEGEND
— STEAM/WATER
COAL/FUEL GAS
AIR/COMBUSTION PRODUCTS
Figure 5. Integrated COGAS/Coal Gasification Power Station
247
-------
LEGEND
COAL/FUEL GAS
AIR/COMBUSTION GAS
STEAM/WATER
AIR
FROM MAIN
STEAM LINE
POWER TURBINE
COMPRESSOR
TURBINE
STEAM TURBINE
TO CON DENSER
COAL
PREPARATION
TO BOOSTER
COMPRESSOR DRIVE
ELECTR|C
GENERATOR
I
COAL
COOLING
TOWER CIRCUIT
CONDENSATE PUMP
TO STACK
Figure 6. Integrated Coal Gasification—COGAS Power Station
-------
0 HIGH-TEMPERATURE CLEAN UP
DDO LOW-TEMPERATURE CLEANUP WITH REGENERATION
A LOW-TEMPERATURE CLEANUP WITHOUT REGENERATION
100
>
I
I
U
UJ
O
iZ
LL
UJ
UJ
I
UJ
90
80
70
60
50
COGAS SYSTEM WITH DISTILLATE FUEL
COGAS SYSTEM WITH GASIFIED FUEL
I
I
I
Figure 7.
5 10 15 20 25
% FUEL HEATING VALUE TO RAISE STEAM
Effect of Cleanup System Operating Characteristics
On System Performance
685°F. The normalized efficiencies of these systems
are all about 0.72. If no regeneration were used,
about 24 percent of the coal heating value would be
used to raise steam, and the normalized efficiency
would be about 0.67.
The differences in efficiency between the
distillate-fired and gasified-coal-fired COGAS systems
with high-temperature cleanup are due to gasifier heat
losses (ash and cooling water), auxiliary loads for
coal-handling equipment and the cleanup systems,
and to the power required for the booster
compressor. The COGAS systems with
low-temperature cleanup face similar losses, plus
degradation due to the large stream flow.
ENVIRONMENTAL CONSIDERATIONS
The objective of all the foregoing has been to set
the stage for discussions of the environmental impact
of the gasified coal-fired combined cycle. At this
time, the evaluations of this most important aspect of
this advanced power cycle concept are just being
initiated. The following comments, however, can be
made on the major pollutant streams.
Sulfur Oxides
As a practical limit, well within the EPA 1975
standards for coal-fired plants (1.2 Ib S02/106 Btu
input), a value of 100 ppm H2S + COS was set for the
249
-------
fuel gas leaving the cleanup system. This corresponds
to less than 0.20 Ib S02/106 Btu of coal, roughly a
factor of six less than the standard. Table 5 shows the
makeup of the fuel gas leaving three different types
of low-temperature cleanup systems, while table 6
shows the fuel gas makeup from high-temperature
systems. These tables also indicate the utility
requirements for these systems.
If necessary, sulfur oxide emissions from the Claus
plant also can be reduced to essentially negligible
levels through the use of several commercially
available processes (ref. 4).
Nitrogen Oxides
The formation of nitrogen oxides is a much more
complex problem than the formation of sulfur
oxides. The nitrogen in the fuel gas in the form of
NHa, HCIM, pyridenes, etc., contributes to NOX
formation and should be removed in the fuel cleanup
process. As has been commented previously, the
low-temperature cleanup systems would remove the
greater portion of these constituents, whereas it is not
apparent that the high-temperature systems would do
so (see tables 5 and 6).
The fuel delivery temperature also has a profound
effect on the production of NOX. In figure 8 (ref. 2}
the combustion temperature, which determines the
rate of NOX production, is plotted as a function of
fuel gas heating value. Two curves are shown, one
representing the increase in combustion temperature
resulting from an increase in the chemical heating
value of the fuel (the lower curve), and one showing
the more rapid increase in combustion temperature
with increased sensible heat (fuel temperature). If
fuel gas having a 120 Btu/scf chemical heating value
were sent directly to the engine from a
low-temperature scrubber (e.g., 100°F as with an
amine system), the adiabatic combustion temperature
would be approximately 3,680°F. (The combustion
air preheat due to compressor work also would effect
the temperature). If a high-temperature cleanup
system were used (1,750°F), the fuel chemical plus
sensible heat would be increased to around 148
Btu/scf; and following the upper curve, a combustion
temperature of about 4,250°F would result. Using
the fuel gas regeneration scheme previously discussed,
the final fuel temperature would be nearly 685°F,
thus giving rise to a combustion temperature of
approximately 3,900°F.
What effect on NOX production results from these
varying combustion temperatures, and how do these
rates compare with more conventional fuels? Figure 9
shows the NOX emissions as a function of combustion
temperature for several turbine inlet temperatures
Assuming a 2,200°F (2,660 R) inlet temperature, the
NOX emissions given in table 7 can be postulated.
The above projections are based upon a theoretical
treatment developed by Pratt & Whitney Aircraft
(ref. 5). These theoretical results have been borne out
in tests on the combustion of low-Btu gas carried out
by Pratt & Whitney Aircraft and the Turbo Power
and Marine Systems, Inc. (subsidiary of United
Aircraft) and Texaco. Inc. These tests (ref. 6) give
NOX emissions from conventionally, designed, gas
turbine combustors burning low-Btu fuel of the order
of 5 to 10 ppm.
To the above values of NOX formed by atmospheric
nitrogen must be added those values produced by the
nitrogen-bearing compounds in the fuel. These
compounds would be removed in the
low-temperature cleanup systems (see table 5) but
not in the high-temperature systems as presently
configured. The amount of NHs, HCN, HCNO, etc..
formed is a function of nitrogen content of the
various coals used. Using reference 2 as a guide for
HCN, HCNO, etc., mole fractions of these
constituents could be of the order of 10~5 to 10~4 or
about 0.01 Ib NO/106 Btu of coal. The NH3 content
shown in table 5 for low-temperature systems
indicates concentrations varying from 0 to 600 ppm.
This could add as much as 0.4 lb/106 Btu of coal for
these cleanup systems. In table 6, NHs
concentrations are shown to be six times larger,
meaning that when both atmospheric and fuel
nitrogen are considered, NOX emissions for
high-temperature systems could be over 2 lb/106 Btu
of coal, an unacceptable value. It is probable that not
all the fuel nitrogen would be converted to NOX, but
at this time no reliable estimates of the fraction
converted are available.
Trace Elements
The fate of trace elements during gasification is
difficult to assess. Work performed at IGT (ref. 7)
provides the only source of data in the literature.
Since these data are available, no further discussion
will be attempted, except to note that the values of
Pb, Ni, and V in the vapor state (probably as oxides)
are of a magnitude that could potentially be harmful
to the gas turbine (see table 2). These metallic vapors
would condense during the low-temperature cleanup
process and would not reach the turbine. It is not
evident that the high-temperature processes would
remove these potentially harmful fuel gas
constituents.
250
-------
Table 5. Estimated performance of lov-tec::erature cleanup of BCR gag
Process Polyethylene jlycol He- Methtr.ol
* *
Feed Sircars1 a'
BCR gas flow, nph
Temperafirs , F
Pressure, psia
Product Streams
Sulfur, Ib/hr
Transport gas, mph
Product gas, mph'
HHV, Btu/scf
Temperature, F
Composition, Vol %
tu
2
CO
C02
CHi.
H20
iiK-3
H2S + COS
Utilities
Cooling duty, !MBtu/hr
Steam 3 1300 psia, Ib/hr
8 65 psia, Ib/hr
Electric Pover, kv
Boiler Feed Water, Ib/hr
Steam Condensate, Ib/nr
Feed Gas Cooling, MMBtu/hr^
Efner
126
1750
1.50
7!*. 9
31*
333
ll»3
100
55
19
9
14
3
0
100 ppn
2.9
107
1020
61
219
1233
C arbor ate
126
1750
1»50
*7\i Q
?l|
350
137
250
52
18
7
13
h
6
0.06
100 ppm
3.3
107
2505
26
223
2718
5.2
1*26
1750
1*50
76.2
31
33C
ll*l«
90
55
19
8
ll»
li
0
0.06
10 ppm
3.0
107
780
U2
223
995
fc.6
(a) Based on 2000 Ib/hr coal feed to gesifier
(b) Available for steac generation and/or gas reheat
251
-------
Table 6. Estimated perfcrcance of iugh-teaperature cleanup and BCR gas
Sintered Iron
Feed Streams^
BCR gas flov, mph
Temperature, F
Pressure, psia
Dolomite, Ib/hr
Product Streans
Sulfur, Ib/hr
Transport gas, mph
Product gas, mph
HHV, Btu/s=f
Temperature, F
Composition, Vol %
H2
CO
co2
H2
CH|j
HoO
NH-
HgS + COS
Utilities
Cooling Duty, M-Btu
Steam g 1300 psia
Electric Power
Boiler Feed Water
Steam Condensate
Process Water
Natural Gas
Oxiie
126
1750
1.50
69.3
3U
392
125
1000
1*8
12
1U
17
3
6
.38
.02
1.9
(11*90.0)
98
371.6
2183
595
Molten
Carbonfete
1*26
1750
»*50
71.8
31*
390
125
1610
1.8
16
10
13
3
10
.38
.01
1.2
275
25
1113
130
Half-Calcined Fully-Calcined
Dolonite
1*26
1750
1*50
33
67.2
3U
390
125
1610
US
16
10
13
3
10
.38
.06
.5
(U70)
22
606
(122)
1*2
Dolomite
1*26
1750
U50
273
71*. 8
3U
21*1
lit 3
1550
51*
12
3
3
21
6
.UU
.01
1.0
(8103)
(322.0)
891.1
(1.30)
181.
(a) Based on 2000 Ib/hr coal feed to gasifier
(b) Net product gas after deducting process fuel requiremento
252
-------
REFERENCE FUEL HHV = 120 BTU/SCF
REFERENCE FUEL TEMPERATURE = 80F
STOICHIOMETRIC FUEL-AIR RATIO
INITIAL AIR TEMPERATURE = 825F
4800
4600
01
tr
4400
DC
UJ
Q.
UJ
4200
CO
O
CJ
u
m 4000
9
3800
3600
INCREASE FUEL
TEMPERATURE
INCREASE FUELHHV
I
I
I
100
120 140 160 180
FUEL CHEMICAL PLUS SENSIBLE HEAT-BTU/SCF
200
Figure 8. Effect of Fuel Gas Chemical And Sensible Heat On
Combustion Temperature
253
-------
1000
BASED ON P&WA THREE-ZONE BURNER MODEL
CONSTANT BULK CAS FLOW RATE
FIXED BURNER VQLUUE
STOICHIOMETRIC FUEL'AIR RATIO IN RECIRCULATION ZONE
BURNER PRESSURE * 12.5 ATM
TURBINE INLET TEMPERATURE, R
2220 2460 2860 3260
O \7 D 0
METHANE
JP-5
SIMULATED LOW
HICH-BTU
FUELS
LOW-BTU FUELS
I I
0.1
3400
3600
3800 4000 4200
MAXIMUM COMBUSTION TEMPERATURE - R
4400
4600
FIGURE 9. NITRIC OXIDE FORMATION IN GAS TURBINE BURNER
254
-------
Table 7- Potential NOX emissions
Tfype System
Low-temperature fuel
Low-temperature with regeneration
High-temperature fuel
Conventional distillate fuel
NO
Emissions^8-'
lb/106 lb/106
ppm Btu Coal "' Btu Coal
2
8
110
1*50
0.01 0.02-O.U
0.03 0.03-O.U
O.lt 3.2
1.0 1.0
(a) Based on gas turbine exhaust at approximately 300$ theoretical air.
(b) NOX formed from atmospheric nitrogen.
(c) NOX formed from atmospheric and fuel nitrogen.
-------
Thermal Discharge
All of the power systems considered herein would
be equipped with wet cooling towers; thus, there
would be essentially no thermal pollution to
surrounding water sources. The cooling tower systems
would handle approximately 4,500 Btu/kWhr for the
low-temperature systems and approximately 3,600
Btu/kWhr for the high-temperature systems. To these
values must be added roughly 1,200 Btu/kWhr of
heat rejected by the low-temperature cleanup systems
and about 800 Btu/kWhr for the high-temperature
systems.
SUMMARY
The foregoing discussion has briefly described the
results to date of a study being performed under EPA
Contract 68-02-1099. The information presented
should be treated as preliminary, since the analyses
are continually being updated and the modeling
techniques are being refined.
Table 8 serves as a method of summarizing the
environmental impact of the integrated
combined-cycle systems. There appears to be no
difficulty in meeting the SOa limitations with the use
of any of the low- or high-temperature cleanup
systems. If a low-temperature system such as
polyethylene glycol ether is used, essentially all the
nitrogen-bearing compounds in the fuel gas would be
removed and only NOX formed from atmospheric N2
need be considered. Other low-temperature systems
remove a portion of the fuel nitrogen and, even with
regeneration, could still meet the environmental
regulations. However, the high-temperature cleanup
processes would not remove fuel nitrogen and appear
to result in unacceptable emission levels. (A
nitrogen-compound removal system could be added,
but it would operate at 150 to 200°F, thereby
negating any advantage of the high-temperature
system.) Even when the emissions are considered on a
Ib/MWhr basis, which takes into account efficiency
advantages, the high-temperature cleanup systems do
not appear attractive from the environmental impact
viewpoint.
Included in table 8 are two conventional steam
stations to serve as a basis for comparison. The steam
station using low-temperature cleanup would meet
both the sulfur and NOX regulations, while the steam
system using high-temperature cleanup would have
difficulty meeting the NOX regulations.
Up to this point, no mention has been made of
economics. Because of the status of the study,
insufficient information has been obtained to
generate reliable cost estimates. All that can be said at
this time is that the COGAS systems continue to
appear economically competitive with alternatiave
clean power systems in the near term and. as
technology improves, have the potential to become
the lowest-cost (mills/kWhr) power generating
system.
REFERENCES
1. F. L. Robson. A. J. Giramonti, G. Lewis, and G.
Gruber, "The Technical and Economic
Feasibility of Advanced Power Systems and
Methods of Producing Non-polluting Fuel for
Utility Use." Final Report to National Air
Pollution Control Administration, NTIS PB-198
392, December 1970.
2. A. J. Giramonti, "Advanced Power Cycles for
Connecticut Electric Utility Station." Final
Report to Connecticut Development
Commission, January 1972.
3. F. L. Robson and A. J. Giramonti, 'The Effect
of High-Temperature Materials on Combined
Cycle Performance." Paper presented at Army
Materials Technology Conference, November
1972.
4. E. S. Fisch and S. A. Sykes, Jr. "Synthetic Fuel
Gas Purification Using Shell Treating Processes."
Presented at the American Chemical Society
Meeting, April 1973.
5. S. A. Mosier and R. Roberts "Low-Power
Turbopropulsion Combustor Exhaust
Emissions." Theoretical Formulation and Design
Assessment. Vol. 1, Technical Report
AFAPL-TR-73-36, June 1973.
6. W. B. Crush, W. G. Sen linger, R. D. Klapatch,
and G. E. UiHi "Recent Experimental Results on
Gasification and Combustion of Low-Btu Gas for
Gas Turbine." ASME Paper 74-GT-11, April
1974.
7. A. Attari, "Fate of Trace Constituents of Coal
During Gasification." EPA-650/2-73-004, August
1973.
256
-------
Table 8. Summary of COCAS system environmental Impact
10
Ib S02 Ib S02 Ib NOX
Type of Cleanup 106 Btu Coal MwHr 10° Btu Coal
Low-Temperature 0.15 1-7 0.02-0.1*
Low-Temperature 0.15 1.6 O.Ob-O.b
With Regeneration
High-Temperature 0.15 l.fc 3.2
Conventional Steam
with Gasification.
and Low-Temperature
Cleanup 0.15 1.8 0.01-0.2
Conventional Steam
with Gasification
and High-Temperature
Cleanup 0.15(b) 1.7 3.2
Ib NOX Btu to Cooling^**
Mwhr kwhr
0.2-1*.0 1*300
O.lt-U.O 1*500
30 3600
0.1-2.0 7600
32 7300
Particulates
None
None
Environmentally
Acceptable^0'
None
Environmentally
Acceptable
(a) Only pover system discharge is tabulated.
(b) Depending on process, this value could go to 0.6-0.8. Only power system emissions are tabulated.
(c) May not be acceptable to this turbine.
-------
258
-------
ENVIRONMENTAL CONSIDERATIONS IN THE USE OF ALTERNATE
CLEAN FUELS IN STATIONARY COMBUSTION PROCESSES
G. Blair Martin*
Abstract
In response to the shortage of low-sulfur, premium
quality fuels, such as natural gas and distillate oil, a
variety of processes are under development for
conversion of coal and other resources into gaseous
and liquid fuels. The physical and chemical properties
of these alternate clean fuels may be substantially
different from the fossil fuels currently in use. The
properties of these fuels can have an important
impact on the pollutants emitted to the environment
by combustion processes. The purpose of this paper is
to review the available information on the
combustion and emission characteristics of these fuels
and to assess the applicability of combustion
modification techniques for control of NO* and
other pollutants. A comparison is made between
chemical and physical properties of fossil fuels and
selected alternate fuels, including low-Btu gas,
methanol, and synthetic oil. Particular emphasis is
placed on trace constituents of the fuel and the role
of these constituents in pollutant formation. The
similarities and differences of pollutant control
techniques between alternate fuels and fossil fuels is
considered. Finally, a summary of unresolved
questions about use of alternate fuels in stationary
combustion systems is posed.
INTRODUCTION
Within the past year, events have brought home the
fact that clean fossil fuels are being used at rates
exceeding our ability to produce them from existing
sources. This realization has intensified efforts in the
area of fuel conversion processes utilizing natural
resources which are in abundant supply. One category
of such processes is based on the conversion of coal
to a variety of "clean" fuels. In this context, clean
has come to mean low sulfur fuels. A variety of
approaches are being taken, including the production
of synthetic natural gas (SNG) which can be used to
supplement natural gas in pipelines. In addition,
various other conversion processes are being
developed to produce other fuels such as low-Btu gas
and synthetic oils. A second category is based on the
*G. B. Martin is with the Combustion Research Section,
Control Systems Laboratory of the U.S Environmental
Protection Agency, Research Triangle Park, North Carolina.
conversion of oil shale to produce oil products The
fuel products of both categories of processes may
have properties significantly different than those of
current fossil fuels.
The fuels produced by these processes will be used
either as substitutes for current fossil fuels in existing
combustion processes or as the basis for design of
new combustion processes to attain maximum
efficiency. The different properties of these alternate
fuels may have a significant impact on pollutant
production in the combustion process and/or the
energy efficiency of the process. The purpose of this
paper is to assess available information on the
properties of these alternate fuels and to discuss
potential impact of these fuel properties on pollutant
production and process efficiency of stationary
combustion systems. The applicability of pollution
control technology available and under development
for conventional fuels may have an influence on the
extent and/or necessity of fuel processing, thereby
impacting both the cost and the energy efficiency of
the fuel conversion processes. Primary consideration
will be given to gaseous and liquid fuels for which the
most information appears to be available. There are
certain solid byproducts of the processes; however,
the information on these is limited and will not be
considered at this time. Several of the ideas are
frankly speculative and are included to point out the
possibility of basic rethinking combustion system
design for alternate fuels, considering both
environmental and efficiency aspects. This paper
evaluates technical concepts and does not attempt to
anticipate future EPA pollutant control regulations.
BACKGROUND
To provide perspective for discussion of the
environmental aspects of combustion of alternate
fuels, it is necessary to provide some background on
potential pollutant emission, available pollutant
control techniques for conventional fuels, and
comparison of properties of conventional and
alternate fuels and classes of equipment in which
these fuels may be used.
Identification of Pollutants
In the combustion process, pollutants are produced
259
-------
during the oxidation of the fuel to release energy.
Pollutants that are formed can be categorized into
three general classes: (1) pollutants which are
primarily related to the conditions of the combustion
process; (2) pollutants which are primarily related to
the composition of the fuels; and (3) pollutants
which are attributable to a combination of the above.
Pollutants related to combustion conditions.
Pollutants formed solely as a function of the
conditions of the combustion process can generally
be categorized as products of incomplete combustion.
including carbon monoxide, unhurried hydrocarbons,
and carbon paniculate. Formation of gaseous
pollutants (carbon monoxide and unburned
hydrocarbons) can be related to two areas of the
combustion process: (1) air/fuel mixing at the
burner, and (2) subsequent quench rate of the
combustion products. If the proper burner design is
used initially, complete oxidation of the hydrocarbon
fuel will occur in the flame zone; however, the
combustion gas may contain a substantial
concentration of carbon monoxide. This carbon
monoxide and any residual hydrocarbon will then
oxidize in the high temperature postflame region
unless the reactions are quenched. This quench can
occur in the gas phase through the improper mixing
of cold gas with the combustion products, or it can
result from rapid cooling at the heat transfer surface.
Therefore, control of these pollutants requires proper
burner design which is also matched to the heat
transfer configuration. Most properly designed fossil
fuel systems produce CO and UHC levels below 100
ppm. However, after the system is placed in service,
improper tuning or maintenance can have significant
adverse effects on this performance. The other type
of pollutant in this category is carbon particulate,
which may form by either of two mechanisms. One
of these is a gas phase paniculate formation which
tends to be a relatively small panicle size formed by
condensation of hydrocarbon radical fragments in the
flame. This type of particulate would generally
appear as "smoke" and can be formed for any fuel.
The second type of carbon particulate is the larger
size cenosphere paniculate derived from coking of
the fuel droplet or panicle. This type of particulate is
produced in combustion of liquid or solid fuels. In
general, paniculate formation must be prevented at
the burner as it is extremely difficult to burn out in
the postflame zone once formed.
Pollutants related to fuel composition. This
category of pollutants is a function of fuel
composition and is virtually independent of
combustion conditions. The prime compounds which
fall in this category are sulfur oxides, trace metals,
and ash (noncarbon paniculate). From all evidence,
the levels of emissions of these compounds can be
quantitatively calculated based on fuel composition
and are not affected to any great extent by
combustion zone conditions. (It is conceivable that
the chemical form of trace metals could be altered;
however, this has not been proven.)
Combined effect pollutants. Pollutants related to
both combustion process conditions and fuel
composition include nitrogen oxides, oxygenated
hydrocarbons, and possibly carcinogenic polycyclic
organic matter (POM). Of these three, the major
information is available on the formation and control
of nitrogen oxides. There are two potential paths for
the formation of nitrogen oxide: (1) thermal NO,
which is a function solely of the combustion
conditions; and (2) fuel NO, which is a function of
both fuel composition and local combustion
conditions. Thermal NO is a product of high
temperature fixation of atmospheric nitrogen present
in the combustion air. This reaction set has an
exponential dependence on temperature and a lesser
dependence on oxygen concentration (ref. 1),
although other factors enter in (ref. 2). Since
practical turbulent diffusion flames are not
characterized by a single unique temperature or
oxygen concentration, the actual level of nitrogen
oxide formed in any combustion process by
atmospheric fixation is dependent on a variety of
factors, including overall stoichiometric ratio, air/fuel
mixing, and heat removal. These factors govern the
location and size of local regions of high temperature
in which thermal NO is formed1. Thermal NO can
potentially be formed in the combustion of any fuel,
and it predominates for nonnitrogen-bearing fuels
such as natural gas or distillate oil. Fuel NO is formed
by oxidation of chemically bound nitrogen in the fuel
to nitrogen oxides. The reactions forming fuel NO are
apparently relatively independent of temperature and
have a strong dependence on the availability of
oxygen (refs. 3,4,5). The formation of fuel NO is also
dependent on localized flame conditions. Fuel
nitrogen is distinct from fuel sulfur in that it is not
completely convened into nitrogen oxide, but rather,
from the available evidence, some fraction is
converted to nitrogen oxide with the balance going to
molecular nitrogen. There has been unconfirmed
speculation of formation of other nitrogen
compounds such as hydrogen cyanide. The fraction
of fuel nitrogen oxidized to NO is dependent on a
number of factors, including overall excess air, level
260
-------
of nitrogen in the fuel, fuel injection method, and
fuel/air mixing pattern. In general, the absolute level
of fuel NO increases as the fuel nitrogen
concentration increases. Evidence indicates that at
•
least 50 percent of the total nitrogen oxide formed in
the combustion of nitrogen-bearing fuels can be
attributed to fuel NO. The fact that these two
possible mechanisms for formation of NO exist
requires the selection of the control techniques based
on the nature of the fuel being considered.
The formation and control of the other two
potential pollutants in this category, i.e., oxygenated
hydrocarbons and polycyclic organic matter, is not
well documented and must be considered in future
research. The concern for oxygenated hydrocarbons
arises primarily for fuels which have high levels of
partially oxidized hydrocarbons (e.g., methanol) as
fuel constituents. The consideration of POM in this
category arises from the fact that many hydrocarbon
constituents in heavier fuels are similar in structure to
the multiple ring form of POM compounds. Also coal
appears to produce high levels of POM. Both types of
pollutants can also be synthesized in the combustion
process by condensation of radical specie.
Combustion Control of Pollutant Formation
Historically, combustion processes were operated
to maximize combustion efficiency. This in turn
meant minimum emissions of products of incomplete
combustion, i.e., CO, unburned hydrocarbon, and
carbon paniculate. As a result, if modern combustion
equipment is well maintained and operated, the level
of emission of these pollutants is very low. For
example, a utility boiler is normally operated at less
than 200 ppm of CO in the stack.
Pollutants due only to fuel constituents are
relatively insensitive to changes in the combustion
process. For this reason, development of control
technology for these pollutants, including SOz and
metallic paniculate, has been concentrated in two
areas: (1) removal of these elements from the fuel
prior to combustion, and (2) removal of the
pollutants from the stack gases by scrubbing and/or
precipitation. The major emphasis in fuel conversion
•NOTE. Although EPA's policy is to use metric
quantitative descriptions certain nonmetric units are used in
this paper for convenience. The following factors may be
used to convert to the metric system
1 Btu = 252.00cal, 1 cu ft = 28.32 liters,
1 in. = 2.54 cm; 1 Ib = 0.45 kg;
and5/9(0F-32) = °C.
processes currently under development is tiie removal
of these elements prior to combustion. It is
appropriate to mention here that through the years
the Philosopher's Stone of combustion engineers has
been a magic additive compound which, when added
to the fuel in trace amounts, can remove sulfur oxides
during the combustion process. To date, these
pursuits have been relatively ineffective. The additives
of this type which have been tried require several
times stoichiometric amounts of material, provide
limited removal of sulfur, and double or triple the ash
loading in the flue gas.
In recent years, there has been a growing concern
from the environmental standpoint about the
emissions of nitrogen oxides into the atmosphere by
combustion processes. Of the nitrogen oxides emitted
into the atmosphere, approximately 50 percent
originate from motor vehicle sources. The remaining
50 percent are generated predominantly from
stationary combustion sources. Minor total
contributions, which may be of considerable local
importance, are emitted by nitric acid plants and
other chemical processes. Development of
combustion modification techniques for control of
the formation of nitrogen oxide in the" combustion
process itself has been the main thrust of NO control
research and development efforts in the United
States. There are two mechanisms upon which
modification techniques are based. The first
mechanism is reduction of temperature in the
combustion zone, thereby limiting the fixation of
atmospheric nitrogen and the formation of thermal
NO. This approach involves the introduction of an
inert diluent into the combustion zone or the use of
controlled rapid heat removal to accomplish the
reduction of the temperature. The second mechanism
is the limitation of local oxygen availability. This can
have an effect on thermal NO; however, the
predominant effect is on fuel NO. Although these
two separate factors can be identified, essentially all
practical combustion modification techniques
embody both elements. A brief practical description
of combustion modification techniques is given
below.
The introduction of inert material into the flame
zone can reduce the combustion temperature,
thereby inhibiting formation of thermal NO. The two
common techniques of introduction of inert are flue
gas recirculation and water injection. Flue gas
recirculation involves the removal of cooled flue gas
from the stack of the combustion source at
temperatures of 400° to 600°F* by a fan, and
mixture of this flue gas with the incoming
261
-------
combustion air in proportion up to 30 percent. At 30
percent recirculation, the flame temperature is
reduced by 600° to 700°F which, based on NO
kinetics, should give significant reductions in NO.
There is considerable experimental evidence that flue
gas recirculation is an effective technique for control
of thermal NO from clean fuels including natural gas
and distillate oil (refs. 4,6). Reductions of NO up to
85 percent have been observed at 30 percent
recirculation. The use of flue gas recirculation is
considerably less effective for fuels which contain
significant quantities of chemically bound nitrogen.
Current evidence suggests that NO reductions of 30
percent can be obtained for heavy oil and lesser
reductions for coal by the use of flue gas recirculation
(refs. 5,7). This is attributable to the presence of fuel
NO which is not significantly affected by reduction
of flame temperature. Water injection can be
accomplished by: (1) a direct spray of liquid water
into the combustion zone, (2) the introduction of
steam with either the fuel or the combustion air, or
(3) emulsification of the water with liquid fuel. These
techniques have been tried for both boilers and gas
turbines (refs. 6,8,9). The results for both thermal
and fuel NO are similar to those with flue gas
recirculation.
Staged combustion is based on the operation of the
burners in a fuel rich condition followed by delayed
addition of secondary air to bring the overall
stoichiometry to fuel lean conditions and complete
the combustion. The effectiveness of this technique is
based on a combination of factors. First, the peak
temperature in the initial rich flame zone is reduced,
and heat is removed prior to the addition of
secondary air thereby reducing the peak flame
temperature of the entire process relative to
conventional combustion at the same overall
stoichiometry. This provides a viable control
technique for thermal NO. Second, the presence of
the fuel rich flame zone limits oxygen availability and
thereby provides an effective control technique for
fuel NO. The major applications of this technique to
date have been in utility boilers where significant
reductions for all fuels have been achieved,
particularly when using staged combustion in
combination with low overall excess air (refs. 10.11).
Staged combustion has not been applied to smaller
sources due to process limitations making the
additions of secondary air difficult. However, efforts
are currently underway for the application of this
technique to smaller boilers fueled by natural gas and
residual oil (ref. 12).
Both of the techniques discussed above constitute
what may be called external combustion
modifications. A body of data is rapidly accumulating
to indicate that burner design changes may in fact
achieve the pollutant control objectives without the
necessity for addition of either external inert
injection or second stage air. Key variables in burner
design are: (1) fuel injector type and configuration,
and (2) method of introduction of combustion air. As
with external combustion modification, the type of
burner modification that is used depends on the
nature of the fuel. For gaseous and clean liquid fuels.
where the NO is predominately thermal, the design
should promote relatively rapid air/fuel mixing and
maximize entrainment of relatively cool combustion
products from the recirculation zones near the
furnace boundary heat transfer surfaces (ref. 13). For
fuels containing significant quantities of chemically
bound nitrogen, the burner design should promote
local fuel rich zones in the flame to minimize the
oxidation of the chemically bound nitrogen
compounds and promote formation of N2. The
subsequent mixing of the bulk of combustion air with
the fuel rich products to complete oxidation is
controlled by burner design. For example, Heap has
observed that if pulverized coal is rapidly mixed with
combustion air by radial fuel injection, nitrogen
oxide emissions of 800 parts per million are
produced. Conversely, if the coal is maintained as a
jet with limited primary air and surrounded by a
flame front to delay mixing with the bulk of the
combustion air, these emissions can be reduced to the
level of 150 parts per million (ref. 14). It is obvious
that burner design cannot consider merely nitrogen
oxides. Other factors have to be considered
including: stability of the flame, shape of the flame
relative to the furnace volume, and combustion noise.
All of these are criteria which must be considered for
burner design.
Other control techniques which have been tried
include reduced load, reduced air preheat, and other
measures of this type. Although these measures are
effective in reduction of NO (in some instances), they
can also have an adverse impact on the overall process
efficiency and/or output capacity and are therefore
to be avoided whenever possible.
It is also recognized that in combustion processes
the various problems are truly interrelated and,
ideally, the use of processes which control nitrogen
oxides should not result in emission of products of
incomplete combustion being drastically increased
and/or process efficiency being adversely affected. In
general, the combustion modification techniques for
control of nitrogen oxides are compatible with low
262
-------
emissions of products of incomplete combustion, if
proper design is used. There is also evidence for
staged combustion with utility boilers that the carbon
efficiency, as based on residual carbon in the ash, is
very slightly impacted, even when using a
combination of staged combustion and low excess air
to achieve control of nitrogen oxides from about 900
parts per million to 600 parts per million (ref. 11).
Somewhat more difficult problems have been
encountered with application of combustion
modification techniques, particularly staged
combustion to heavy oil in a smaller class of
equipment; i.e., package boilers (ref. 15). In these
experiments, an increase in smoke has accompanied
significant decreases in nitrogen oxides. These
problems should be overcome as a result of ongoing
research.
The other consideration mentioned is overall
process efficiency. Certain of the control techniques,
particularly the ones involving inert injection and
reduction of preheat, can adversely impact the overall
process efficiency. A strong consideration in the EPA
program for development of NOX control techniques
has been to avoid any significant reduction in the
process efficiency. This goal appears to be within the
realm of the possible. Evidence on utility boiler
testing suggests that the combination of staging and
low excess air may, in fact, slightly improve the
overall boiler efficiency (ref. 11).
Fuel Properties
Based on the foregoing discussion, it is obvious that
one of the first subjects that must be addressed when
considering the environmental aspects of the
combustion of fuels resulting from various fuel
cleaning processes is the properties of those fuels
themselves. Two areas of interest are: (1) trace
constituents, such as nitrogen compounds, sulfur
compounds, and metals present in the fuel product;
and (2) any natural diluent in the fuel.
A summary of information for selected gaseous
fuels is presented in table 1. The fuels represented are
three classes of "synthetic" fuels: low-Btu gas,
medium-Btu gas, and synthetic natural gas (SNG),
with two types of natural gases shown for compariso i
(refs. 16,17). The only "trace element" information
is on hfeS, which varies not only with process, but
also with the parent coal. No information on nitrogen
compounds or metals is available. There is some
indication that a significant amount of ammonia is
produced in some fuel conversion processes. It should
be pointed out that these are compositions at the
gasifier exit, without cleanup processes to remove
H2S and other trace compounds.
A summary of information on selected liquid fuels
is given in table 2. The "synthetic" liquid fuels
include coal-derived oil, shale-derived oil, and
methanol (refs. 16,18). The residual and distillate fuel
oil properties presented for comparison are for the
oils used in EPA/CRS in-house research and are
"representative" of the fuel oils sold on the east
coast. The coal-derived and shale-derived oils are
uniformly lower in sulfur than the residual oil, but
higher in nitrogen by factors of 3.5 to 7. The
hydrotreated COED oil shows negligible levels of
sulfur and nitrogen. The alcohol fuel properties are
for pure methanol, as no information on "synthetic"
fuels derived from coal was available. The alcohol
fuels will almost certainly contain significant amounts
of higher alcohols and possibly other hydrocarbons.
EMISSION CHARACTERISTICS OF ALTERNATE FUELS
Information on the combustion and emission
performance is unavailable for most of these alternate
fuels. In many cases this can be attributed to the
early state of development of the fuel conversion
process. The emphasis to date has been on the
properties of the fuel and the limited quantities of
fuel which have been produced but have not been
sufficient for combustion characterization. It is
possible that some testing has been done and the
results have not been published.
There is a scattering of information which is
available on alternate fuels. In addition, there is a
substantial body of information on combustion and
emission characteristics of conventional fossil fuels.
This section will attempt a synthesis of this
information to give some indication of potential
pollutant emission problem areas and to point out
gaps in existing knowledge. The major discussion will
center on the formation and control of nitrogen
oxides since this is the area of combustion generated
emission control about which the most is known. The
experimental data shown in the figures has been
recently generated, and more detailed presentations
will be made at a later date Other emissions are also
considered, based on available information. In the
following discussion, fuels having similar
characteristics are considered as a group.
Synthetic Natural Gas
The composition of SNG appears to be very similar
to that of natural gas. The primary difference is the
263
-------
Table 1. Comparison of various gaseous fuels
1
Type of Fuel
Toxarkana Natural Gas'-3''
Cleveland Natural Gas^
Synthetic Natural Gas
Koppc rs -Tot zek (b )
Synthetic Natural Gas
LurgiC')
Medium BtU Gas.., .
Koppc rs -Tot zok * •*
MoUium £tu Gus
Lurgi fb J
Low BtU Gas-LurgiOO
Low BtU> Cns-Winklcr^b)
Low Btu Gas-Hygas(b)
Low Btu Gas - U-Gas^
ligher Heating Value
BttfFT3 (Dry)
967
1131
962
980
298
302
180
118
236
ISO
Gas Composition, Mole '
To
0
0
0.08
0
50.4
9.2
13.9
19.0
13.5
17
H2
0
0
2.S
0.8
33.1
20.1
19.6
11.7
16.6
11.6
dl4
96.0
80.5
94.2
96.8
0
4.7
5.5
0.5
8.4
4.1
C2H6
0
18.2
0
0
0
0.5
0
0
0.6
-
co2
0.8
0
0.4
1.2
5.6
14.7
13.3
6.2
12.7
8.8
N2
3.2
1.3
2.8
1.1
0
0
37.5
51.1
28.9
45.4
H20
0
0
0
0
I
9.6
50.2
10.1
11.5
18.2
12.0
H2S
0
0
0
0
0.3
0.6
0.6
0.13
0.8
0.6
(&) Handbook of Chemical Engineering, John H. Perry-Editor, 3rd Edition.
(b) "Clean Fuels from Coal-Symposium Papers," Institute of Gas technology, Sept. 10-14, 1973.
-------
Table 2. Comparison of various liquid fuels
Fuol
Distillate Oil(a)
Residual Oil (B)
COI-I) Crude (b)
C01-I)00
liyd retreated
SynthoilO5)
H-Coal Crude ^
M-Coal Low Sulfur
Fuel 00
Toscoal Oilfb5
Shale Oil
Alcohol Fuel
Higher Heating Value
Btu/LB
19,300
18.980
-
-
16,800
-
-
16,200
18.700
9,578
Ultimate Anal)
C
86.9
86.8
83.0
88.0
89.6
-
80.7
84.6
37.5
II
13.1
12.5
8.4
11.6
7.6
9.5
8.4
9.1
11.7
12.5
N
0.023
0.22
1.1
0.01
0.9
0.68
1.05
0.7
1.77
0
'sis, Weight %
S
0.096
0.89
0.35
0.01
0.31
0.19
0.43
0.2
0.76
0
0
0
0
7.15
0.38
1.6
-
-
9.4
50
Ash
< 0.002
0.03
0
0
(1.3)
-
-
0.2
0.01
0
API Gravity
Degrees
35
- 4
24.5
1.126 SplGr.
a 60/60° P
15
4.4
4.5
Sp.Gr. 60/60
0.903
NA
01
CRS in-house fuels
"Clean Fuels from Coal-Symposium Papers," Institute of Gas Technology, Sept. 10-14, 1973.
-------
presence of 1 to 3 percent of hydrogen in the SNG.
The only data on trace constituents show the
hydrogen sulfide content of the SNG to be zero.
There is no direct data on nitrogen compounds,
although mention is made of ammonia as a byproduct
stream from a scrubber used to remove H2Sfrom the
synthesis gas (ref. 16). This raises an interesting
aspect of the environmental impact of the fuel
conversion process as the possibility of using the
ammonia as an onsite boiler fuel is mentioned. No
details are given; however, it might be assumed that
the ammonia would be fired in combination with a
supplemental fuel, such as natural gas. Available
small-scale combustion experiments indicate that,
dependent on system design, substantial
concentrations of nitrogen oxides could be present in
the boiler flue gas (ref. 19). The conversion to
nitrogen oxides would depend on ammonia
concentration, identity of second fuel, point of NHs
injection, overall excess air, and other factors;
therefore, no quantitative assessment can be made.
However, if all the coal nitrogen is converted to
ammonia in the process and subsequently burned, the
total NO emissions could equal or exceed those from
direct combustion of the parent coal. The conversion
can be limited by proper design of the combustion
system, and this should receive careful consideration
at any installation where disposal by combustion is
anticipated.
The SNG should be indistinguishable from natural
gas in conventional combustion equipment. The only
exceptions may be slightly wider flammability limits
due to the presence of hydrogen and the potential for
fuel NO formation if any bound nitrogen compounds
(NHa, HCN, etc.) are present in the product gas. The
principal source of NO would be thermal fixation,
which can be controlled by any of the techniques
previously mentioned. Products of incomplete
combustion will not be significant with proper system
design, as is the case with natural gas.
Medium-Btu Gas
The synthesis gas fed to the SNG plant is generally
a medium-Btu gas (about 300 Btu/ft3) produced by
an oxygen blown gasifier. The main constituents are
carbon monoxide and hydrogen, however, large
concentrations of water can also be present in the
products of certain gasifiers. Although it is not
normally considered in the United States, the
possibility of firing this gas directly (after sulfur
cleanup) does exist and should be considered here.
The potential advantage compared to low-Btu gas is
that smaller volumes of relatively nitrogen-free fuel
gas need to be handled for the same Btu input to the
furnace. The potential disadvantage is that the
theoretical flame temperature is greater than that for
methane, which could lead to high thermal NO
emissions.
In this context a point worth considering is the use
of this medium-Btu gas in a steam generator
specifically designed to be oxygen fired. Since this
could necessitate a considerable departure from
current design practice, the final resolution will
probably be based on economics as well as technical
considerations. The advantages include smaller boiler
size, higher combustion temperature, better heat
transfer, and lower energy loss in the flue gas.
Potential disadvantages are that problems may be
encountered in finding economical materials and
boiler construction to handle the higher
temperatures, and the cost of the oxygen being used
for combustion may be prohibitive. In the past, the
cost of the oxygen appears to have been one of the
main barriers to the concept; however, the presence
of an oxygen plant on the gasification site and the
projected higher cost of synthetic fuels may alter this
conclusion. The impact of this concept on pollutant
emissions is unknown at this time, but the following
arguments can be considered. Even though the
combustion temperature would be greater than
4,000°F, the thermal NO formation would be
insignificant if the fuel gas were completely free of
nitrogen. However, the analysis of the
Koppers-Totzek gas shows about 1 percent Na. and
the possibility exists that this small amount of
nitrogen could be converted nearly quantitatively to
NO at these temperatures. Similarly, the nitrogen
imputiries in the oxygen must also be taken into
account. In addition the system would operate at
initial temperatures at which the CO/CO2 equilibrium
is strongly shifted to CO. This would necessitate
careful heat exhange design to avoid quenching too
rapidly, resulting in large concentrations of CO,
which represent both a pollutant and an energy loss
from the system.
Low-Btu Gas
The final gaseous fuel being considered is low-Btu
which is produced in air-blown gasifiers. This fuel gas
contains between 30 and 50 percent molecular
nitrogen and has heating values between 100 and 240
Btu per cubic foot. The principal fuel constituents are
CO, H2, and CH/j, in proportions dependent on the
specific process. Similar comprehensive information
266
-------
on trace elements other than HjS and COS is not
available. The concentration of HzS must be reduced
before the gas can be burned and. based on previous
information on medium-Btu synthesis gas cleanup, it
might be expected that nitrogen compounds and
metals would be removed as well.
The other potentially significant variable is the fuel
gas temperature as delivered to the burner of the
combustion system using the low-Btu gas. This will
depend on two factors: (1) the analysis of optimum
gasifier/combustor system configuration based on an
analysis of cost and energy efficiency; and (2) the
development of high temperature (1,000°F) cleanup
processes if these are warranted. (Note both of these
aspects are being considered in ongoing EPA
contracts with Ultrasystems and UARL, respectively.)
The fuel gas temperature has a direct bearing on both
furnace efficiency and pollutant emission.
Robson has reported that, if high temperature
processes are used to remove the H2S, the resultant
clean fuel gas can contain 0 38 percent NHa (ref. 20).
If this NHa were quantitatively converted to NO in
the combustion process, the resultant fuel NO level
would be 2000 ppm. The actual level of conversion
would depend on the system design; however, for
conventional practice a 50 percent conversion or
1000 ppm might not be unrealistic. The burner
and/or system can certainly be designed to minimize
the conversion; however, some further R & D
addressed to this specific point may be required.
The theoretical flame temperature is a function of
the inlet temperature of the fuel gas. If low-Btu gas
temperatures of 70 and 1,000°F are assumed, the
theoretical flame temperatures are approximately
3.000° and 3,450°F, respectively. As previously
indicated, lower flame temperatures may result in
lower NO emissions and thermal efficiency. For
purposes of comparison the theoretical flame for
natural gas is 3,550°F, and significant thermal NO
formation can occur.
Another uncertainty with low-Btu gas is the effect
on burner design, particularly fuel injector, and
air/fuel mixing configuration. For methane
combustion the fuel stream represents approximately
8 percent of the total air/fuel mixture, whereas, for
low-Btu gas, the fuel gas is approximately 50 percent
of the total. Also, for a constant injector area, the
fuel gas velocity, which may be a significant factor
influencing emission levels, will increase by a factor
of approximately 3 if the gas temperature is raised
from 70° to 1,000°F. No information is available on
the effects of these burner parameters on combustion
and emission performance of low-Btu gas.
The low-Btu gas produced specifically as a
sulfur-free fuel derived from coal is envisioned as
being burned onsite in two types of practical
combustion systems, utility boilers and gas turbines.
Although various forms of low-Btu gas produced as
byproducts from industrial processes (e.g., blast
furnace gas) have been burned for a long time in
industrial boilers, either singly or in combination with
natural gas, emission data for these practical
combustion systems are not documented. It is
fortunate that some experimental information has
become available recently.
Under EPA Contract 68-02-0202. the International
Flame Research Foundation of Umuiden, Holland,
has run a series of experimental trials to establish
burner design criteria for control of NOX emissions
from heavy oil and pulverized coal, with limited use
of gaseous fuels for purposes of establishing baselines.
In the AP-3 trial recently concluded, some runs with
a simulated low-Btu gas were made (ref. 21). This gas
was basically a blast furnace gas doped with
approximately 6 percent methane to raise the heating
value to about 180 Btu/ft3, which is quite similar to
the low-Btu gas composition produced by most
gasif iers. This gas was fired singly and in combination
with additional natural gas at a total heat input of 4.5
x 106 Btu per hour with 15 percent excess air. The
fuel injector and combustion air inlet areas were
constant. The combustion air was introduced at
300°C and over a range of swirl values. The results for
a highly cooled furnace are shown in figure 1. For
these conditions, the NO emissions for 100 percent
natural gas range from 47 to 62 ppm as a function of
swirl; whereas, for 100 percent "low-Btu gas" the NO
emissions were below the detection limit (4 ppm).
These emission trends are consistent with the
measured axial (maximum) temperatures of the
combustion gases near the burner, which were 1,530°
and 1,200°C, respectively. An interesting feature of
the profiles is that the temperature difference
decreases until at 2 meters it is only 100°C,
suggesting that perhaps the heat release zone of the
low-Btu gas is stretched out (i.e., the combustion
intensity is reduced). Both decreased peak
temperature and decreased combustion intensity
would tend to produce low NO emission. It can also
be seen from figure 1 that the first increment of
low-Btu gas (33 percent of the heat input) has the
largest effect on NO emissions (i.e., about 60 percent
reduction), which is similar to results previously
observed for external diluent addition by flue gas
recirculation (ref. 6). CO emissions in the flue were
comparable for natural gas and the low-Btu gas. Axial
267
-------
50
- 40
UJ
O
X
O
O
oc
30
20
10
PERCENT NATURAL GAS
A67 PERCENT NATURAL GAS - 33 PERCENT LOW Btu GAS,
Q33 PERCENT NATURAL GAS - 67 PERCENT LOW Btu GAS
100% LOW Btu GAS BELOW DETECTION LIMIT
I \ \ I
8
10
RELATIVE SWIRL INDEX, Rs
Figure 1. Nitrogen oxide emissions as functions of combustion
air swirl and fuel gas composition
268
-------
profiles of CO concentration were obtained and will
provide further information on fuel burn-out and
heat release patterns. The data is not available at this
time.
The other application of low-Btu gas is to gas
turbines for which a number of combustor inlet
parameters are significantly different from those for
boilers. A generalized summary is presented in table
3. Most of these conditions can have a significant
effect on the emissions of NO. Fortunately, there has
also been data recently published dealing with
combustion of a low Btu gas in an experimental
combustor simulating a combustor can (ref. 23). The
combustor operated at low pressure (less than 40
inches of Hg absolute), but with air preheat up to
1,250°F to simulate compression heating. The
observed NO levels for the low-Btu gas were zero to
10 ppm and for natural gas were 20 to 25. (It is not
stated if the NO levels are as measured or corrected to
some standard basis. It is noted that there was a 1.8
to 5.6 ppm contribution to these levels from the
direct fired preheater.) Based on these numbers,
Klapatch projects NO emissions from a TPM FTHC-1
(10-30 MW) gas turbine fired on low-Btu gas to be 50
percent and 65 percent less than the emissions for
natural gas and No. 2 oil, respectively. The CO
emissions for the experimental combustor on low-Btu
gas were 3 to 4 times those for natural gas; however,
it is also projected that proper design can produce
equivalent levels for an actual engine. The stability
limits for the low-Btu gas appear to be wider than
those for methane.
Both sets of data tend to substantiate the projected
low NO emission levels for combustion of low-Btu gas
at70°F.
Synthetic Oil
The properties of the synthetic oil products in table
2 appear to be generally similar and, therefore, the
discussion of coal-derived oils and shale oil will be
covered as a single topic.
API gravity was the most commonly supplied
physical property of the "crude" oils. The gravity was
generally 5° API or less, which can be compared to a
"typical" residual oil gravity of 12° API. This
indicates a rather dense product which could be
handled by a fuel system but would probably present
flow difficulties. Viscosity information was presented
in a wide variety of units and/or at several
temperatures making comparison of flow properties
laborious. The oil physical and chemical properties
appear to vary as a function of parent coal and
processing conditions. It may be assumed that at least
limited processing will be necessary to obtain a
suitable boiler fuel. One example of a hydrotreated
oil produced a product upgraded to 24.5° API with
essentially complete heteroatom removal (ref. 16). As
with other aspects of the fuel conversion process, the
amount of treatment given the "crude" oil will be
dependent on the end use of the product,
environmental considerations of use, and the
economic factors involved in each of the two
preceding factors.
The sulfur level in most of the crudes is less than
0.4 percent which is close to some current east coast
sulfur regulations for residual oils (0.3 percent in
some States). Economics might suggest combustion
of these oils directly or with minimum treatment
necessary to improve flow properties. From an
environmental point of view, one of the problems
then becomes fuel NO from the chemically bound
nitrogen which ranges 0.7 to 1.77 percent. (This
would correspond to 1,050 to 2,500 ppm NO if
completely converted to NO and possibly 400 to
1,000 based on experience with actual levels of
conversion.) The control of this fuel NO may be
accomplished by staged combustion and/or burner
design dependent on several factors. For convenience,
chemically bound nitrogen can be divided into two
Table 3. Comparison of operating conditions for modern utility
gas turbines and boilers firing natural gas
Equipment Type
Pressure, atm
Air preheat, °F
Overall excess air,
percent
Boiler
1
600
10
Gas Turbines (22)
greater than 9
600 or greater*
greater than 200
Depends on Pressure Ratio and Use of Regeneration.
269
-------
classes: (1) "volatile" compounds which are evolved
early in the combustion process; and (2) "refractory"
compounds which are burned out along with the
char. These classes are intuitively defined, based more
on'speculation over experimental combustion results
than by scientific tests. However, it should be
mentioned that some analyses show that 50 to 60
percent of the nitrogen in high volatile bituminous
coal is contained in the matter evolved during the
ASTM standard "volatile" test (ref. 24). In the case
of petroleum, the terms have somewhat less meaning
as the nitrogen and sulfur heteroatoms tend to be
quite refractory and concentrate in the heavy ends
(e.g., residual oil) and any "volatile" nitrogen is
determined by fuel pyrolysis in the flame. The
available information does not give any indication of
the distribution of nitrogen compounds in the
synthetic crudes. This presents difficulties in assessing
the potential effectiveness of control techniques.
In general, results of combustion experiments
appear to fall into the two categories related to the
nitrogen classes discussed above. In the first category
are results of combustion of fuels with high levels of
"volatile" nitrogen compounds. Much of the early
work on control of fuel NO was based on distillate oil
doped with relatively low boiling heterocyclic
nitrogen compounds, such as pyridine (refs. 3,4). This
represents a case of 100 percent volatile nitrogen, and
conversion levels of 50 to 60 percent to NO were
observed. When staged combustion techniques were
applied, the level of fuel NO could be reduced from
750 ppm at 120 percent of theoretical air through the
burner to about 100 ppm at 70 percent theoretical air
through the burner and 120 percent overall (ref. 4).
There is evidence to show that the predominant
source of NO from coal is fuel nitrogen. Pershing has
experimentally compared NO emissions from
combustion of pulverized coal in air (1,030 ppm NO)
to those for Argon/21 percent oxygen mixture (900
ppm) at 120 percent theoretical oxygen and has
confirmed the hypothesis that fuel NO is relatively
independent of flame temperature (ref. 7). Heap has
shown that the NO emissions from pulverized coal
can be reduced from 800 ppm to about 150 ppm by
change in burner operating parameters and has
proposed an hypothesis based on conversion of
volatile fuel nitrogen compounds (ref. 14). In all of
these cases of "volatile" fuel nitrogen, significant
reductions in NO have been achieved by producing a
fuel rich zone early in the combustion process by
either "staged" combustion or alteration of the
air/fuel mixing patterns by burner changes. These
reductions in NO can apparently be achieved without
apparent increases in carbon loss (smoke, CO, etc.).
The results on the second category of fuels having
refractory nitrogen (e.g., residual oil) are somewhat
mixed. Turner has reported reductions of fuel NO of
40 to 50 percent (200 ppm fuel NO down to 100
ppm) in a refractory-lined package boiler without
significant increases in smoke (ref. 5). On the other
hand, Muzio has conducted experiments in a
Dowtherm cooled unit (450°F wall temperature) and
has encountered smoke problems, with staged
combustion producing only 25-30 percent reduction
in total NO. By combining flue gas recirculation and
staged combustion, a 45 percent reduction in total
NO was achievable (ref. 15). The results of Muzio
may be a function of the burner configuration tested
or of differences in the fuel used. In the AP-2 trials at
the IFRF, Heap found the NO emissions for residual
oil to be much less sensitive to burner parameters
than coal was. The range of NO observed was from
250 ppm to 150 ppm at equivalent conditions (ref.
25).
These results may indicate the sensitivity of fuel
NO emission from oil combustion to "volatile"
nitrogen content (e.g., 85 percent reduction of fuel
NO for doped distillate versus 25 to 40 percent for
residual). In addition, they show that the production
of carbon paniculate (smoke) is dependent on system
parameters and, possibly, on the fuel properties as
well. As a result, all that can be definitely stated at
this time is that combustion modification techniques
are potential control methods for fuel NO from
synthetic crudes from which significant amounts of
fuel NO can be expected, and that the effectiveness
will depend on the distribution of nitrogen
compounds in the synthetic oils.
Alcohol Fuels
Alcohol fuels have a number of uncertainties
associated with them, including potential sources.
The principal current source appears to be as an
alternative to LNG; however, one or more fuel
conversion processes producing alcohol fuels from
coal, refuse, or other waste material seem to be a
distinct possibility. The alcohol fuel may have a
variety of compositions; however, a probable
composition is 90 plus percent methanol with the
balance composed of higher alcohols. From an energy
standpoint, methanol (CHaOH) can be viewed as a
mixture of 47 mass percent distillate oil (CHj) and
53 mass percent water. The energy content (HHV)
per Ib of CH2 is then very close at 20,200 Btu for
methanol versus 19,300 for a distillate oil. The other
270
-------
physical properties are obviously quite different with
methanol boiling at 149°F versus an endpoint of over
700°F for a distillate oil The "water" content of
methanol is a disadvantage as it represents a mass of
inert matter which must be transported and
constitutes an additional source of heat loss in the
combustion products. However, it may offer an
advantage from the environmental aspects.
The author is conducting an EPA/CRS in-house
experimental study on the characterization of
combustion and emission characteristics of future
fuels. The experimental system is a refractory wall
combustor fired at a nominal 300,000 Btu per hour.
Comparisons have been made between alcohol fuels
and conventional fossil fuels. Some prelinimary data
is shown in figure 2. The results shown are at 5
percent excess air without air preheat and with the
refractory temperature above 2,500°F. Three features
of the data are obvious: (1) the NO emissions for
methanol are a factor of 4 less than distillate oil and a
factor of 3 less than propane; (2) increasing the
content of higher alcohols appears to increase NO
emissions; and {3) although the alcohol fuels are
liquid the emission trends with air swirl appear to
follow those of gaseous propane.
For a distillate oil at 5 percent excess air, the
nominal air to fuel mass ratio is 16. For the same heat
input, methanol is equivalent to 16 masses of air, one
of fuel, and one of water, or the inlet mixture is 5.5
percent "water." In this case, approximately a 66
percent NO reduction is achieved relative to propane.
For comparison, Halstead achieved approximately a
65 percent reduction in NO by injecting 5 percent
liquid water as a spray into a natural gas flame (ref.
6). The increase in percentage of higher alcohols also
decreases the "diluent water" in the fuel, thereby
increasing the theoretical flame temperature and
increasing thermal NO. Finally, the appearance of the
methanol flame was observed to be more similar to a
gas flame (nearly nonlummous) than to an oil flame.
This is probably due to very rapid vaporization of the
methanol m the hot refractory chamber, coupled
with lack of high boiling hydrocarbons which crack
to form luminous soot particles. This behavior could
account for the similarity of the trend of NO versus
swirl to propane. Finally, since the "water" is not
actually present in that form in the fuel, chemical
effects may also play a role.
In all of these tests, the level of CO and unburned
hydrocarbons was less than 30 ppm. However, it
should be pointed out that under relatively cold wall
conditions found in furnaces and boilers, the high
"water" content of methanol could produce a quench
effect leading to emission of products of incomplete
combustion, particularly oxygenated hydrocarbons,*
unless the system is properly designed.
The potential energy inefficiencies associated with
alcohol fuels are. (1) lower flame temperature
limiting heat transfer; and (2) latent and sensible heat
losses in the flue gas (e.g., for 20,000 Btu of
methanol a 2 Ib mass is required, 1 of which is
"water." Considering only the 1,000 Btu/lb latent
heat to form steam, at least 5 percent of the Btu is
unrecoverable).
Combined Fuel Firing
One concept has been to convert coal to a
sulfur-free, low-Btu gas, which is burned in a boiler
on the gasifier site. Dependent on the fuel conversion
process and system optimization, the overall
efficiency of the gasifier may result in an energy loss
equivalent to at least 15 percent of the heating value
of the coal (ref. 16), which is apparently prior to any
fuel cleanup. The author would like to propose a
concept which might satisfy environmental
requirements and also offer an energy saving.
The current EPA New Source Performance
Standard for sulfur oxide emissions from a utility
boiler is 1.2 Ib SOa per million Btu input. If a boiler
fired with a combination of coal and low-Btu gas
were to be regarded as a coal-fired power plant, the
sulfur oxide standard could be met by firing 25
percent of the Btu input as a 3 percent sulfur coal
with 12,500 Btu per Ib or 50 percent of a 1 percent
sulfur coal with 8,300 Btu/lb and the balance of the
heat input as a zero percent sulfur low-Btu gas. The
potential energy savings are 4 and 8 percent,
respectively. This savings on energy input needs to be
balanced against requirements imposed on particulate
removal from the flue gas and other considerations.
Now let us consider the impact on other emissions.
Although the data on the proposed fuel mix is not
available at this time, some data has been generated in
the recent AP-3 trial at the I FRF (ref. 21). Data on
NOX emissions for 100 percent coal, 67 percent coal,
and 33 percent simulated low-Btu gas, and 100
percent low-Btu gas were generated and are presented
in figure 3. The low-Btu gas NOX emissions were less
than 10 ppm at these conditions. If this is averaged
on a 33 to 67 basis with the results of firing 100
percent coal, the result is the solid line (i.e., as if the
fuels were fired separately). However, when the coal
and low-Btu gas are mixed and introduced through
the same injector, the lower curve results. Although
this data is far from definitive and no attempt was
271
-------
400
350
300
250
J8
i 200
\u
Q
X
o
1 is.
100
50
PROPANE
50% METHANOL
50% ISOPROPANOL
02468
SWIRL BLOCK POSITION
Figure 2. Comparison of nitric oxide emissions from
combustion of distillate oil, propane, and three alcohol fuels
272
-------
1
800
700
600
500
I
uf
§ 40°
O
o
E
H
300
200
100
O 100 PERCENT COAL
A 67 PERCENT COAL - 33 PERCENT LOW Btu GAS
— NUMERICAL AVERAGE
— 100 PERCENT LOW Btu GAS NO. WAS LESS THAN 10
RELATIVE SWIRL INDEX
Figure 3. Nitrogen oxide emissions as a function of
combustion air swirl and coal-blast furnace gas ratio
273
-------
made to optimize the NOX reduction, it does indicate
that combined firing of coal and low-Btu gas can
actually reduce overall NOX emissions.
SUMMARY
It is clear that the state of knowledge both of
detailed composition of alternate fuels and of the
environmental impact of utilizing these fuels in
combustion processes is relatively limited. The main
thrust of fuel conversion processes is to produce
sulfur-free fuels for a variety of end uses and to
remove ash as a part of the bargain. This reduces or
eliminates two major pollutants normally produced in
direct coal combustion. The pollutants which remain
to be dealt with are nitrogen oxides, products of
incomplete combustion, and, possibly, trace metals.
Combustion modification appears to have good
potential for control of nitrogen oxides for the
alternate fuels which are not inherently low NOX
emitters. Proper system design, based on combustion
characteristics of the fuels, should eliminate products
of incomplete combustion. Trace metals emissions
will depend primarily on the characteristic of the
fuel, and control will depend on removal at the fuel
production site or from the flue gas.
To allow minimum environmental impact of
combustion of alternate fuels, a body of information
still remains to be generated, including the following:
1. Characterization of trace elements including
nitrogen and sulfur compounds, and metals present in
the full range of gaseous fuels.
2. For low-Btu gas, the effect of fuel
temperature and air preheat on emission
characteristics needs to be established. Information to
allow burner and combustion system design for
minimum pollutant formation compatible with
maximum thermal efficiency must be established.
3. Quantitative information on the influence of
high temperature (-(28 removal processes on the
concentration of other trace elements in fuel gases
needs to be established.
4. The fate of ammonia generated as a
byproduct of fuel conversion processes and design
criteria defined for low-NO combustion need to be
established.
5. Characterization of the nitrogen and oxygen
compounds contained in synthetic liquid fuels.
6. For synthetic crudes, combustion and
emission characteristics as a function of fuel
properties and extent of fuel processing need to be
established. Special emphasis needs to be placed on
evaluation of burner design and staged combustion
for control of both NO and smoke.
7. The potential for formation of oxygenated
hydrocarbons from fuel constituents and control
requirements need to be established for all fuels, but
especially alcohol fuels.
8. Further evaluation of combined firing of coal
and low-Btu gas for pollutant control needs to be
explored and system design criteria established.
9. Characterization and end use of combustible
solid residue byproducts of the processes need to be
established.
10. Critical analyses of the relationship of
pollution control options to overall energy efficiency
need to be carried out for each class of fuel.
11. The fact that unconventional
fuels-generation processes are being developed, which
may result in substantial increases in fuel cost,
indicates that careful thought needs to be given to
combustion system design with both environmental
and energy efficiency considerations taken into
account. On this basis, considering the systems as a
whole, some dramatic departures from past practice
may be justified.
REFERENCES
1. Y. B. Zeldovich, P. Y. Sadonikov, and D. A.
Frank-Kamenetskii, "Oxidation of Nitrogen in
Combustion," Academy of Sciences of USSR,
Institute of Chemical Physics,
Moscow-Leningrad, 1947.
2. D. W. Pershing and E. E. Berkau, 'The Chemistry
of Nitrogen Oxides and Control through
Combustion Modification," Pollution Control
and Energy Needs. ACS Symposium Series #127,
pp. 2I8-240, 1973.
3. G. B. Martin and E. E. Berkau, "An Investigation
of the Conversion of Various Fuel Nitrogen
Compounds to Nitrogen Oxides in Oil
Combustion," AlChE/Symposium Series, Air
Pollution and Its Control, Volume 68,1972.
4. G. B. Martin and E. E. Berkau, "Evaluation of
Various Combustion Modification Techniques for
Control of Thermal and Fuel-Related Nitrogen
Oxide Emissions," 14th Symposium
(International) on Combustion, Pennsylvania
State University, August 1972.
5. D. W. Turner. R. L. Andrews, and C. W.
Siegmund, "Influence of Combustion
Modification and Fuel Nitrogen Content on
Nitrogen Oxides Emissions from Fuel Oil
Combustion," presented at 64th Annual AlChE
Meeting, San Francisco, November 1971.
274
-------
6. C. J. Halstead, C. D. Watson, and A. J. E. Munro,
"Nitrogen Oxides Control in Gas-Fired Systems
Using Flue Gas Recirculation and Water
Injection," presented at the IGT/AGA
Conference on Natural Gas Research and
Technology. Atlanta, Ga., June 1972.
7. D. W. Pershing, G. B. Martin, and E. E. Berkau,
"Influence of Design Variables on the Production
of Thermal and Fuel NO from Residual and
Coal." presented at the 66th Annual AlChE
Meeting, Philadelphia, Pa.. November 1973.
8. D. W. Turner and C. W. Siegmund, "Control of
NOX from Fuel Oil Combustion: Water in Oil
Emulsion," presented at the Winter Symposium
of the IEC Division of ACS, 1973.
9. P. P. Singh, W. E. Young, and M. J. Ambrose,
"Formation and Control of Oxides of Nitrogen
Emissions from Gas Turbine Combustion
Systems," ASME Paper No. 72-GT-22, December
1971.
10. W. Bartok, A. R. Crawford, and G. J. Piagari,
"Systematic Field Study of NOX Emission
Control Methods for Utility Boilers," Esso
Research and Engineering Company Final Report
No. GRU.4G No. 71, Contract No. CPA70-90,
NTIS No. PB-210-739, December 1971.
11. A. R. Crawford, E. H. Manny, and W. Bartok,
"NOX Emissions Control for Coal-Fired Utility
Boilers," EPA Coal Combustion Seminar,
Research Triangle Park, N.C., June 1973.
12. "Development of Low Emission Combustion
Systems Utilizing External Flue Gas
Recirculation and Delayed Combustion Air
Addition, Ultrasystems," EPA Contract No.
68-02-0222.1971-1974.
13. M. P. Heap, T. M. Lowes, and R..Walmsley, 'The
Effect of Burner Parameters on Nitric Oxide
Formation in Natural Gas and Pulverized Fuel
Flames," presented at the AFRC/EPA "American
Flame Days," Chicago. III. September 1972.
14. M. P. Heap, T. M. Lowes, R. Walmsley, and H.
Bartelds, "Burner Design Principles for Minimum
NOX Emissions," EPA Coal Combustion Seminar,
Research Triangle Park. N.C.. June 1973.
15. L. J. Muzio. R. P. Wilson, and C. McCoomis,
"Phase II report on Development of Low
Emission Combustion Systems Utilizing External
Flue Gas Recirculation and Delayed Combustion
Air Addition/' (in preparation).
16. Proceedings of Clean Fuels from Coal
Symposium. Institute of Gas Technology,
Chicago, III. September 1973.
17. Handbook of Chemical Engineering, J. H. Perry
(Ed.), 3rd ed p. 1577, McGraw-Hill Book Co.,
Inc., 1950.
18. Technical Data on Fuel, H. M. Spier (Ed.), 6th
ed, p. 272, The British National Committee of
the World Power Conference, 1962.
19. A. F. Sarofim, G. C. Williams, M. Modell, and S.
M. Slater, "Conversion of Fuel Nitrogen to Nitric
Oxides in Premixed and Diffusion Flames,"
presented at the 66th Annual AlChE Meeting,
Philadelphia, Pa., November 1973.
20. F. L. Robson and A. J. Giramonti, 'The
Environmental Impact of Coal-based Advanced
Power Systems," presented at the EPA
Symposium on the Environmental Aspects of
Fuel Conversion Technology, St. Louis, Mo., May
1974.
21. M. P. Heap, Personal Communication of AP-3
Trial Results. May 1974.
22. Personal Communication, G. E. Utility gas
turbine.
23. R. D. Klapatch and G. E. Vitti, "Gas Turbine
Combustor Test Results and Combined Cycle
System," Combustion Vol. 45, No. 10, pp.
35-38, April 1974.
24. EPA Internal Report, Analysis of EPA In-House
Bituminous Coal.
25. M. P. Heap. Unpublished data from AP-2 and
AP-3 trials, 1973 and 1974.
275
-------
276
-------
STATUS OF FLUE GAS DESULFURIZATION TECHNOLOGY
Frank T. Princiotta*
Abstract
A comprehensive discussion describing the status of
flue gas desulfurization (FGD) technology is
presented. Information is included which lists
operating and planned commercial FGD systems in
the United States and Japan, SO? removal efficiencies
achievable, typical capital and operating costs, other
environmental considerations (e.g., sludge disposal),
retrofit considerations, and barriers retarding rate of
FGD system installation. Also included is a
description of lime/limestone, double alkali,
magnesium oxide, Wellman Lord and Catalytic
Oxidation FGD systems including advantages,
disadvantages, and operational status. Summaries of
operational status of operating United States and
selected Japanese FGD full-scale systems are also
presented.
INTRODUCTION
Flue Gas Desulfurization (FGD) systems can be
classified in two general categories: (a) systems in
which the sulfur product is disposed of as waste
(throwaway product systems), and (b) systems in
which the sulfur product, such as sulfuric acid, is
marketed (saleable product systems). The following
commercially offered throwaway and saleable
product systems are considered the most important
for near term (through 1980) SO2 control (ref. 1).
Throwaway Product Systems
Lime Scrubbing
Limestone Scrubbing
Double Alkali
Saleable Product Systems
Magnesium Oxide Scrubbing
Wellman Lord (Sodium Sulfite
Scrubbing)
Catalytic Oxidation
•Frank T. Princiotta is in the Control Systems Laboratory
of the Office of Research & Development, National
Environmental Research Center, U.S. Environmental
Protection Agency, Research Triangle Park. North Carolina.
An FGD system which best meets the specific
requirements of a given SO2 control problem can be
selected from this list of available systems. (A
description of each of these systems is presented in
appendix A. The information in appendix A includes
process descriptions, history and operating experience
of the systems, advantages and disadvantages of the
systems, and SO2 removal efficiencies. Also, a
performance and reliability summary is included for
each system.)
OPERATING AND PLANNED COMMERCIAL FGD
INSTALLATIONS IN THE UNITED STATES
Along with the advance of FGD technology over
the last 5 years has come substantial utilization of
FGD systems in the United States and Japan. In the
United States, FGD systems are already operating on
2.000 MW of the 18,000 MW ot electric generating
capacity for which FGD is planned. Figure 1 shows
operating and planned power plant capacity
controlled by FGD systems. Table 1 summarizes
ordering trends for the various FGD control systems.
These systems are planned for plants using high-sulfur
content Eastern coal, low-sulfur content Western
coal, and high-sulfur oil. (Appendix B briefly
describes all known operating and planned full-scale
FGD installations for power plant SO2 control in the
United States.) Based on the ordering trends
suggested by these data, the following conclusions
were made:
1. Although orders for FGD systems to date
have been significant, the installation rate is
still demand-limited;
2. 18,000 MW of generating capacity represent
only a small fraction of the capacity which
can and should be controlled by retrofitting
FGD systems to existing plants, there is a
potential demand for the installation of FGD
systems on approximately 50,000 MW of
generating capacity in 1975;
3. Based on the number and variety of FGD
systems which have started up and the
additional systems that will commence
operation within the next 12 months, a
substantial operational data base is being
generated.
277
-------
00
18,000
16,000
14,000
1 12,000
-I I I I I I I I I I I I I I I I I I I I I I
o
10,000
8.000
o 6,000
o
4,000 —
2,000
BEFORE
1972
I I I I I I I I I I I I I I I I I I I I
1972
1973 — *•+- — 1974 — -f-t — 1975 — * I •• 1976
TIME
FIGURE 1. CUMULATIVE U.S. POWER PLANT CAPACITY WITH INSTALLED S02 CONTROL
-------
Table 1. Summary of Operating and Planned Flue-Gas-Desulfurization
Systems on U.S. Power Plants as of September 1973
Started Up
FGD System Type N'o. of Units Total Mw No. Mw
Limestone (LS)
Lime (L)
L/LS - Not Selected
Magnesium Oxide
Other S0? Control Systems
Process Not Selected
9
11
10
3
5
5
3931
3945
5929
370
600
2960
3
4
2
1
1076
725
250
110
Totals 43 17735 10 2161
OPERATING AND PLANNED COMMERCIAL FGD
INSTALLATIONS IN JAPAN
As a result of increasingly more stringent SO2
regulations in Japan, the rate of installation of FGD
systems has accelerated during recent years. In Japan,
utilization of these systems is considered a viable and
cost-effective means of achieving standards set by
regulations for the predominantly oil-burning utility
industry. Presently, more than 60 commercial and
prototype FGD plants are in operation. Even though
most of the plants are of relatively small capacity and
are designed to treat waste gas from industrial boilers,
chemical plants, and smelting plants, several large
FGD systems have been installed. Table 2 summarizes
ordering trends for selected SO2 control systems for
Japanese boilers. (Appendix C briefly describes these
units.) Presently, several of these installations are
generating important performance and operability
information. As is the case for U.S. installations, a
wide variety of process types have been selected, and
much of the information being obtained from them is
relevant and important with respect to the
application of FGD in the United States.
FGD RELIABILITY SUMMARY
The reliability of currently available systems has
been the subject of some question since SO2 control
systems must exhibit the high degree of reliability
required by the utility industry. The required
reliability has been achieved in Japan and will be
achieved in the United States with the early
resolution of a number of applications and
engineering problems related to specific hardware
components and system design parameters. Solutions
to each of these problems have been developed and
demonstrated at one FGD installation or another. It
should be noted that the above assessment of
technology status is consistent with that stated by the
Sulfur Oxide Control Technology Assessment Panel
(SOCTAP) which consisted of representatives from
the Council on Environmental Quality, the Office of
Science and Technology, the Department of
Commerce, the Federal Power Commission, and the
Environmental Protection Agency (ref. 2). Since the
Panel's findings were reported in late 1972, further
operating experience at Boston Edison, Mitsui
Aluminum and Japan Synthetic Rubber units,
279
-------
Table 2. Summary of Selected SCL Control Systems
on Japanese Boilers (As of September 1973)
Process
Wellman-Lord
Dilute Su If uric Acid-
Gypsum (Chiyoda)
Double Alkali -Gypsum
(Limestone)
Mitsubishi-JECCO
Lime/Limestone-Gypsum
Wet Limestone
Carbon Adsorption
DAP -Manganese
Lime Scrubbing
No. of
Units
4
3
3
4
1
1
1
_!_
18
Total Mw
(Planned f, Operating)
545
536
456
530
100
139
110
156
2572
Operating
No . Mw
2
1
1
1
1
1_
7
295
52
156
139
110
156
908
Louisville Gas & Electric system, and Arizona Public
Service tend to corroborate these findings. The state
of the art of SO2 desulfurization technology has
advanced rapidly over the last year and many
full-scale installations have been ordered and some
operated in the United States and Japan. (A summary
of operating experience to date for most of the
full-scale units which have started up in the United
States and Japan is presented in appendix D.)
The operating experience at two plants with
throwaway products and two plants with saleable
products is considered particularly significant. The
most successful operation of a throwaway system has
been the Chemico calcium hydroxide scrubber
process in Japan. It has operated on a coal-fired boiler
at the Mitsui aluminum plant in Japan since March
29, 1972, without any significant downtime;
availability of this unit has been effectively 100
percent since start-up. Sulfur dioxide and paniculate
removal efficiencies have been approximately 85
percent and 98 percent, respectively. In addition,
there are important similarities between this
application and typical U.S. requirements, including:
1. Retrofit on an existing coal-fired boiler;
2. Installation on a moderately large boiler (156
MW);
3. Availability of calcium hydroxide in the
United States.
The system takes on additional significance since it
was based on U.S. technology (Chemico) and a
similar unit, installed at Duquesne's Phillips Station,
is presently in a start-up phase.
A second significant throwaway product system is
the Louisville Gas & Electric FGD system, which
started up in April 1973 on a 70 MW generating unit
at the Paddy's Run Station. Since start-up, scrubber
280
-------
availability has been high with no evidence of major
operating problems. This is considered further
evidence that FGD technology is a workable and
viable SO? control technique.
In addition to the two full-scale throwaway FGD
facilities discussed above, EPA's prototype (three 10
MW units) lime/limestone scrubbing facility at the
TVA Shawnee Steam Plant has also provided valuable
reliability information. Limestone reliability
verification testing has identified scrubber types and
operating modes which have allowed reliable
operation for up to a month's duration; long-term
limestone reliability testing has recently been
initiated. Also, testing at Shawnee and at a supporting
EPA pilot facility at EPA-Research Triangle Park
(RTP) in North Carolina has generated important
process chemistry information which indicates that
enhanced reliability and operability of lime and
limestone systems can be achieved under selected
operating conditions.
Of the saleable product systems, the Wellman-Lord
regenerable sodium sulfite scrubbing process has
operated most reliably to date. A system treating flue
gas at Japan Synthetic Rubber's Chiba Plant has
shown reliable and efficient operation for almost 3
years (since June 1971), producing high quality
su If uric acid. The main disadvantage of this system is
the requirement for discarding a sodium sulfate bleed
stream which is ecologically and economically
undesirable. However, there are indications that bleed
rates can be substantially decreased so that less than 5
percent of the sulfur in the incoming flue gas need be
discarded, compared to the present 10 percent. Also,
a larger 220 MW Wellman-Lord system has been
operating reliably in Japan at a Chubu Electric utility
boiler since May 1973 under varying load (peaking)
operation. No significant reliability problems have
been encountered, and availability has been close to
100 percent.
Chemico's magnesium oxide, saleable product
system at Boston Edison's Mystic Station was started
up in April 1972 and operated until June 1973 on an
intermittent basis due to mechanical difficulties.
However, during June and July 1973, operability was
greatly improved and availability was greater than 80
percent until a scheduled boiler outage terminated
the run. The system was recently restarted and, after
some minor mechanical problems, has operated at an
availability greater than 80 percent since February
22, 1974. Sulfur dioxide removal efficiencies have
been in excess of 90 percent with no significant
scrubber problems. Recent experience with the
critical regeneration system has been good. There
appears to be a high probability for long-term,
reliable operation of this unit in the near future. It
should be noted that no significant environmental
problems have been identified with this system.
However, problems in marketing large quantities of
sulfuric acid will probably limit acceptability of
saleable product systems to only a portion of the
total potential flue gas desulfurization market.
SO, REMOVAL EFFICIENCIES
When evaluating SO, removal efficiencies, it should
be noted that a removal efficiency of about 75
percent is needed to meet the New Source
Performance Standards while burning bituminous
coal containing 3 percent sulfur. Generally,
efficiencies of 85 percent are sufficient to meet the
SO, emission limitations of most State
implementation plans.
As discussed above, a number of FGD systems are
being tested and evaluated. At the Mitsui aluminum
plant near Omuta, Japan, the Chemico scrubbing unit
has exhibited reliable, essentially trouble-free
operation, with removal efficiencies of 80 to 90
percent since March 29, 1972 (ref. 3). The
Wellman-Lord scrubbing unit, at the Japan Synthetic
Rubber plant near Chiba, has accumulated over
15,000 hours of operation since June 1971, with a
removal efficiency averaging about 90 percent.
In the United States, SO, removal efficiencies of
approximately 90 percent have been reported for
Boston Edison's magnesium oxide and Louisville Gas
& Electric's calcium hydroxide FGD systems.
Commonwealth Edison has reported efficiencies of
80 to 90 percent, although this limestone scrubbing
facility has been plagued with mechanical difficulties
since its start-up in February 1972.
Based on the removal efficiencies reported at
various facilities, it is apparent that such systems are
capable of meeting all present SO, emission
regulations.
COSTS
It is difficult to generalize on control costs since
costs must be calculated for a specific application and
usually cannot be readily extrapolated to predict
costs for other applications. This is the case because
of varying interrelationships between the many
factors which influence costs. For control processes,
these factors, all of which affect capital and operating
costs, include: the size of the power plant (whether
the system is new or retrofit), amounts of sulfur and
281
-------
ash m the fuel, pollution control requirements, price
of reactants, solid waste disposal constraints, and
scrubber type
Table 3 presents ranges of capital and annualized
costs for the important FGD processes. For
comparison purposes, capital and operating costs for
a coal-fired power plant and a range of low-sulfur cost
increments are included. As can be seen, FGD costs
are not particularly sensitive to FGD process type.
Generally, the aforementioned application factors
have a more significant effect. In general, incremental
capital costs for including a FGD system in the
construction of a new electric generating plant range
from a low of $30 to a high of $50/kW capacity. This
includes particulate control equipment, where
required. The average incremental cost for new
generating plants is expected to be about $40/kW.
Capital costs for retrofit installations to existing.
generating plants in most cases are expected to be in
the $45 to $65/kW range. For some retrofitted
plants, installation costs have been estimated as high
as $80/kW or more. However, the practical limiting
cost for retrofitting is fixed by economic
considerations at each particular plant.
The total annual costs estimated for stack gas
cleaning range from 1.5 to 3.0 mills/kWh, (ref. 4)
with a mean of about 2.0 mills/kWh, this is
comparable to the cost increment associated with
low-sulfur fuels. The as-produced cost of electricity is
about 9 mills/kWh, whereas the price to customers
averages about 20 mills/kWh. It is estimated that the
average increase in electricity costs to consumers will
be about 3 to 6 percent assuming 100,000 and
200,000 MW of installed FGD capacity by 1983,
respectively. However, for those utility systems which
are predominantly coal users with essentially the total
capacity controlled by FGD. price increases could be
as high as 15 percent.
Since FGD annualized costs are comparable to the
low-sulfur fuel cost increment and are a reasonable
fraction of electrical generating costs, FGD costs,
although significant, are not considered prohibitive.
OTHER ENVIRONMENTAL CONSIDERATIONS
One of the major considerations inherent in any
FGD system is the necessity to dispose of or utilize
large quantities of a sulfur-containing product which
may be throwaway or saleable. To date, most
attention has been focused on lime/limestone
scrubbing systems which produce throwaway sludges.
The disposal of these sludges adds to the existing
problem of flyash disposal for coal-fired power
plants.
Two environmental problems are associated with
throwaway sludges: (a) potential water pollution
problems primarily associated with the dissolved
species in the liquid phase of the sludge; and (b)
potential land utilization problems since nonsettlmg
sludges make land reclamation difficult. However,
techniques are available which should minimize
adverse environmental effects. These techniques
include: (a) operating the scrubber in a close-loop
mode (returning all liquid streams back to the
scrubber circuit to reduce the water pollution
potential); (b) using pond liners in closed-loop
systems employing well-engineered disposal sites to
eliminate water pollution problems; and (c)
employing commercially available sludge fixation
processes to convert the sludge into a more desirable
landfill material with acceptable structural properties
and decreased permeability and teachability.
RETROFIT CONSIDERATIONS
Recent surveys have estimated the proportion of
existing boiler capacity having sufficient space
between the boilerhouse and stack to allow
installation of SO2 scrubbing equipment. Generally, a
scrubber, reheater, induced draft fan. and ducting
must be installed in this limited area. Approximately
20 to 25 square feet of ground space per megawatt is
required for installation of the various SO2 control
systems currently commercially available. Boilers
built within the last 10 years tend to be relatively
large units. Approximately 85 percent of this boiler
capacity less than 20 years old or greater than 100
MW can be retrofitted. Older and smaller boilers are
less likely to have available space and are generally
peak loaded. Fortunately, their size and low load
factor account for a small proportion of total SO2
emissions.
Process equipment outside of the scrubber area
(hold tanks, pumps, etc.) is of less concern to the
retrofit problem since it can be located in the
peripheral areas of the plant. However, disposal of
throwaway sulfur products can be troublesome,
especially in metropolitan areas where land costs may
be prohibitive. Generally, about 0.27 acre-ft/yr of
ponding is required for each megawatt of boiler
capacity. Several techniques have been proposed for
disposing of large quantities of throwaway sulfur
products. To date, most of the operating lime or
limestone scrubbing systems have relied on disposal
of the sludge materials in a disposal pond on the
power plant site. If sufficient land is available, the
pond is designed to eventually store all of the solid
282
-------
TABLE 3. COMPARISONS OF S02 CONTROL PROCESS SYSTEMS FOR COAL-FIRED POWER PLANTS
Apprjx. invest. Approx. (annual)
Rcactant Throwaway costs^3) for coal- costs, t*0 mills/kw-hr
input or fireJ boilers No credit for With credit for SO. removal
requirements recovery $/kw S recovery S recovery efficiency, °»
Coal -fired pouer plant
Lot>- sulfur fuel increment
(coal and oil)
Wet lime/limestone/
Ca(OH)3 sluiry scrubbing
"
Magnesium oxide scrubbing
to
Monsanto catalytic
oxidation (add-on)
We 11 man -Lord process
(soluble sodium
scrubbing with
regeneration)
Double alkali process
N. A.
N. A.
Lime (100-
120". Stoich.);
limcbtone
(120 -ISO's
Stoich.)
MgO alkali;
carbon a:ul fuel
for regenera-
tion and drying
Catalyst ViOs
(periodic re-
placement) and
fuel for heat
Sodium make -up
and heat for
regeneration
Sodium make-up
plus lime/ lime-
stone (lUO-130%
Stoich.)
N. A.
N. A.
Throuaway
CaSO /
CaS(T
4
Recovery
of cone.
1I2S04
or clem.
sulfur
Recovery
of dilute
II SO
tm *t
Recovery
of cone.
IbSOj or
sulfur
Throwaway
CaSO /
CJSOJ
200
N. A.
iS - 52
56 - 66
13 - 67
•10 - 68
!6 - 47
8.9
2.0 - 4.0
1.5 - 2.4
1.6 - 3.0
1.6 - 2.7
1.5 - 3.2
1.2 - 2.2
'
N. A.
N. A.
N. A.
1.4 - 2.8
1.5 - 2.6
1.2 - 2.8
N. A.
N. A.
N. A.
SO - 90
90
85 - 90
90
90
(a) Generally, where a cost range is indicated, the loner end refers to a new unit (1000 Mw);the high end refers to a 200 Mw retrofit unit.
Coits include particulatc removal and arc in 1973 dollars.
(b) Assumptions. Costs calculated at SO. load factor, fixed charges per year i!8> of capital costs.
(c) Includes environmental controls to minimi;c land and water pollution.
-------
waste produced during the power plant lifetime. Such
ponds are fed by a bleed stream which is pumped
either directly to the pond or via a thickening system
(clarifier, filter, centrifuge) with the thickened sludge
pumped to the pond. The supernatant liquor from
both the dewatering system and the pond is usually
returned to the scrubber circuit.
Another important disposal technique, used where
land is not available at the plant site, involves
maximum dewatering of the throwaway bleed stream
using one of the many effective combinations of
clarifying, filtering, or centrifuging equipment
available; the solid, dewatered sludge can then be
transported to a suitable landfill site. However, some
sludge materials are difficult to dewater mechanically.
Although sludge products which retain large
quantities of liquor are difficult to transport and
eventually lead to land-use problems due to the
instability (nonsettling) of the wet sludges, chemical
fixation processes are commercially offered by several
firms including Dravo Corporation and IU Conversion
Systems, Inc.
BARRIERS TO SUPPLYING, INSTALLING, AND
OPERATING FGD SYSTEMS
There are a number of institutional barriers in the
electric utility and control systems industries which
affect the rate of application of SO2 control systems.
Some of the most important are: (a) the inadequacy
of the market demand to encourage development of a
supply industry; (b) the limitations in vendor and
construction capabilities when (and if) the market
situation becomes supply limited; (c) the necessity to
maintain adequate electrical reserve generation
margin; (d) the lack of process chemistry expertise in
the electric utility industry; and (e) fuel switching
alternatives where higher costs for low-sulfur fuels
can be passed directly to consumers by means of fuel
adjustment clauses. The cost of control systems
cannot be directly passed on in a similar manner.
These factors tend to delay the ordering, fabricating,
assembling, and placing into operation of SO3
scrubbing systems.
An important factor now restricting system
installation is the currently limited market demand
for SO2 control systems. This lack of demand by the
electric utilities and other industries arises from such
factors as lack of confidence in the ability of the
systems to perform as promised, anticipation that
regulations may be altered in the near future,
potential difficulties in raising capital and obtaining
rate increases to cover expenses for pollution
abatement, and the lack of suitably trained personnel
in the industry to evaluate and operate these systems.
With increased demand pressure, scrubber sysiems
could be constructed at a significantly higher rate
than at present.
When and if the market situation becomes supply
limited, the following are among the factors which
will limit the rate of FGD system installation:
qualified vendors and their capacities, availability of
construction workers and critical components (fans,
pumps, etc.), production capacity, capital availability,
and limitations imposed by reserve margin
considerations. Based on qualified vendor capacity,
which was considered the major limiting factor, the
SOCTAP (ref. 2) estimated that FGD systems could
be installed on 10,000 to 20,000 MW of generating
capacity by 1975 and that 48.000 to 80,000 MW
could be controlled by 1977. Based on delays in
ordering equipment to date, actual numbers will
probably be closer to the low end of these estimates.
Nationally in the electric power industry, there is
an upper limit to the generating capacity which can
be retrofitted each year because of the necessity to
maintain adequate reserve margins. The upper limit is
related to the fact that it takes up to 6 weeks to tie in
a scrubber to an existing boiler, necessitating
downtime for that period; this factor may preclude
higher, more desirable rates of installation. In
particular, there may be scheduling problems in
retrofitting scrubbers in the middle central and
middle southern parts of the country where the large
coal-fired utilities, already under pressure because of
delays in installing new equipment, are concentrated.
Electric utility companies must also plan for the loss
of 2 to 6 percent of plant power output with use of a
control system.
The electrical utility industry has little expertise in
large-scale chemical process technology. Thus, there
may be serious operational problems once the
scrubbers are installed because of the lack of
familiarity with the operational details of the
scrubbing system. The utilities now depend almost
completely on control system vendors and
engineering consultants for technical advice.
There is a major economic deterrent to the
installation of stack gas scrubbers. The utilities can
meet the S02 standards by converting coal-fired
plants to low-sulfur oil. or by burning low-sulfur coal.
Both options have broad implications for national
economic and environmental policies. Many utilities
are allowed to pass most of the increased costs for
low-sulfur fuels directly and immediately on to the
consumer without regulatory commission action. On
the other hand, utilities must apply for rate increases
to cover the capital and operating expenses of the
284
-------
scrubbers. It would appear reasonable and desirable
to pass FGD system costs directly to the customer as
are the increased costs for low-sulfur fuels.
CONCLUSIONS
FGD is the only significant, near-term alternative to
the use of scarce, low-sulfur fossil fuels in many
power plants. The costs for the installation of FGD
systems are not considered prohibitive; annualized
costs are comparable to the cost increments
associated with the use of low-sulfur fuel for many
applications. Since FGD technology is applicable for
the control of SOa emissions from the vast majority
of existing and new power plants, it is considered an
important factor in helping achieve the country's
clean air goals consistent with the requirements of the
Clean Air Amendments of 1970.
References
1. F. T. Prmciotta, EPA Presentation on Status of
Flue Gas Desulfurization Technology • National
Power Plant Hearings, October 18.1973.
2. Final Report of the Sulfur Oxide Control
Technology Assessment Panel (SOCTAP) on
Projected Utilization of Stack Gas Cleaning
Systems by Steam-Electric Plants, April 1973.
3. Report of the Hearing Panel. National Public
Hearings on Power Plant Compliance with Sulfur
Oxide Air Pollution Regulations, U.S.
Environmental Protection Agency, January 1973.
4. G. T. Roche Me, Economics of Flue Gas
Desulfurization, Control Systems Laboratory,
NERC-RTP, ORD. EPA. May 1973.
APPENDIX A
DESCRIPTION AND SUMMARY OF
IMPORTANT FGD SYSTEMS
A. THROWAWAY PRODUCT SYSTEMS
1. LIME AND LIMESTONE FLUE GAS
DESULFURIZA TION PROCESSES
Process
Several methods have been developed for the use of
limestone and lime slurries in a wet scrubbing process.
The major variations are as follows (see fig. A-1):
1. Use of limestone (CaCO3) added to the
scrubber circuit;
2. -Use of hydrated lime (Ca(OH)2) added to
the scrubber circuit;
3. Use of limestone injected in the boiler
effecting calcination to lime with subsequent
lime slurry scrubbing.
In all three process modes, a slip stream consisting
of reaction products, flyash, and unreacted alkali is
subjected to a dewatering operation and is discharged
as waste to either a disposal pond or landfill site.
The overall reactions for limestone and lime
scrubbing can be represented by the following
reactions:
Limestone: CaCO3 + SO2 + %H2O -»•
CaSOa-'/iHjO + COj (1)
Lime: Ca(OH)2 + S02 -> CaS03-V4H2O + %H20
(2)
History and Experience
There has been a considerable amount of bench
model, pilot plant, and full-scale activity in FGD
since the early 1930's. Over the last 5 years,
developmental activities have been particularly
intense, and 31 full-scale commercial systems have
been ordered since 1968 in the United States of
which 7 have started up and have a backlog of
operating experience.
The boiler injection plus the wet scrubbing process,
has been extensively tested on a commercial scale by
Combustion Engineering, Inc., (C.E.) since 1968.
After 4 years of intermittent operation due to
numerous technical difficulties, C.E. no longer offers
this process.
The first full-scale installation in this country to
introduce limestone into the scrubbing circuit was the
175 MW Commonwealth Edison Will County Station,
Unit No. 1. This unit was started up in February
1972, and has operated intermittently since then. It
has achieved SO2 removal efficiencies in the range of
75 to 85 percent. The major problems experienced to
date are demister pluggage with a soft, mud-like
substance, lack of system reliability due to
mechanical problems, and waste sludge disposal. A
great deal has been learned in the past year at the Will
County Unit) concerning practical operating
problems with limestone scrubbing. None of the
problems encountered at this unit appear to be
insurmountable.
Additional valuable information concerning
operation of lime/limestone scrubbing processes is
being gathered at the versatile EPA prototype test
facility at TVA's Shawnee Steam Plant. The 30 MW
facility includes three types of 10 MW (equivalent)
scrubbers (venturi. TCA. and marble bed), extensive
process instrumentation, and sophisticated data
acquisition and handling systems. Tests to date have
285
-------
GAS TO STACK
STACK t
GAS f"
CaS03+CaS04
METHOD 1. SCRUBBER ADDITION OF LIMESTONE TO WASTE
STACK
CAS
CaCOj
CALCINER
SCRUBBER
CAS TO STACK
Ca(OH)
CaO
PUMP
TANK
SETTLER
CaS03+CaS04
TO WASTE
METHOD 2. SCRUBBER ADDITION OF LIME
C3C03
BOILER
CaO + Flue
—fr
GAS TO STACK
SCRUBBER
CaCOH)
*
PU«P
TANK
+
*
SETTLER
METHOD 3. BOILER INJECTION OF LIMESTONE
TO WASTE
FIGURE A-1. MAJOR PROCESS VARIATIONS FOR USE OF LIME OR
LIMESTONE FOR REMOVAL OF SO2 FROM STACK GASES.
286
-------
identified test conditions which have led to reliable
operation during tests of up to 1 month in duration.
The most recent successful operation of a lime wet
scrubbing process is the 70 MW installation at
Louisville Gas & Electric Company's Paddy's Run
Station. The unit uses carbide sludge (Ca(OH)2) as
the alkaline absorbent. No scaling or plugging
problems have been encountered in over 1,000 hours
of closed-loop operation since April 1973. The
system has demonstrated near 100 percent
availability while removing 85 to 95 percent of the
S02 in the flue gas from boilers fired with coal
containing 3.5 to 4.0 percent sulfur. Waste sludge is
thickened, filtered, and disposed of as untreated
landfill.
The most successful lime scrubbing system is
Chemico's Mitsui Aluminum Company's facility. This
156 MW power plnat has been retrofitted with two
Chemico dual-stage venturi scrubbing systems, each
capable of handling 75 percent of the full-load gas
flow. The system has demonstrated reliable,
trouble-free operation since being put on stream in
March 1972. The plant is presently burning 2 percent
sulfur coal (1,800 to 2,200 ppm inlet SO2) and
achieving 80 to 85 percent SO? removal from the flue
gas using carbide sludge as the alkaline absorbent.
Since coming on stream, the system has operated at
near 100 percent availability. The absence of scaling
difficulties has been attributed to operational
know-how developed by Mitsui in extensive pilot
plant tests (in Japan) and precise pH control.
SO2 Removal Efficiency
A survey of the seven companies with experience in
full-scale tail-end wet scrubbing shows that most
companies will provide S02 removal guarantees
varying from 70 to 90 percent, or as required to meet
EPA standards.
Advantages and Disadvantages
The advantages of lime and limestone systems are
as follows:
1. Relatively low capital and operating costs;
2. Potentially high SO2 removal efficiencies;
3. Ability to simultaneously remove both SO2
and participates;
4. Most fully characterized of FGD systems.
The disadvantages are:
1. The requirement to dispose of large
quantities of waste sludge in an
environmentally acceptable manner;
2. The tendency toward chemical scaling,
plugging, and erosion problems if not
carefully designed and operated.
Performance and Reliability
Operating experience at the Mitsui, Shawnee, and
Louisville Gas & Electric scrubbers indicates that
lime/limestone scrubbers which have the alkali added
to the scrubber circuit can be made to operate
reliably. The Mitsui unit m particular has
demonstrated the viability of this technology via
reliable operations extending over 1 Vi years. However,
experience at other facilities indicates that reliability
can be a problem if the systems are not carefully
desgined and operated. Also, the boiler injection
mode has proven to be a troublesome configuration
(Union Electric and Kansas Power & Lights units)
which is prone to potentially serious operating
problems.
2. DOUBLE ALKALI FLUE GAS
DESULFURIZATION PROCESS
Process (see fig. A-2)
The many double alkali process variations involve
the scrubbing of flue gases with a clear liquor
containing dissolved sodium or ammonium salts,
followed by treatment of the spent liquor with lime
or limestone in a reaction producing a throwaway
sludge for disposal and regenerated alkali liquor for
scrubbing. Typical reactions occurring in the scrubber
and reaction tank, respectively, are as follows for a
sodium-based system:
Na2SO3+S02+H2O-*2NaHSO3; (3)
2NaHSO3 +Ca(OH)2 -»Na2SO3 +3/2H20
+ CaS03-!4H2O (4)
History and Experience
In the United States, primary developmental
attention has been placed on sodium-based double
alkali systems using lime for regeneration. Important
pilot plant work has been performed by General
Motors, FMC Corporation, Envirotech, A.D.
Little/Combustion Equipment Associates, and
Chemico.
Double alkali systems have been intensively
developed in Japan, with limestone used as the input
alkali and gypsum produced as a saleable product.
Showa Denko has recently started up a 156 MW
system on an oil-fired power plant. Two additional
150 MW units, on oil-fired oilers using
Kawasaki/Kureha technology, are under construction
and will start up in mid-1974.
SO2Removal Efficiency
Based on pilot scale results to date, SO2 removal
efficiences between 90 and 99 percent are achievable
at reasonable costs.
287
-------
t
SCRUBBED
GAS
FLUE
GAS
BY-PASS
I
10
FLUE
GAS
FEED
SCRUBBER
i
FEED
MAKE-UP
SCRUBBER
1 I ' SCRUBBER
J I EFFLUENT
THICKENER
WASTE
CALCIUM
SALTS
FIGURE A-2. DOUBLE ALKALI PROCESS VARIATION - SODIUM SULFITE SCRUBBING
WITH REGENERATION OF THE SULFITE WITH LIME
-------
Advantages and Disadvantages
The advantages of double alkali systems include:
1 Relatively low capital and operating costs;
2. Very high SO? removal efficiencies;
3. Use of clear solution scrubbing minimizes
solids buildup and erosion problems offering
potential for high reliability,
4. Ability to simultaneously remove S02 and
participates.
Disadvantages include:
1. Requirement to dispose of large quantities of
waste sludge in an environmentally
acceptable manner;
2. Design complexities necessary to deal with
the following problems:
a. Necessity to prevent excessive purge of
Na2SO4 produced as a result of
oxidation (Na2SO4 is difficult to
regenerate),
b. Necessity to avoid saturation of the clear
scrubbing liquor with calcium sulfate
which could lead to scaling problems.
Performance and Reliability Summary
Based on pilot scale operating experience at
General Motors, FMC Corporation, Envirotech, and
A.D. Little in the United States, and at Kureha and
Showa Denko in Japan, double alkali systems offer
potential for extremely high (>90 percent) SO2
removal with high reliability.
B. SALEABLE PRODUCT FGD SYSTEMS
1. MAGNESIUM OXIDE SO2 SCRUBBING
PROCESS
Process (see fig. A-3)
Chemico's MgO process utilizes an aqueous slurry
of magnesium oxide, magnesium sulfite, and
magnesium sulfate to scrub SO2 from flue gas
streams. The major reaction involves the formation of
additional magnesium sulfite through combination of
SO2 and magnesium oxide. Magnesium sulfite
removed from the scrubber loop is dried ?"H
subsequently calcined to drive off SO2 and to
regenerate active MgO for return to the scrubber
loop. The regeneration can be accomplished either at
the power plant site, or at some remote location since
the magnesium sulfite and magnesium oxide are
stable solids capable of being shipped. The SO2
generated in the calcining operation can be converted
to high grade sulfunc acid or to elemental sulfur by
provision of the appropriate equipment.
History and Experience
In June 1970, the EPA entered into an agreement
with Chemico, Boston Edison Company, and Essex
Chemical Company for construction and operation of
the Chemico magnesia slurry process on the No. 6
boiler at Boston Edison's Mystic Station m Everett,
Massachusetts. The installation on this 155 MW
oil-fired boiler was completed in May 1972. After
completion of the system, numerous operational
problems developed requiring equipment
modifications and investigations directed toward
solving the problems. Most of the problems were of a
materials handling nature, resulting from the
character of the solids generated in the scrubber loop.
Most of these problems have been satisfactorily
solved as demonstrated by the high availability factor
for June and July 1973. and more recently since late
February 1974. Some equipment modifications are
continuing to improve operability.
An additional MgO system has recently been
started (September 1973) at Potomac Electric Power
Company's Dickerson Station. This unit will handle
half the flue gas from a 195 MW coal-fired boiler. The
system is designed to accommodate flue gas from the
burning of 3.0 percent sulfur coal. Very early results
are encouraging. An additional coal-fired application,
designed and engineered by United Engineers &
Constructors, is nearmg completion at Philadelphia
Electric's Eddystone Station. This unit will handle
the equivalent of 120 MW with 2.5 percent sulfur
coal fuel.
Advantages and Disadvantages
The major advantages of the MgO process are
summarized as follows:
1. Sulfur can be removed as high grade acid or
elemental sulfur depending upon equfoment
provided for regeneration.
2. Regeneration can be accomplished at a
location quite distant from the power plant
(for instance, at an existing sulfur acid plant)
thus permitting the use of a central
regeneration facility servicing several flue gas
cleaning locations.
3. By maintaining adequate inventories of MgO.
extended outages of the regeneration facility
can be tolerated without interruption of the
pollution control facility.
4. Process reliability has benefited from the
modifications and investigations at the
Boston Edison site and will continue to
improve as the two additional systems,
Potomac and Philadelphia, become fully
operational in the near future.
289
-------
FLUE GAS
CONTAINING S02
VEMTURI
ABSORBER
SCRUBBER
AIR
PUMP
FIGURE A-3. MgO SLURRY PROCESS FOR FLUE GAS FREE OF PARTICULATE MATTER
-------
The major disadvantage of the process is the lack of
both reliable long-term operating experience and
experience with a coal-fired system.
SO2 Removal Efficiency
The MgO process is capable of achieving 90 percent
SO2 removal over a wide range of inlet SO2
concentrations.
Performance and Reliability
To date, the experience at Boston Edison has
established the capability of the process to
consistently achieve 90 percent S02 removal. Also,
the high turndown capability and reliable operation
of the venturi scrubber configuration used at Boston
Edison have been established. The reliability of the
entire MgO process has not been established through
long-term operation; however, the onstream time at
Boston Edison has improved with the various
modifications, as indicated by an 85 to 90 percent
availability for June and July 1973. Mod if ications to
improve system reliability are continuing.
2. WELLMAN-LORD FGD PROCESS
Process (see fig. A-4)
The Wellman-Lord (W-L) SO2 recovery process
utilizes a sodium sulfite-sodium bisulfite solution to
absorb SO2 from flue gas. The spent absorbent, rich
in bisulfite, is processed in a steam-heated evaporator,
regenerating active sodium sulfite and producing a
stream of S02 for further processing. The process,
depicted in simplest for is:
Absorption: SO2 + Na2S03 + H20 -»• 2NaHSO3
^ (5)
Regeneration: 2NaHS03 heat Na2SO3 4 +
S02 t + H20 t (6)
Inactive sodium sulfate is formed by three
mechanisms: SO3 absorption, disproportionation,
and sulfite oxidation. Sodium sulfate must be purged
from the system in order to maintain adequate levels
of active sulfite in the absorber/evaporator loop.
History and Experience
Patents for the W-L process were filed in 1966, and
patent rights are currently held by Davy Powergas
Inc. Lakeland, Florida. Two Japanese firms are
licensed to market the system There are currently
seven operating plants in the United States and Japan,
including two oil-fired boiler applications. In
addition, more than 10 systems are on order
including 5 additional boiler applications. The earliest
operating W-L system is the sulfuric acid plant
applications at Paulsboro, New Jersey, which has
been operating since July 1970. The earliest boiler
application is the industrial boiler (oil-fired) at Japan
Synthetic Rubber (JSR) Company, Chiba, Japan.
This unit, which is equivalent to 75 MW, has been
operating successfully since August 1971 and has an
excellent onstream factor of 97 percent since that
time. It is worthy of note that both JSR and Olin
Corporation (owner of the Paulsboro system) have
ordered additional systems, thus attesting to the
satisfactory performance of the W-L system. Standard
Oil of California purchased a W-L system for Claus
Plant tailgas cleanup which was started in June 1972.
As a result of the performance of the system,
Standard Oil has ordered three additional W-L
systems for other locations.
The largest unit in operation is on a 220 MW
oil-fired utility boiler operated by Chubu Electric in
Japan. This unit has been operating since May 1973
with particular success in minimizing the quantity of
sulfate purge.
The EPA has undertaken the demonstration of the
W-L system on a 115 MW coal-fired boiler at
Northern Indiana Public Service Company's D.H.
Mitchell Station in Gary, Indiana. The capital cost of
the system is being cost-shared on an equal basis with
the using utility, NIPSCO; the demonstration year is
scheduled to start in the fall of 1975. In the case of
the EPA/NIPSCO demonstration unit, the W-L
system will be mated with the Allied Chemical S02
reduction process to produce elemental sulfur. Allied
Chemical will operate and maintain the W-L/Alhed
system under contract with NIPSCO.
SO2 Removal Efficiency
W-L systems have obtained greater than 90 S02
removal efficiency for commercial systems operating
for long periods of time.
Advantages and Disadvantages
The W-L process has several major advantages as
follows:
1. Simplicity and reliability of the various unit
operations involved;
2. Ability to produce elemental sulfur or high
grade sulfuric acid;
3. High efficiency SO2 removal when required
(95 percent or better);
4. Surge capacity before and after the absorber
to handle flue gas surges and to enhance
system reliability;
5. Many applications and considerable
operating experience which provide
confidence for success in future applications.
291
-------
NJ
NaOH
MAKEUP
(DESULFURIZED
STACK GAS
REHEATER AND
BLOWER
ABSORBER
1
PRESCRUBBER
t
FLUE GAS
N32S03
NaHS03
H20
DISSOLVER
Na2S03
SLURRY Na2S04
Na?S03
NaHS03
S02
CONDENSER
EVAPORATIVE
CRYSTALLI2ER
LOW PRESSURE
STEAM
PURGE TO WATER TREATMENT
FIGURE A-4. WELLMAN-LORD PROCESS SCHEMATIC
-------
Major process difficulties and disadvantages are:
1. Need to sell or dispose of a quantity of purge
solids (sodium sulfate and other sodium
salts);
2. High energy demand results in derating of
power station (3 to 6 percent);
3. No coal-fired applications in operation.
Performance and Reliability Summary
Operating W-L systems have consistently achieved
SO2 removal efficiencies in excess of 90 percent for a
wide range of SO2 inlet concentrations. The most
significant development efforts to date have been in
the areas of reduce capital costs and minimization of
purge requirement. As a result of process
modifications, which have now been proven in
various operating systems, purge requirements of 5
percent or less of inlet sulfur can be anticipated.
Both the inherent high reliability of the equipment
involved in the W-L process and the actual operating
experience (97 percent onstream factor over a 2-year
period at the JSR boiler installation) point to an
availability in excess of 95 percent. The high system
reliability would be enhanced in large-scale systems
due to the opportunity for greater use of equipment
spares and partial systems operation as a result of
multitrain configuration. The current practice of
providing absorbent surge capacity permits short-term
shutdown of the regeneration process without
interrruption of the scrubbing capability.
3. CAT-OXFGD PROCESS
Process (see fig. A-5)
The Monsanto Cat-Ox Process utilizes catalytic
oxidation to convert most of the SO2 present in the
flue gas stream to S03 for subsequent removal by an
acid-absorbing tower (followed by a fiber-packed mist
eliminator to remove H2SO4 mist). For retrofit or
"reheat" applications, the flue gases emerging from
the boiler are passed through a high efficiency (99.6
percent) precipitator and then heated ("reheated") to
850° F (454°C) as preparation for the catalytic
oxidation step. The strength of acid produced in the
absorbing tower is ~80 percent, which is primarily
suitable for use in fertilization production.
History and Experience
The Cat-Ox process was piloted on a 15 MW scale
for 2 years, commencing in August 1967. Based on
the successful pilot operation, agreement was reached
in June 1970 between EPA, Illinois Power, and
Monsanto to install and operate a demonstration
Cat-Ox system on a 110 MW coal-fired boiler at
Illinois Power's Wood River Station at East Alton,
Illinois. Construction of the system was completed in
July 1972; after a considerable debugging period, the
system was acceptance-tested in July 1973. Because
of the present scarcity of natural gas, the reheat
burners must now be modified to provide the
capability for 100 percent firing on fuel oil. This has
occasioned another delay which will preclude
commencement of the yearlong demonstration
program until approximately May 1974.
SO 2 Removal Efficiency
During the acceptance test, the Illinois Power
System achieved emission control guarantees of 85
percent SO2 removal and 99 percent particulate
removal. Removal efficiencies of greater than 90
percent are achievable with this technology for many
applications.
Advantages and Disadvantages
The Cat-Ox process advantages are as follows:
1. The generation of a product which, in certain
limited locations, can be disposed of by sale;
2. Operating costs are relatively low;
3. SO2 removal is consistently 85 percent or
better over a wide range of SO2 input
concentrations.
Major process difficulties and disadvantages are:
1. Cat-Ox must be used near an appropriate
acid user, and dilute acid can be difficult to
market in large quantities in some locations;
2. Capital costs are high;
3. Reliability and maintenance costs are not
currently established due to lack of operating
experience.
Performance and Reliability Summary
Work to date at the Wood River demonstration site
has established the capability of the system to achieve
85 percent SO2 removal; however, no information is
available regarding system reliability or any possible
performance degradation as a function of operating
time. It should be noted that the process and
equipment are similar to the standard contact acid
process, and that major reliability uncertainties
associated with the process center around the ability
of the precipitator to provide adequate particulate
removal to protect the catalyst bed.
293
-------
PRECIPITATOR -
YYYYY
OIL OR
GAS
FIRED
FURNACE
GAS
HEAT
EXCHANGER I
STACK
STORAGE
CAT-OX
MIST
ELIMI-
NATOR
SULFURIC
ACID
FIGURE A-5. REHEAT CAT-OX PROCESS
-------
APPENDIX B
OPERATING AND PLANNED FGD SYSTEMS ON U.S. POWER PLANTS AS OF SEPTEMBER 1973
TABLC B-l. OPERATING AMJ PLANNED TGD UNITS ON
U. S. POhF.R PLANTS AS OF SOTr-BCR 1973--LIMi:Si'ONE SCRUBBING
01
Utility Company
Po'-er Station
Cocnonvcalth Edison
Will County No. 1
Kansas City Power 6
Lie.iit, Hawthorn No. 4
Knrcas City Power &
Lit. nt, LaCygnc Sea.
New or
Retrofit
R
R
N
Arizona Public Service R
Challa Station
Detroit Edison
St. Clair No. 6
Southern California
E.Jjscn (operating
a^enc) Mohavc Sta.
TVA
Widow's Creek No. 8
Norcliern States Power
Siicrburne County ^o.l
Pulilic Service of
Indiana. Gibson Sta.
Northern States Powci
R
R
R
N
N
Slicrburne County No. 2 N
1
Size of PCD
Unit, Mw
156
100
820
115
180
160
550
680
650
680
Process
Vendor
B&W
CE
B&W
Research
Cottrell
Pcabody
Engineering
UOP
TVA
CE
CE
CE
Fuel,
Sulfur Content, %
Coal, 3.5
Coal, 3.5
Coal, 5
Coal, 0.4 -
1.0
Coal, 3.7
Coal, 0.5 -
0.8
Coal, 3.7
Coal, 1
Coal, 1.5
Coal, 1
Status
(Start-Up Date)
Operational
(Feb. 3972)
Operational
(Aug. 1972)
Operational
(June 1973)
Operational
(Dec. 1973)
Under construction
(Mid- 1974)
Under construction
(Mid- 1974)
Under construction
(Oct. 1975)
Under construction
(May 1976)
Planned
(1976)
Planned
(May 1977)
-------
TABLE B-2. OPERATING AND PLANNED FGD UNITS ON
U. S. POWLR PLANTS AS OF SEPfKMBER 1973--LIMU SCRUBBING
o»
Utility Company
Power Station
Union Electric Co.
Mcramcc No. 2
Kansas Power & Light
Lawrence No. 4
Kansas Power & Light
Lawrence No. 5
Kansas City Power &
Light, Hawthorn No. 3
Louisville Gas &
Electric
Paddy's Run No. 6
Duquesnc Light Co.
Phillips Station
Southern California
Edison (operating
agent) Hohave Sta.
Ohio Edison/Mansfield
Sta. (2 units)
Montana Power
Cols trip No. 1 & 2
Columbus & Southern
Conesville No. 566
New or
Retrofit
R
R
N
R
R
R
R
N
N
N
Size of FGD
Unit. Mw
140
125
430
100
70
100
160
1650
720
750
Process
Vendor
CE
CE
CE
CE
CE
Chemico
SCE/Stearns-
3oger
Chemico
CEA
Not selected
Fuel,
Sulfur Content j %
Coal, 3
Coal, 3.5
Coal, 3.5
Coal. 3.5
Coal. 3
Coal, 2
Coal, 0.5 -
0.8
Coal, 4.3
Coal, 0.8
Status
(Start-Up Date)
Abandoned
(Sept. 1968)
Operational
(Dec. 1968)
Operational
(Nov. 1971)
Operational
(Nov. 1972)
Operational
(April 1973)
Operational
(March 1974)
Under construction
(Mid-l'J74)
Under construction
(Early 1975)
Under construction
(May 1975)
Planned
(1976)
-------
TABLE B-3. OPERATING A.W PLANNED FGD UNITS ON
U. S. POWER PLANTS AS OF SEPT2MBLR 1973--L/LS NOT SELECTED
Utility Company
Power Station
Salt River Project
Navajo No. 1
Salt River Project
Navajo No. 2
Arizona Public Ser.
Four Corners No. 1
Arizona Public Ser.
Four Corners No. 2
Southern California
Edison (operating
agent) Muhave No. 1&2
Arizona Public Ser.
Four Corners No. 3
Salt River Project
Navajo No. 3
Arizona Public Ser.
Four Corners No. 4
Arizona Public Ser.
Four Corners No. 5
New or
Retrofit
N
N
R
R
R
R
N
R
R
Size of FGD
Unit Mw
750
750
175
175
1180
229
750
800
800
Process
Vendor
Not selected
Not selected
Not selected
Not selected
Not selected
Not selected
Not selected
Not selected
Not selected
Fuel,
Sulfur Content, %
Coal. 0.5-0.8
Coal, 0.5-0.8
Coal, 0.75
Coal, 0.75
Coal, 0.5-0.8
Coal, 0.75
Coal, 0.5-0.8
Coal, 0.75
Coal, 0.75
Status
-(Start-Up Date)
Construction start
Nov. 1974 (Mar. '76)
Construction start
Oct. 1975 (Octfc'76>
Construction 'start
Oct. 1975 (Oct. '76)
Construction start
Nov. 1975 (Dec. '76)
Planned
(Dec. 1976)
Construction start
June 1976 (Mar. '77)
Construction start
Mar. 1976 (Mar. '77)
Construction start
Sept. 1975 (Apr. '77)
Construction start
Nov. 1976 (June '77)
-------
TABLE B-4. OPERATING AND PLANNED FGD UNITS ON
U. S. POWhR PLANTS AS OF SEPTEMBER 1973-- Hag-Ox SCRUBBING
Utility Company
Power Station
Goston Cdlson
Mystic Ho. 6
Potomac Clectrte &
Power
DLckcrson No. 3
New or
Retrofit
R
R
Philadelphia Electric R
Eddys tone No. 1 I
Size of FGD
Unit, Hw
150
100
120
Process
Vendor
Chcmlco
Chenleo
United
Engineer*
Fuel,
Sulfur Content, \
Oil, 2.5
Coal', 2
Coal, 2.5
Status
(Start -Up Date)
Operational
(April 1972)
Operational
(Sept. 1973)
Operational
(April 1974)
TABLE B-S. OPERATING AND PLANNED FCD UNITS ON
U. S. POWER PLANTS AS OF SEPTEMBER 1973--OT1IER SOj CONTROL SYSTEMS
Utility Company
Rower Station
Catalvtlc Oxidation (Ca
Illlnol:> Power Co.
UooJ jlivcr No. 4
Wellm.in-Lord
Northern Indiana
Public Service,
D.ll Mitchell No. 11
Aqueout Sodium Base Ser
Nevada Power
Reid Gardner No. 1&2
Novada Power
Reid Gardner No. 3
New or
Retrofit
t-Ox)
R
R
ubblne, Non-1
R
R
Site of FGD
Unit. Mw
110
115
egenerable
250
123
Process
Vendor
Monsanto
Davy Foverga
Allied Chemi
CEA
CEA
Fuel,
Sulfur Content, \
Coal. 3.2
if Coal, 3.5
cal
Coal. 0.5 -
1.0
Coal. O.I -
1.0
Status
(Start-Up Date)
Operational
(Oct. 1972)
Under construction
(Early 1975)
Operational
(April 1S74)
Under construction
(1975)
TABLE B-6. OPFRATING WD PLANNED FGD UNITS. ON
U. S. POWER PLANTS AS OF SEPTEMBER 1973—PROCESS NOT SELECTED
Utility Company
Power Station
Public Service of
New Mexico
San Juan No. 2
Potomac Electric &
Power
Chalk Point No. 3
Potomac Electric &
Power
OialL. Point No. 4
Potomac Electric &
Power
Dlckersi
-------
APPENDIX C
SELECTED S02 CONTROL SYSTEMS ON JAPANESE BOILERS
TABU: C-l. SI.M:Cn:i) S02 CONTROL SYSTliMS ON JAPANLSE BOILCRS
(September 1973)
Company and Plant
J.ip.in Synthetic Rubber
Clilba I'l.iiit
Ciwbu F.li-ctric
Yui.Mikia Plant
Ml l cut Aluminum Co.
Oi;,uLa 1'lant
(O
(O
Tokyo Kl metric
K.isliinu 1'l.uiL
Fuji lioi.m
K.iinan PL.int
Clmlju lih-ctric
iUi.ii Lnaj'.oya Plant
Snow.i Ucnko
Ciilbn riant
Cini|',o\u lilccLric
MJiuiililnia
Nllion Syntlictic Rubber
Vokkalchi Plant
Proccr.n
Ucllman-Lord
llAP-Mn
Llinc Scrubbing
Carbon
Ail.soipLion
DlluLc SulCuric
Acid-Gypsum
Wcllman-Lorcl
Double Alkali
(Li me-:; tone)
Wet L liner. Cone
Wcllman-I.ord
Size of I;Gn
Unit, Mw
75
110
156
139
52
220
156
100
132
Process Vendor
Davy Power gas
(MM)
Mitsubishi
H.I.
Chcmico-Mltsui
Hitachi Ltd..
Chiyoda
Davy 1'owergAS
(flKK)
Sliowa Dcnko
Dabcock-llitachi
Davy Powcrgas
(NKK)
Fuel
Oil
Oil
Coal
Oil
Oil
Oil
oh
Oil
Oil
Status
(Start-Up Date)
Operotionol
(June 1971)
Operational
(Fch. J972)
Operational
(Match 1972)
Operational
(1972)
Operational
(Oct. 1972)
Operational
(May 1973)
Operational
(Aug. 1973)
Operational
(Nov. 11)73)
Operational
(1973)
-------
Cont.
8
o
TAIUJ; C-l. S!:Ll:CTi:i) S02 LUNFKOL SYSTEMS ON JAPANliSI: BOILIRS
(Si-ptember 1973)
Company nnd Pl.int
liuiLii tuiiiii Cliiu.i Clicm.
Chlba ri.inL
Tokyo nicctrlc
Yo!.cu;uk;i Plant
Tohoku Electric
Ilaciiiiuu' riant
Kanr:nl Electric
A:n.i|>n:.akl J'lant
Knn'i.il Moctric
KnJnan I1 Line
Tolioku lilccLrLc
Sliiir-.cinhi IM.int
S.H'-.'.u r.k-rirlc
Sltiiiiuktriiili'i.! I'lnnt
liokurik.i Klcctric
SliiniRJiLito Plain
!Ut;:u!>r:!il Petroclicm
Yokknichl PJ.mr
Process
Wullman-Lord
Limuutonci-
Gypcum
Limc-Cypcum
Lime -Gypsum
LJ mo-Gypsum
Double-Alkali
(Limestone)
l)oui)]c-Aiknli
(i.iinentonr)
Dilute Sulfurlc
Acid-Gypsum
Dilute Sulfurlc
Arid-Gyp.';»m
Size of FO)
Unit (MW)
118
130
125
125
150
150
150
250
234
Process Vendor
Dnvy Powurgas
(SCliC)
Mitsubishi
JLCCO
MUsubialii
JF.CCO
MUsublslii
Jl-CCO
MUoublsl>5
JLCCO
Kureha-Kawosaki
Kurolia-Kawasaki
Chiyoda
Clilyoda
Fuel
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Stntuo
(Stort-Up Date)
Ooorationul
(1973)
Operational
(197/0
Under construction
(1974)
Under construction
(1974)
Under construction
(1974)
Operational
(Jan. 1974)
.Umler consiruction
(1974)
Undur construct! »n
(June 1974)
Under construction
(Due. 1974)
-------
APPENDIX D
System Description and History of Operation:
SUMMARY OF OPERATIONAL EXPERIENCE
WITH FULL-SCALE FGD UNITS IN
THE UNITED STATES AND JAPAN
A. OPERATIONAL EXPERIENCE
ON U.S. INSTALLATIONS
1. PROCESS BOILER INJECTION OF
LIMESTONE FOLLOWED BY WET
SCRUBBING-THRO WAWA Y
PRODUCT
Process Supplier Combustion Engineering
Constructor Combustion Engineering
System Location- Union Electric Company, Meramec
Unit 2, St. Louts, Missouri
Startup Date September 1968
System Description and History of Operation •
This 140 MW unit, the first full-scale utility SO2
control system in this country, was officially shut
down and abandoned in December 1971,
approximately 3 years after its inception. This system
consisted of two parallel single-stage marble bed
absorbers equipped with demisters and reheaters. It
was operated with some clarified liquor recycle.
The reason for abandonment was massive plugging
and scaling in the entire boiler and SO2 removal
system. This recurrent problem barred the company
from keeping the generating unit going for long
periods. It has been said that the up-and-down
operation of the boiler, necessitated by scrubber
problems (due to the fact that no provisions for gas
bypass had been made), may have compounded the
problems by causing moisture to combine witti
powdery deposits on the boiler tubes to form
concrete-like deposits during periods of boiler
shutdown. The implication is that boiler plugging
might have been at least minimized by equipping the
scrubber system with a bypass, thus allowing the
boiler to operate independently of the scrubber and
less intermittently.
The 125 MW Unit No. 4, started up in December
1968, was one of the first attempts to design,
construct, and operate a full-size SO2 scrubber. The
limestone injection method was used. Multiple
problems occurred during early stages of operation
including corrosion, plugging of lines, and problems
with reheaters and demisters. These problems did not
include scaling. During the first 4 months of 1971,
modifications in the original design enabled operation
with some reliability.
When the scrubbers for the much larger 420 MW
unit No. 5 were started up in November 1971, the
pond which was common to both units became
overloaded and scaling occurred. Modifications in the
design have been made that reduced these chemical
problems, but mechanical problems remain. At the
present time, the modular arrangement allows
cleaning of the scrubbers without shutting the boiler
down.
The experience at Lawrence has proved invaluable
in making changes for later Combustion Engineering
units such as the successful Paddy's Run plant. The
Lawrence Station is, however, set in much of its
design as a boiler injection system and in the
closeness of the demisters to the absorbing bed. It,
therefore, cannot fully benefit from the knowledge
that has come from the operation of it and other
systems.
Kansas Power and Light is able to operate a
limestone SC>2 scrubbing system, with significant SO2
removal and some reliability, while serving a large
utility generating plant. This is a milestone in the
development of SO2 control technology.
3. PROCESS
Process Supplier
Constructor
System Location
Stsrtup Date
LIMESTONE SCRUBBING WITH
THROWAWAY PRODUCT
Babcock & Wilcox
Babcock & Wilcox
Commonwealth Edison Company,
Will County Station No. 1,
Romeoville, Illinois, near Chicago
February 1972
2. PROCESS
Process Supplier
Constructor
System Location
Startup Date.
BOILER INJECTION OF
LIMESTONE FOLLOWED BY WET
SCRUBBING-THRO WAW A Y
PRODUCT
Combustion Engineering
Combustion Engineering
Kansas Power and Light, Lawrence,
Kansas, Units No. 4 & 5
December 1968 and November 1971
System Description and History of Operation:
Will County Unit 1. with scrubber on line, has a net
power output of 156 MW. The system consists of two
identical, parallel, wet limestone scrubbing trains,
each consisting of a venturi for participate removal,
followed in series by a turbulent contact absorber
(TCA) for SO2 absorption. Each absorber and
scrubber is equipped with its own recirculation tank.
301
-------
Spent slurrry is bled to a clarifier which produces
liquor for recycle via a 5-acre pond and a thickened
sludge (underflow) which is pumped to a ready mix
concrete truck where additives are mixed with the
sludge in an attempt to make the sludge acceptable as
landfill.
Since February 1972, the SOX control systems have
operated intermittently. Generally, SOX removal
efficiencies in the 80 to 90 percent range are
attainable during periods of operation. Chemistry is
not considered to be a problem with the system.
Problems which have been responsible for shutdown
of the system can be classified as mechanical and
were not all attributable to the SOX control system.
Some of the problems attributed to the limestone
SOX control system are: (1) demister and reheater
pluggage; (2) wearing and plugging of spray nozzles;
(3) reheater vibration and stress corrosion cracking;
(4) plugging of slurry lines; (5) "sulf ite blinding" of
limestone; and (6) scaling. Some of the other reasons
cited for system outage are: (1) expansion joint
failure; (2) inspection; (3) boiler outage; (4) motor
failure; (5) contractor and operator errors; (6) fan
trip; (7) water loss to pump glands; (8) fan damper
operation; (9) leaks in slurry lines; (10) limestone
supply; and (11) booster fan vibration.
Solutions to almost all of the problems do not
require development of new technology. Methods of
controlling all of the problems specific to limestone
wet scrubbing, except for the reheater problems, have
been used with some degree of success at Will
County. Installation of Inconel alloy reheater tubes is
expected to solve the reheater stress corrosion
cracking problem. Plugging is avoided by circulation
of high-solid content slurries and using adequate
liquid/gas ratios. Demister pluggage is minimized by
good demister wash techniques. Wear of nozzles is
controlled by proper selection of materials of
construction.
Between February and December 1972, the two
SOX control trains accumulated in excess of 1,400
and 1,200 hours of operation, respectively. During
the outage periods, many improvements and repairs
were made. One of the trains has been shut down
since April 1973 and presently is being cannibalized
to support the other. Commonwealth Edison is
attempting to iron out the problems with one train
before attempting to operate both simultaneously.
Since March 1974, reliability of the system has
improved, with a continuous run of 23 days
successfully completed; recent mist eliminator
modifications have appeared successful in minimizing
plugging problems.
4. PROCESS
Constructor
System Location
Startup Date
MAGNESIUM OXIDE SCRUBBING
WITH THERMAL REGENERATION
Chemical Construction Corporation
Boston Edison's Mystic Station
Everett, Massachusetts
April 1972
System Description and History of Operation:
The MgO system, which has been applied to the
150 MW oil-fired' boiler at Boston Edison's Mystic
Station, utilizes a venturi scrubber to contact the
magnesium oxide magnesium sulfite slurry with boiler
flue gases. The solids removed from the scrubber, rich
in magnesium sulfite, are dried in a direct-fired rotary
dryer. The dried solids are shipped by truck to the
Essex Chemical Company contact acid plant in
Rumford, Rhode Island, where the magnesium sulfite
is calcined. The SC<2 produced by the calcining
operation is converted to high-grade sulf uric acid and
the MgO produced is shipped back to Mystic Station
for reuse in the absorber.
In April 1972, the shakedown period began for the
Mag-Ox scrubbing system. The venturi scrubber has
operated intermittently since then due to mechanical
difficulties. During operation, the scrubber has
achieved SO2 removal efficiencies in excess of 90
percent with no apparent scrubber-related problems.
The major problem has been with the design and
operation of the MgSOa crystal dryer. Redesign of
the dryer and a change of fuel to a low viscosity oil
appear to be resolving these problems. Other
problems with centrifuging the sulfite crystals from
the scrubbing liquor and properly calcining the sulfite
to regenerate MgO appear to be manageable. An
availability factor of about 80 percent was achieved
for June and July 1973. After a series of mechanical
difficulties during late 1973; the operation since
February 1974 has been substantially improved with
an availability to the boiler of about 90 percent.
This project is quite important because it will be
the first time the individual steps of scrubbing,
centrifuging, and calcining have been integrated in the
Chemico process. Partially funded by EPA, the
project involves not only the scrubber, centrifuge,
and dryer at the Boston Edison plant but also the
calcining and acid plants at Essex Chemical Company
in Rumford, Rhode Island.
The first large-scale coal-fired application was
started up in September 1973, at the Dickerson
Station of Potomac Electric and Power. Flue gas from
approximately 100 MW of the 195 MW of Dickerson
Unit 3 will be processed. Since the plant burns coal (3
302
-------
percent S, 8 percent ash), the scrubbing facility uses
one venturi scrubber to remove the particulate and a
second scrubber to remove the SO2. Regeneration of
MgO for this system will be carried out at the Essex
Chemical facility which also serves the Boston Edison
system.
5. PROCESS
Process Supplier
Utility.
System Location
Startup Date
LIMESTONE SCRUBBING WITH
THROW/AWAY PRODUCT
Research Cottrell
Arizona Public Service
Cholla Power Station No. 1 near
Joseph's City, Arizona
December 1973
System Description and History of Operation:
The FGD System at the Cholla plant was first
placed in service on December 15, 1973. The system
performed well with about a 92.6 percent availability
factor. One of the major problems encountered was
corrosion on the outside of the reheater tubes due to
acid condensation. This problem was corrected by
insulating the ductwork to the reheaters and the
installation of a plate ahead of the reheater to divert
any acid condensation away from the tubes.
Vibrations in the reheater unit were overcome by
installation of cross baffles at the gas inlet to the
reheater in order to dampen the vibration. Scales and
deposits which accumulated around flooded disc
scrubber shaft and restricted its rotation were
eliminated by modifying the shaft's gland assembly.
& PROCESS
Process Supplier
Constructor
System Location
Startup Date.
CAT-OX
Monsanto Enviro-Chem Systems, Inc
Leonard Construction Company
Illinois Power Company, Wood River
Station, East Alton, Illinois
Construction was completed in July 1972, followed
by debugging and modification. Acceptance testing
was completed in July 1973, with full operation to
commence April 1974, following provision of
additional modifications.
System Description and History of Operation:
The retrofit or "reheat" version of the Cat-Ox
system has been installed on the 110 MW coal-fired
Wood River No. 4 boiler operated by Illinois Power.
The process accepts flue gases from the discharge of a
specially provided high efficiency ESP. The gases are
heated to 850° F (454°C) by heat exchange with
processed gases from the catalytic converter and by
supplemental "reheat" burners. The heated gases pass
through the fixed bed catalytic converter where SO2
is oxidized to SOs. An acid absorbing tower followed
by a fiber acid mist eliminator serve to remove the
SOa prior to discharge of the flue gas to the stack.
Product acid is cooled and stored in tanks.
Since completion of the system in July 1972, a
series of mechanical difficulties has occurred and
modifications or repairs have been effected. During
July 1973, an acceptance test was conducted which
established the capability of the system to achieve the
specified 85 percent 863 removal while producing an
acid product of somewhat greater than the required
77.7 percent concentration. Also, subsequent testing
of the high efficiency ESP has established the
particulate removal to be sufficient to prevent undue
costs for catalyst cleaning. Long-term operation of
the system has been delayed until April 1974, due to
late delivery of equipment for a planned system
modification to permit operation of the reheat
burners on fuel oil rather than natural gas.
7. PROCESS-
Process Supplier.
Constructor
System Location-
Startup Date
LIMESTONE SCRUBBING WITH
THROWAWAY PRODUCT
Combustion Engineering
Combustion Engineering
Kansas City Power and Light,
Hawthorn Station, Units No 3 and 4
September 1972
System Description and History of Operation:
In September 1972, the 100 MW Kansas City
Power and Light's Hawthorn Units 3 and 4 started
up. Each of the boilers was originally equipped with a
boiler injection system and two identical scrubber
modules. Unit No. 4 has recently been converted to a
tail end system. Before changing to a tail end system,
boiler pluggage problems were experienced on Unit
No. 4. Unit No. 3 still uses boiler injection and has
not experienced boiler pluggage. No problems have
been reported with the fans or reheaters on either
unit. The remaining problems appear to be primarily
with the recirculation system. Modifications similar
to those used successfully at Combustion
Engineering's scrubber at Louisville Gas and Electric
Company's Paddy's Run plant show great promise of
overcoming these problems. These include problems
with headers and drain pots. Demister pluggage has
been a problem but this appears to be solved. Some
settling has occurred in the recirculation tank, but
this should be corrected with improvements in the
agitation of the tank.
The method of ultimate sludge disposal has not
been decided upon. Enough land area is available to
303
-------
enable ponding of the sludge for up to 15 years.
This plant is the last plant installed by Combustion
Engineering using the limestone injection technique.
Removal efficiencies have been between 70 and 80
percent.
Startup Date.
Southwest of Louisville
April 1973
8. PROCESS-
Process Supplier
Constructor
System Location
Startup Date
LIMESTONE SCRUBBING
THROWAWAY PRODUCT
WITH
Babcock and Wilcox
Babcock and Wilcox
Kansas City Power and Light,
LaCygne Station, Unit No. 1
June 1973
System Description and History of Operation:
The SO2 scrubber at the new 820 MW LaCygne
Station started operation in February 1973. The
system consists of seven modules. At present, one
module is controlling S02 and paniculate with a
venturi scrubber and a grid plate scrubber. The
limestone is added to the scrubber rather than to the
boiler.
The remaining six modules at LaCygne are
controlling paniculate only, using the venturi section.
The grid plate will be installed and limestone added at
a future date to control SO2 for the entire plant.
It is too early to accurately assess the reliability of
this system, since the boiler is new and has not yet
become fully operational. The system is essentially a
duplicate of the Will County scrubbing system and
has experienced many of the same problems. These
include plugging of the demisters, corrosion of the
reheater tubes, and other mechanical problems. Like
that of Will County, the problems are mechanical in
nature and solvable using state-of-the-art methods. It
is worthwhile to note that no chemical problems with
the scrubber itself have occurred. It appears likely
that the system will achieve reliable operation in the
near future.
Unlike that of Will County, there are no bypass
provisions at LaCygne, and no electrostatic
precipitators are installed to collect paniculate. The
scrubbers are expected to achieve 80 percent control
of SO2 as well as satisfactory control of paniculate.
A 1-year hold time is available for sludge disposal.
Plans beyond that time are uncertain.
9. PROCESS
Process Supplier
Constructor
System Location
LIME SCR UBBING
THROWAWAY PRODUCT
Combustion Engineering
Combustion Engineering
Louisville Gas and Electric Company,
Paddy's Run Station No 6,
System Description and History of Operation:
The SO2 control system installed on this 70 MW
electric generating unit consists of two parallel,
two-stage marble bed scrubbers installed downstream
of an electrostatic precipitator. The scrubber effluent
liquor enters a large reaction vessel from which some
spent liquor is bled to a thickener followed by a
rotary drum filter. A carbide sludge slurry which
contains lime as the actve ingredient is fed to the
reaction vessel. This absorbent slurry feed is
controlled by a measurement of acidity in the system,
and changes as necessary with variations in 502
throughput. S02 throughput varies with
boiler-generator load and with variation of fuel sulfur
content.
Between April and August 1973, the unit has
accumulated about 1,000 hours of operation. The
scrubbers have operated for periods of up to 10-12
days with no problems. SO2 removal has been in the
90 percent range. There has been no evidence of
scaling or plugging. Neither erosion nor corrosion has
been a problem. There have been some minor
mechanical problems. The demisters, two stages of
standard chevron, have not been a problem. The
demister is washed once every 8 hours with high
velocity fresh water at the bottom of the demister.
The amount of water used is only that amount
needed to make up for normal evaporation and losses
with the throwaway sludge. Thus, the system is
operated as close to closed loop operation as can be
expected.
The limited operation, overall, has not been due to
problems for the most part, but due to the lack of
operating manpower. During the peak demand
periods, when all the Paddy's Run units were on line,
LG&E has had to shut the scrubber system down
because operating manpower was spread thin and
operation of the electric generating equipment took
first priority.
B. OPERATIONAL EXPERIENCE
ON JAPANESE INSTALLATIONS
WITH 1. PROCESS
Process Supplier
Constructor
SOLUBLE SODIUM SCRUBBING
WITH THERMAL REGENERATION
(WELLMAN-LORD)
Davy Powergas
Mitsubishi Chemical Machinery
Company
304
-------
System Location- Japan Synthetic Rubber Company
(JSR) near Chiba, Japan
Startup Date July 1971
System Description and History of Operation:
Successful, leliable operation of the Wellman-Lord
SOa control process at Chiba with essentially 100
percent availability for over 2 years is considered
quite significant for the U.S. control situation. This
process consistently removes over 90 percent of the
SO2 from the exhaust gases of a 75 MW equivalent
oil-fired boiler. The load is essentially constant, but
the concentration of SO2 varies from 400 to 2,000
ppm.
It appears that the process should be applicable to
coal-fired boilers, if flyash removal equipment is
installed upstream of the absorber. A Northern
Indiana Power Service Company (NIPSCO) unit.
partially funded by EPA, will evaluate such systems
on a coal-fired boiler. Cost studies indicate that
capital and operating costs for a Wellman-Lord
system in the United States on a coal-fired boiler are
not a great deal higher than those for wet
lime/limestone or magnesium oxide scrubbing
systems, which are generally considered the least
expensive of the flue gas desulfurization systems. The
system is commercially offered and guaranteed in the
United States.
The major problem with the process is the
requirement for a purge to remove contaminants,
primarily sodium sulfate (NA2S04). Present
information indicates about 10 percent of the total
incoming sulfur is lost as soluble N32SO4 at JSR.
Sodium sulfate is a natural component of sea water
but could possibly cause problems in fresh water.
This purge has been substantially reduced at the
newer installation at Chubu Power and may be
further reduced by oxidation retardants research by
Sumitomo.
The product of the Wellman-Lord system at JSR is
high-purity sulfuric acid. While there may be
insufficient markets for the sulfuric acid produced if
a large percentage of the plants in the United States
used this method, there is probably a market available
for the output of several plants, particularly those in
eastern and midwesteran industrial states.
Elemental sulfur, which will be produced in the
NIPSCO unit, is another potential product which is
both storable and potentially saleable; this could
ultimately be a more desirable end product, especially
for utilities not near a market for sulfuric acid. A
disadvantage of elemental sulfur production is the
necessity of the use of considerable quantities of
reducing agent, such as coke or natural gas.
2. PROCESS- LIME SCRUBBING WITH
THROWAWAY PRODUCT
Process Supplier. Chemical Construction Company
(Chemico)
Constructor. Mitsui Miiki Machinery Company
System Location: Mitsui Aluminum Company, Omuta
Power Station, Japan
Startup Date- March 1972
System Description and History of Operation:
The scrubber at Mitsui Aluminum's Omuta Power
Station began operation on March 29, 1972. The
system uses as an absorbent carbide sludge that is
chemically identical to lime with regard to S02
scrubbing. The scrubber serves a coal-fired 156 MW
boiler that burns coal equivalent to about 2.5 percent
sulfur eastern or midwestern U.S. coal. The scrubber
has had several load variations similar to, but less
frequent than, typical U.S. boilers. Both SO2 and
particulate removal efficiencies have been quite high,
85-90 and 98 percent, respectively. The system has
operated at closed-loop conditions for substantial
periods of time and is open-loop only occasionally
during periods of heavy rain. Flyash concentration
into the scrubber is similar to that for typical U.S.
retrofits.
The system has operated 24 months, continuously,
and essentially trouble free, since startup.
It should be noted that the reliable performance of
this system is of real significance to the United States
air pollution control program, since the design ground
rules for the Japanese unit are quite similar to those
of many of our power utilities requiring
desulfurization systems. The following are among the
areas of commonality: retrofit of existing coal-fired
boiler, moderately efficient electrostatic
precipitators, installation on moderately large boilers,
production of a throwaway product, and availability
of lime (calcium hydroxide). The unit takes on
additional significance since the system was designed
based on U.S. technology (Chemico) and is offered
and guaranteed in this country. Two similar units
using lime on coal boilers are being constructed in the
United States for Duquesne Light Company's Phillips
Station and Ohio Edison's Bruce Mansfield Station.
3. PROCESS:
Process Supplier
Constructor-
SODIUM SCRUBBING WITH
THERMAL REGENERATION
(WELLMAN-LORD PROCESS)
Davy Powergas, Inc.
Mitsubishi Chemical Machinery
(MKK)
305
-------
System Location
Startup Date:
Chubu Electric. Nagoya. Japan
May 1973
System Description and History of Operation.
The Chubu system is applied to a peaking service,
oil-fired utility boiler of 220 MW output. The system
utilizes a rectangular sieve tray absorber which has
maintained SCb outlet levels consistently below 150
ppm. Double effect evaporation is utilized for
regeneration, and a purge crystallization system is
provided to minimize sodium losses through purge.
The purge crystals have assayed higher than 85
percent sodium sulfate. The system is designed to
treat flue gas from burning of fuel containing 4
percent sulfur and to handle changes in boiler load
from 25 to 100 percent. Because of the peaking
service application, the system is subjected to
frequent weekend shutdowns with no restart
problems encountered to date. It is noteworthy that
at one point during the recent testing program the
boiler fuel was changed from 0.7 to 4 percent sulfur
oil instantaneously through boiler operator error. In
spite of this many-fold step change in inlet
concentration, outlet concentration of SC>2 remained
below 150 ppm.
306
-------
15 .Vlay 1974
Session V:
RESEARCH AND DEVELOPMENT NEEDS
Robert P. Hangebrauck
Session Chairman
307
-------
308
-------
TECHNOLOGY NEEDS FOR POLLUTION ABATEMENT
IN FOSSIL FUEL CONVERSION PROCESSES
E. M. Magee and H. Shaw*
Abstract
The current status of fossil fuel conversion
processes is being evaluated with respect to pollution
control and thermal efficiency. An awareness of
potential pollution problems will allow the process
developers to obviate most of the problems through
proper design and construction. Other problems
which do not have an apparent solution are also being
specified in this study. Early identification of
pollution problems will allow research, development,
and design work to be carried out in time for
implementation in commercial plants. The
"technology needs" that have become apparent thus
far are reviewed in this paper. The areas that are
discussed are:
«• Dust, Fumes, and Water Runoff from Coal
and Shale Storage
• Acid Gas Systems
• Dirty Process Water Treatment
• Trace Elements
• Other Technology Needs
- Raw Gas Scrubbing
- Lock Hopper Pressurization
- Noise
— Odors
- Solid Wastes
INTRODUCTION
Under contract with the Environmental Protection
Agency,T the Exxon Research and Engineering
Company is studying the pollution and thermal
efficiency aspects of fossil fuel conversion processes.
The contract may include all fossil fuels, but work to
date has concentrated mainly on coal gasification and
liquefaction.
Earlier papers in this symposium have discussed the
trace element content of fossil fuels produced or
consumed in the United States (ref. 1) and some of
the pollution control and thermal efficiency aspects
of coal conversion processes (ref. 2). Information
gaps and new technology needs in fossil fuel
conversion processes are also being defined under this
contract and are the subject of the present paper.
Although it is necessary to study each conversion
process in order to adequately define the technology
needs for that process, some areas are general for
more than one process and for more than one fossil
fuel. These general areas are emphasized in this paper.
INFORMATION GAPS AND TECHNOLOGY
NEEDS
Dust, Fumes, and Water Runoff
From Coal and Shale Storage
Large storage piles are, or will be. used in coal
conversion, shale conversion, and power generation.
In coal conversion plants it is estimated that as much
as 1 million tons of coal will be stored in an area of
approximately 2 million square feet. The large area
and the huge quantity of material involved offer
potential for pollution of the surrounding air and
water. It is difficult to estimate the quantity of dust
dispersed from the storage piles, since this will
depend on the physical state of the materials as well
as meteorological conditions; but for a rainfall of 6
inches over 24 hours, the water runoff would be 2.5
million pounds per hour.
The dust from the coal piles might be assumed to
have the same composition as the bulk coal. This may
not be justified for two reasons. First, the dimunition
of the coal could lead to enrichment or depletion of
certain elements, depending on the physical state of
the elemental compounds in the coal. If a particular
element is present as microcrystals of its compound,
then it could well be enriched in the finer portions of
dust. The second reason why dust may not be
representative of fresh bulk coal arises because of the
ease of surface oxidation of coal when exposed to air
(ref. 3, pp. 272-279 and 296-306; ref. 22). That this
oxidation is not negligible is illustrated by table 1,
which shows the oxygen and carbon dioxide content
of the gases in a coal pile at Garrison Dam, North
Dakota (ref. 3, p. 299). As can be seen from the
table, the oxygen is almost depleted within the coal
pile.
'Authors are with the Government Research Laboratory of
Exxon Research and Engineering Company, Linden, New
Jersey.
tThis work was carried out under contract No. 68-02-0629
with the Environmental Protection Agency.
309
-------
Table 1. Oxygen depletion in a
coal pile
Location
(months)
Top,* (12 mo.)
Top,* (20 mo.)
Sides, (12 mo.)
Sides, (20 mo.)
C02,
percent
10.0
12.0
7.3
11.2
02.
percent
0.5
0.3
5.4
2.4
*3.5 ft depth.
Table 2. Effects of weathering on
physical properties of lignite
after 160 days
Method of
storage
Size de-
gration,
percent
Friability
percent
Sample at
beginning
of test 3.2
Sealed in
metal cans 8.8
Atmospheric 81.1
15.7
21.1
64.9
Further evidences of the magnitude of weathering
is shown in table 2 (ref. 3, p. 301). Considerable size
degradation takes place on weathering, thus-
increasing the fraction of fines. This could lead to a
change in the dust analysis from that of bulk coal.
In addition to dust pollution, air pollution could
result from the release of organic materials during
oxidation of the coal or shale. This could become
especially acute if spontaneous combustion occurs.
No information is currently available on the quantity
and composition of volatile organic materials present
in the air over coal piles.
Of perhaps more concern from the viewpoint of
potential pollution is the nature of the liquid effluent
(runoff and seepage) from the storage pile. The water
analysis might be similar to acid mine water, but this
is not for certain due to the increased surface area of
the coal or shale and weathering effects. Not only
might trace elements be leached from the storage
piles, but traces of organic materials might also be
removed. The nature of these organic materials
Table 3. Technology needs in coal
and shale storage
• Analyze trace elements in dust in
the vicinity of storage piles.
• Analyze organic materials in the
air over storage piles.
• Determine runoff water composi-
tion from coal or shale piles.
cannot be predicted, especially in view of the
weathering effects on coal composition.
There are techniques that could be used to contain
effluents from storage piles. Silo storage is such a
technique; however, since this solution could be
expensive, it would be worthwhile to determine the
magnitude of the potential problem. The technical-
effort needed to obtain the appropriate information
is indicated in table 3.
Acid Gas Systems
Although acid gas cleanup has been practiced for
some time in the petroleum industry, the prospect of
deriving synthetic fuels from coal and from shale and
the need for releasing cleaner effluents emphasize
certain shortcomings of the available technology.
Most acid gas removal processes involve absorption of
H2S, CO2, COS, etc., in a suitable medium. These
processes, including hot carbonate scrubbing, amme
scrubbing, low temperature scrubbing with methanol,
and others have been available for a number of years.
(refs. 4-6 are examples of many publications on the
subject, and ref. 7 pertains to recent discussions of
several available processes.) Acid gas removal
generally follows shift conversion in a gasification
plant. The hot gases from the shift converter must be
cooled to the absorption temperature which can
result in a loss of thermal efficiency of 3 percent or
more. The removal of sulfur compounds by reaction
with solids is expensive, and the spent solids represent
a disposal problem. Thus, incentives exist for research
aimed at developing a high temperature system for
acid gas removal.
Another deficiency of present day acid gas removal
processes, when applied to coal gasification, results
from the low ratio of KfeS to COa in the effluent
streams. This problem arises from the inability of the
scrubbers to remove CO2 without contamination
from HzB. Thus, the sulfur plant must accommodate
the additional volume of CO2- Present practice
310
-------
Table 4. Technology needs for acid
gas removal and treating
• A cheap, efficient, high tempera-
ture cleanup system
• Selective removal of most of the
C02 in a stream pure enough to
allow venting
• A cheap, clean process to effi-
ciently convert r^S to sulfur (or
nonpolluting compounds of sulfur)
that effectively takes care of
other trace impurities such as
NH3, COS, HCN, hydrocarbons,
etc.
usually involves oxidation of H2S in Claus plants, but
this process is difficult to operate with a feed that has
a low concentration of HaS. If a process were
available for removal of a large fraction of the CO2 at
a purity sufficiently high to allow direct venting to
the atmosphere, then the sulfur problem would be
much easier to manage. A process that could
inexpensively remove HjS from concentrated CO2
would be a good alternative to selective absorption.
Besides the Claus process, a number of other
processes are available for oxidizing HaS to sulfur
(e.g., see ref. 8). Some of these are able to treat low
concentrations of HyS. but they are expensive and
produce water streams that are toxic and difficult to
treat (ref. 9). Also, most do not oxidize COS to
sulfur.
Claus plants produce a tail gas that contains too
high a concentration of gaseous sulfur compounds to
allow venting. In many cases, these sulfur compounds
must be removed by tail gas treatment. A number of
processes are availabe or are under development to
accomplish this (refs. 10-12), but they are expensive
and have problems such as noxious effluents, inability
to handle streams high in CC<2 content, or products
that are difficult to dispose of.
If the H2S-containing stream is not oxidized in a
Claus plant, then another problem may arise. Traces
of other components, such as NHa, COS, or light
hydrocarbons, may be present along with the HaS.
These compounds may go through the sulfur
production step unaffected, or they may interfere
with the sulfur recovery process.
The technology needs in the area of acid gas
removal and treatment are summarized in table 4.
Dirty Process Water Treatment
The area of water effluent treatment needs better
definition. One of the chief concerns, as evident in
the literature, is the need for phenol removal.
Biological oxidation has been investigated as a means
for destruction of phenols, and this technique seems
to work (e.g., see refs. 13, and 14). As a result, some
coal conversion process designs show a biological
oxidation unit with dirty water going in and clean
water coming out. This oversimplifies the few facts
that are available.
Biological oxidation units remove about 90 percent
of the biological oxygen demand (BOD) (refs. 13, and
14). Literature is scarce, however, on the types of
chemicals that are not removed. The 10 percent BOD
that is not removed may represent carcinogenic or
other harmful materials. Furthermore, BOD is not the
same as total dissolved organics (TDO). The Bureau
of Mines has published a list of organic compounds
identified in tar from the Synthane process (ref. 15).
The compounds included condensed ring aromatics
and N-heterocyclics. Some of these compounds may
be refractory toward biological removal and hence
may escape into the environment. When total water
recycle is used, the problem may be magnified;
materials that are not removed in the water-treating
facility will tend to build up in the recycled water.
The chemicals can emerge into the environment from
evaporation, with spray from the cooling towers, and
in ash sludges.
In addition to potential problems associated with
organic materials, problems may also exist with
inorganic substances. For example, cyanides and
thiocyanates were removed only partially in one
installation (ref. 13). Surprisingly, even ammonium
ions were not effectively removed. Trace elements
would also tend to accumulate in recycled water.
Technology needs in water pollution abatement are
summarized in table 5.
Trace Elements
The final major area of concern to be discussed
here, and one about which almost nothing is known,
is the fate of trace elements in all types of fossil fuel
conversion processes. A compilation of available
information has been published concerning trace
elements in coal, petroleum, and shale (ref. 16), but
little information is available concerning the fate of
these elements when these fossil fuels are used. The
311
-------
Table 5. Technology needs in dirty
water treatment
• A study of compounds in water
feed to, and effluent from, bio-
logical treatment of water from
coal gasification and coal and
shale liquefaction.
• A study of other techniques for
cleaning up this water.
literature may be summarized briefly. The
concentration of various toxic metals was determined
for particles of different sizes in particulates in urban
air (ref. 17). A study was made of the fate of trace
elements during combustion of coal in experimental
and industrial furnaces (ref. 18). Mass balances have
been made for 34 elements on a coal-fired power
station (ref. 19). Finally, the disappearance of a
number of elements was studied during coal
gasification (ref. 20). The last reference shows that a
number of elements disappeared from the ash during
gasification, but their fate was not determined. The
problems associated with obtaining good material
balances point out the critical need for proper
sampling and analyses of trace elements.
One potential problem concerning trace elements is
the possibility that hazardous elements may be
concentrated in some process area and may enter the
environment in concentrations much larger than
those in the original fossil fuel. When data are
available, this aspect of the problem should be
analyzed in more detail.
Another possible source of trace element pollution
is the use of limestone type materials in flue gas
scrubbing. Elements that may exist innocuously as
oxides or carbonates in limestones could be released
as soluble ions when contacted with SO2 in flue gas
scrubbing. Work that will furnish some information in
this area will be carried out at Exxon Research and
Engineering Company in connection with
government-sponsored work on coal combustion in
the presence of SO2 acceptor materials. Further work
is needed on flue gas scrubbing.
In the area of trace elements, table 6 lists the
technology needs that have been identified.
Other Technology Needs
Several other areas where new or improved
technology needs are evident will be mentioned
briefly:
Table 6. Technology needs in the
area of trace elements
• Material balances of trace ele-
ments in all types of fossil
fuel conversion processes:
- Coal and shale liquefaction
- Coal gasification
- Coal combustion
- Flue gas desulfurization
- Petroleum processing
• Process development to remove
trace elements where such pro-
cesses are needed.
(1) Raw Gas Scrubbing—Large thermal
efficiency losses and other technical problems
accompany the removal of particulates and tars from
coal gasifiers. More efficient techniques are needed.
(2) Lock Hopper Pressurization—Dirty gases
cannot be used to pressurize lock hoppers, and
thermal efficiency losses occur when clean gas is used.
Better techniques are needed to feed solids to
reactors.
(3) Noise—Noise is not usually discussed as a
pollutant. It has been found, however, to be a
problem in a relatively simple conversion process for
producing SNG (ref. 21). The pressurization and
depressurization of a large number of lock hoppers
( could, by itself, cause a noise problem. The problem
needs better technical definition.
(4) Odors—Like noise, odors can present a
problem that is not easily defined. Biological
oxidation facilities could be especially obnoxious.
Again, there is a need for better technical definition
of the problem.
(5) Solid Wastes-Assuming that solid waste
materials can be changed into all-inorganic effluents,
the problem is reduced to that of determining the
teachability of trace materials into water supplies and
would use the technology discussed under trace
elements. Studies on spent oil shale have shown that
minor elements are easily leached (ref. 23).
CONCLUSIONS
Although all technology needs for pollution control
have not been discussed, and since many problems are
specific to a particular process at a single location, a
number of areas have been identified that are of
general concern. The most immediate need is for
information, since in many cases a decision cannot be
312
-------
made as to whether or not a problem does exist. The
technical difficulties in obtaining this information are
large and, in many cases, the techniques for obtaining
the information (sampling, analytical, etc.) are not
fully developed.
The overall problem with defining the pollution
aspects of fossil fuel conversion is amplified by the
fact that, in most cases, the quantities of pollutants
are small when compared with the total plant
effluent. Thus, there is a tendency to brush aside the
question of pollution with a reference to past
experience in some other industry. With some of the
new technology that will emerge in the area of fossil
fuel conversion, with the high concentration of trace
elements and aromatic materials in coal and shale,
and with a new awareness of environmental needs, it
is possible that minor problems may become major,
and that completely new problems may appear. The
incentives for research and development in the area of
pollution control of fossil fuel conversion processes
are certainly larger than ever before.
REFERENCES
1. H. J. Hall, and G. M. Vargo, Jr., and E. M. Magee,
"Trace Elements and Potential Toxic Effects in
Fossil Fuels," This Symposium.
2. C. E. Jahmg, E. M. Magee and C. D. Kalfadehs,
"Overall Environmental Considerations of
Conversion Technology," This Symposium.
3. H. H. Lowry. (ed.) "Chemistry of Coal
Utilization, Supplementary Volume," John Wiley
and Sons, Inc., New York, 1963.
4. S. Katell and J. H. Faber, "New Costs for Hot
Carbonate Processes," Petroleum Refiner, Vol.
39, No. 3 (1960), p. 187.
5. N. C. Updegraff and R. M. Reed, "25 Years of
Progress in Gas Purification," The Petroleum
Engineer, September 1954, C-57.
6. G. Ranke, 'The Rectisol Process for the Selective
Removal of CO2 and Sulfur Compounds from
Industrial Gases," Chemical Economy and
Engineering Review. Vol. 4, No. 5 (No. 49) (May
1972), p. 25.
7. Abstract of Papers, 167th National Meeting of
The American Chemical Society, I&EC Division,
Los Angeles, April 1, 1974.
8. B. G. Goar, "Today's Sulfur Recovery
Processes," Hydrocarbon Processing, Vol. 47,
No. 9, (1968), p. 248.
9. J. E. Lundberg, "Removal of Hydrogen Sulfide
from Coke Oven Gas by the Stretford Process,"
64th Annual Meeting of the Air Pollution
Control Association. Atlantic City, June27-July
2,1971.
10. C. B. Barry. "Reduce Claus Sulfur Emission,"
Hydrocarbon Processing April 1972, p. 102.
11. J. C. Davis, "Add-On Processes Stem H2S,"
Chemical Engineering. May 15, 1972, p. 66.
12. J. E. Naber et al., "New Shell Process Treats
Claus Off-Gas," Chemical Engineering Progress.
Vol. 69, No. 12 (1972). p. 29.
13. P. D. Kostenbader, and J. W. Fleckstemer,
"Biological Oxidation of Coke Plant Weak
Ammonia Liquor," Journal WPCF. Vol. 41. No.
2 (1969), p. 199.
14. E. F. Mohler Jr.. and L. T. Clere, "Development
of Extensive Water Reuse and Bio-Oxidation in a
Large Oil Refinery," from "Complete Water
Re-Use," L. K. Cecil, (ed.), Papers presented at
the National Conference on Complete Water
Re-Use, April 23-27. 1973, AlChE, New York.
15. A. J. Forney et al.. "Analyses of Tars, Chars,
Gases and Water Found in Effluents from the
Synthane Process," BuMines Technical Progress
Report 76, January 1974.
16. E. M. Magee, H. J. Hall, and G. M. Varga. Jr.,
"Potential Pollutants in Fossil Fuels," EPA
Report No. EPA-R2-73-249, NTIS PB-225 039,
June 1973.
17. R. E. Lee et al., 'Trace Metal Pollution in the
Environment," J. of Air Pollution Control. Vol.
23, No. 10(1973).
18. H. Schultz et al., 'The Fate of Some Trace
Elements During Coal Pretreatment and
Combustion," ACS Div. Fuel Chem.. Vol. 8, No.
4 (August 19, 1973), p. 108.
19. N. E. Bolton et al., 'Trace Element Mass Balance
Around a Coal-Fired Steam Plant." >4CS Div.
Fuel Chem., Vol. 18. No. 4 (August 1973). p.
114
20. A. Attari. 'The Fate of Trace Constitutents of
Coal During Gasification." EPA Report
650/2-73-004. August 1973.
21. D. E. Anderson. "First Large-Scale SNG Plant."
TV?? Oil and Gas Journal, January 21, 1974, p.
74.
22. Power, No. 2 (February 1974), pp.S11-S24.
23. Colorado State University, "Water Pollution
Potential of Spent Oil Shale Residues," for EPA,
PB-206808, December 1971
313
-------
314
-------
LOW BTU GASIFICATION OF COAL:
"WHO NEEDS IT AND HOW CAN IT BE IMPROVED?"
R. A. Ashworth and B. C. Hsieh*
Abstract
The questionable availability of natural gas and
petroleum feedstocks is responsible for various
marketing areas opening up for low-Btu coal gas.
Commercially available low-Btu coal gasifiers fulfill,
to various degrees, the gasifier attributes required for
these new market areas. This paper centers attention
on two of the areas, industrial heating and advanced
gas turbine/steam turbin electric power generation.
The desired attributes of low-Btu coal gasification
systems are compared with the commercially proved
gasifiers to determine further research and
development needs. For the. industrial heating
application, modest research and development is
required; however, intensive development work is
required for the advanced combined cycle
application. A comprehensive low-Btu coal
gasification research and development effort for these
two market areas will cost an estimated $350 million
over the next 15 years.
INTRODUCTION
For the first time in this country since the demise
of the coal gas producer at the hands of clean and
cheap natural gas, low-Btu coal gasification is being
seriously considered by private industry. The
questionable availability of natural gas and petroleum
feedstocks is responsible for various marketing areas
opening up for low-Btu coal gas. Low-Btu gasification
of coal is a viable alternative for many markets, such
as industrial heating, ammonia synthesis, synthesized
chemical feedstocks, and electric power generation.
For electric power generation, it could replace the
scarce fuels now being used in conventional
fossil-fueled plants or combined cycle plants. It also
has application to future advanced power cycles
which will require clean fuels, such as advanced
combined cycles, fuel cells, and possible MHD.
We have addressed ourselves to the needs of two of
these market areas: industrial heating and advanced
gas turbine/steam turbine cycles for electric power
generation.
•The authors are with Gilbert Associates, Inc., of Reading,
Pennsylvania.
For these two applications, the question is "Can
commercially available gasifiers be used to fulfill the
needs, especially in light of the greater process and
environmental restrictions which may be required?"
COAL GASIFIER ATTRIBUTES
Figure 1 shows a generalized list of desired
requirements for modern day gasifiers as applied to
industrial heating and advanced combined cycle
power plants. In addition, the manufactured gas must
be produced at a total cost that is competitive with
other energy forms.
By comparing the attributes of the coal gas
producers commercially available today (Lurgi,
McDowell-Wellman, Winkler, and Koppers-Totzek)
with the desired attributes, attention is focused on
the improvements required through advanced
research and development. Commercially available
gasifiers can now fulfill many industrial heating
needs. Therefore, modest research and development
effort should suffice for industrial heating
applications. However, these gasifiers do not reach
the same level of competence in satisfying the more
demanding requirements of the combined cycle
power systems. Research and development efforts for
this application must therefore be more intensive.
Following is a review of the various desired gasifier
attributes and the areas where today's gasifiers fall
short of our objectives.
Nontar Producing Gas
A coal gas containing tars presents special
problems. If tars are present in the coal gas, it is
necessary to quickly quench the gas with water as it
exits the gasifier in order to prevent related tar
condensation problems on heat exchangers and
pipeline internals. Consequently, besides tar being
somewhat messy to handle, thermal energy is lost in
the quench. The fluidized bed Winkler and entrained
bed Koppers-Totzek gasifiers can satisfy the desired
nontar characteristic because of their high gasifier
temperature profile. Fixed beds, because of low
design outlet temperature, will always produce tars
when bituminous coal is used as a feedstock.
However, tar production is not a problem when
anthracite coal is used.
315
-------
INDUSTRIAL HEATING
ADVANCED COMBINED CYCLE POWER
Non-Tar Producer Gas
I
Caking and Non-Caking Coal Feed Capabilities
Air Used For Oxidation
I
— High Reaction Rates —
I
High Carbon Utilization
I
Low Thermal Loss
Easy Operability
-Low Pressure (<20 psig)-
Livable Operabilicy
High Pressure (300-500 psig)-
- High Capacity (200-400 MW)—
Limited Steam Injection —
"igure 1. Desired coal gasifier attributes
To eliminate tar formation from a bituminous coal
feedstock, the coal gas must be retained at
temperature long enough to allow complete cracking
of the tar before it leaves the high temperature
region. Consol (ref. 1) has reported that, for a
subbituminous coal feedstock, a gasifier temperature
of 1,700°F and vapor retention time of 15 seconds
produces essentially a nontar gas; however, there is
some residual naphthalene. Fifteen seconds for a
fairly fast fluidized or entrained bed gasifier is a long
retention time. To eliminate tar-producing
possibilities, it would seem necessary to maintain
gasifier temperatures somewhat higher than 1,700°F.
However, the lower the gasifier temperature the
better, as it maximizes the Btu content and limits the
sensible heat content of the off-gas. Research and
development is needed to define the tar-producing
parameters for various rank coals in the entrained and
fluid beds.
Caking and Noncaking Coal Feed Capabilities
Since there are relatively large quantities of caking
bituminous coals in the Eastern United States, it
would be advantageous to be able to gasify these
coals. All three commercial gasifier types (fixed,
fluidized, and entrained beds) have demonstrated an
ability to gasify caking coals. The fixed bed gasifier
has been demonstrated on a pilot scale (ref. 2), but
not on a commercial scale. The fluidized bed has been
used commercially for gasification of caking coal (ref.
3) at atmospheric pressure, but not at high pressure
(ref. 4). Entrained beds (ref. 5) present no problem in
handling caking coals.
The need is to prove commercial scale-up of the
deep-stirred fixed bed concept so that caking coals
can be used directly, without pretreatment, in a fixed
bed gasifier. The fluidized bed concept needs to be
proved on a commercial pressure gasifier; parameters
should also be set for degree of mixing required for
various rank coals.
Air for Oxidation
The use of air for gasification has been adequately
shown on a commercial scale for fixed and fluidized
beds; however, this is not the case with an entrained
bed, such as the Koppers-Totzek gasifier. For the
one-stage entrained bed gasifier, the gasifier
temperature must be maintained at a relatively high
level in order to provide good carbon conversion
efficiency and to keep the ash in a molten state. To
yield a combustible Btu content in the gas, air, and
steam, preheating may be required. The possibilities
of using a one-stage entrained bed gasifier. with air as
the oxidizer, should be explored to determine the
feasibility of this approach. The use of oxygen for
these two low-Btu fuel gas applications is not
316
-------
necessary and is somewhat costly. For the longer
term, two-stage entrained bed gasifiers, both high and
low pressure, should be developed.
High Reaction Rates
High reaction rates, or high throughput per unit
volume, is perhaps the main reason research work is
being diverted away from the fixed bed concept to
the fluidized and entrained bed types. Since increased
temperature, pressure, and gas-solids mixing tends to
yield greater throughput per unit volume, the
entrained gasifier promises the greatest throughput
approach. However, complete entrainment of the coal
particles requires delicate control, which can diminish
stability of operation. For industrial heating
purposes, the fixed and fluidized bed approaches
should fulfill most needs. Fluidized and entrained bed
gasifiers will compete for advanced combined cycle
power application. However, one should not
eliminate the fixed bed altogether; it is a good
backup.
Though somewhat subject to debate, we can
probably generalize and say that: fluidized beds seem
to be the best approach to meet intermediate electric
power loads and that the entrained beds seem more
suitable for base loads.
High Carbon Utilization
To yield the desired high carbon utilization, the
two-stage approach applied to entrained and fluid
beds may be appropriate. The second stage is
provided to effect burnout of the unreacted carbon
carried out with the first-stage exit gas and also to
increase coal throughput. One stage is sufficient for
the fixed bed approach because of the long residence
time of coal in the gasifier and the countercurrent
flow characteristics of the bed. The one-stage fluid
bed Winkler, because of high carbon loss with the ash.
yields relatively low carbon utilization. Because of
high carbon loss with the ash, yields relatively low
carbon utilization. A two-stage atmospheric fluid bed
gasifier development would seem to be beneficial for
industrial heating applications. It should provide a
nontar gas, fair turndown ratio, and livable operating
capability. In addition, it could be used a precursor
development to the pressurized two-stage fluid bed
gasifier for electric power generation. A two-stage
atmospheric entrained bed gasifier should be
developed to provide good carbon utilization with air
as the oxidizer. It would also provide a stepping stone
to the pressurized two-stage entrained bed approach
for advanced combined cycle power.
Low Thermal Loss
Heat transfer to low temperature heat sinks is a
problem in coal gasification. In off-gas cooling, heat
exchanger tubes must not exceed much more than
600°F. This is due to the corrosive nature of the
H2S-H2 atmosphere. When a coal gasifier is used for
electric power generation, some thermal efficiency is
lost to these low temperature sinks; the corrosion
potential at higher tube wall temperatures being the
limiting factor. Necessary water jacketing
requirements for entrained bed slagging zones is also a
potential heat loss in low temperature heat sinks.
Pressure gasification further increases the refractory
problems in these hot zones due to increased heat
transfer coefficients. Another unsolved problem is the
ability of refractory to withstand slag corrosion
attack in a reducing atmosphere.
For an advanced gas turbine/steam turbine electric
power plant, heat loss to low temperature heat sink in
the off-gas can theoretically be minimized by
removing the H2S and participate hot. The gas
cleanup aspects of coal gasification will be considered
later. The Btu content of low-Btu gas, with air as the
oxidizer. is sensitive to heat loss; as air is added to
maintain temperature, the added nitrogen must not
only be heated up, but also acts as a diluent, lowering
the Btu content of the gas. Heat loss with low-Btu
gasification schemes can become quite critical.
Operability
To make coal gasification useful for industrial
heating, the gasifier supplied should be easy to
operate. When a high pressure gasifier is connected to
a gas turbine, the operation is not simple; however, it
must be livable!
Fixed bed gasifiers operating at low pressure are the
easiest to operate. Turndown ratio is very good. The
gasifiers can be banked and restarted with ease (ref.
6). The fluid and entrained beds have lower turndown
capabilities, and instrument control is more
sophisticated than with the fixed bed. Pressure
systems increase possible operational control
problems by orders of magnitude for any of the three
gasifier types.
Pressure
High pressure coal gasification is not required for
most industrial heating needs. However, for combined
gas turbine/steam turbine power plants, it is necessary
from an overall thermal efficiency standpoint. Less
317
-------
power is required to compress air for a pressure
gasifier than to compress an atmospheric gasifier
off-gas, because there is less gas. at higher density, to
compress. Fixed bed gasifiers (Lurgi} have been
commercially demonstrated at 285-430 psig (ref. 7).
Fluidized and entrained beds have not been
demonstrated at these high-pressure levels. The
pressure cases present some difficult problems which
must be overcome for both the fluidized and
entrained beds. There is also room for improvement
in the commercially demonstrated fixed beds.
Capacity
The gasifiers available today are of sufficient
capacity per unit to satisfy most industrial heating
needs. High capacity units, however, are needed for
electric power generation, due to the large heat input
requirement. For this reason, we have given values of
200-400 MW capacity per gasifier unit as a goal for
developmental effort in the field of electric power
generation. As mentioned under "High Reaction
Rates," the fluidized and entrained bed approaches
yield the higher throughput potential. Fixed bed
gasifiers, even high pressure ones, require tremendous
land area for an average size power plant. Using the
STEAG Power Plant at Lunen (Germany) as a model,
an estimated 18 {12-ft diameter) fixed bed gasifiers
would be required for a 600 MW combined cycle
power plant (ref. 8).
For the short range, atmospheric pressure.
air-blown entrained bed gasifiers should be developed
for the combined cycle application. For the longer
range, pressurized fluid and entrained bed gasifiers
should be developed to provide better energy
utilization through increased overall thermal
efficiency.
Steam Injection
Water added to the gasifier unit is, in the final
stage, vented to the atmosphere as a vapor, and much
heat is lost due to its high latent heat of vaporization.
Steam in excess of that required for gasifier
temperature control and gasification reactions should
be minimized. A low temperature liquid scrubbing
system is another place for water addition, via water
evaporation from the scrubbing medium to the coal
gas. One of the goals in any process application is to
minimize heat loss. It is particularly true for electric
power generation where overall thermal efficiency is
extremely important. Fixed bed gasifiers require
steam, not only for gasification, but also for grate
cooling. Lurgi gasifiers with air, require about 0.7 Ib
steam/lb of subbituminous coal (coal contains 16.5
percent H20) (ref. 7). Winkler, with oxygen, quotes
0.16 Ib steam/lb of 8.6 percent moisture lignite (ref.
9). Koppers-Totzek, with oxygen, quotes 0.16 Ib
steam/lb of 2 percent moisture subbituminous coal,
and 0.29 Ib steam/lb of 2 percent moisture Eastern
coal (ref. 5).
MISCELLANEOUS GASIFIER SUPPORT
Besides the major gasification work, much support
work would speed up the overall development of the
low-Btu coal gasification program. Hot char valves,
hot gas valves, hot flanges, hot char recycle, coal feed,
and ash removal development programs are very
necessary. Metallurgy and refractory development
also need intensive side developmental effort.
One item that needs to be more clearly recognized
and developed is the instrumentation response and
surge capacity required to provide constant fuel gas
pressure to the gas turbine, when used in a combined
cycle power application. In the pressure Lurgi gasifier
combined cycle power plant at Lunen (Germany), no
surge capacity is installed other than the vessel
capacities themselves (ref. 8). Since many Lurgi
gasifiers are required for a moderately sized combined
cycle power plant, the gasifiers proper may supply
enough surge volume so that added volume will not
be necessary (five gasifiers are required for a 170 MW
unit). However, this may not be the case with higher
throughput per unit volume gasifiers.
Supplemental kinetic and thermodynamic studies
may be necessary to aid in scale-up work. Other areas
such as economic and operation system studies,
environmental impact considerations, and safety
analysis for the high pressure cases should also be
investigated.
GASIFIER CLEANUP
Besides the gasifier proper requiring changes to
adapt to today's needs, the gas cleanup required for
environmental and/or process considerations must be
of greater refinement than anything we have needed
in the past.
In respect to coal gasification, concern for the
environment revolves around two major air
pollutants: hydrogen sulfide. which would eventually
end up as SO2. and participate. In addition, if a
tar-laden gas is produced, water pollutants such as
ammonia, phenols, cyanides, etc., must be addressed.
When the coal gas is finally combusted, another air
318
-------
pollutant form. NOX. is produced. These
environmental considerations play an important part
in any gasification system development.
In figure 2, the environmental and process
restrictions are shown for gas effluents as they apply
to industrial heating and combined cycle power use.
Environmental restrictions are the same in both cases,
but added process restrictions are placed on the
combined cycle application. Paniculate and alkali
metal limits are quite restrictive because of erosion
and corrosion potential on the gas turbine blades.
At the time of the writing of this paper, the
Environmental Protection Agency had not released
water effluent standards for coal gasification plants.
The assumption we made is that the standards would
be similar to those for byproduct coke manufacture,
since the contaminant problems are the same. In
figure 3, the recently published EPA standards (ref.
12) for new byproduct coke plants are shown.
If cold gas cleanup is specified, the gas cleaning and
water contaminant processing aspects should consist
only of selection and application of existing
commercial processing know-how. Commercial
processes are available that should do the job. but
necessary demonstrations on coal gas must be
performed.
Hot gas cleanup (1,400° to 1,600°F range) is quite
another matter. Process development, in this area, is
just beginning. As mentioned previously, hot cleanup
of hydrogen sulfide and paniculate has potential
application possibilities in advanced combined cycle
power systems. The prime reason for hot cleanup is
to provide increased overall thermal efficiencies (ref.
13). The two major gas contaminants, hydrogen
sulfide and particulate, must be addressed when hot
gas cleanup is considered. For hydrogen sulfide
removal, molten salt (ref. 14), iron oxide (ref. 2), and
limestone or dolomite (ref. 15) processes are perhaps
the front-runners in the research and development
stage. To date, however, there is no clear cut choice
among the three. The molten salt process must
contend with alkali carryover and fly ash
contamination of the salt. Iron oxide has shown good
potential, but liberates sulfur as SO2, which requires
more extensive processing to obtain elemental sulfur
than is required with H2S. The limestone and/or
dolomite process concepts have been plagued with an
inability to regenerate CaS stone back to CaC03.
Hot particulate removal process development has
not been extensive to date, and increased effort is
necessary. The hot particulate removal cannot be
separated from the hot H2S removal; they go hand in
hand. Particulate removal is critical to the success of
hot gas cleanup because of the stringent inlet gas
turbine requirements. The panel bed filter (ref. 16)
looks very promising for this application.
RESEARCH AND DEVELOPMENT COST
In scanning the R&D needs for low-Btu
gasification, we considered here only the more
conventional approaches to coal gasification and coal
gas cleanup: fixed, fluidized, and entrained bed
gasifiers, and gas cleanup system indepdent of the
gasifier proper. Furthermore, we have looked only at
the coal gasffier island, which includes the gasifier
proper and the gas cleanup systems required to
deliver a fuel gas to a boundary limit which would
satisfy the fuel requirements of an industrial heating
or a gas turbine/steam turbine power plant
application. Gas turbine development and molten salt
and molten metal gasifiers are not included, but
should not be overlooked. These plus advanced power
concepts, such as topping and bottoming cycles,
magneto-hydrodynamics, fuel cells, etc., should, and
are, being investigated.
We will now take a look at estimated cost and time
frames needed to accomplish the outlined
development. The development has been structured
on the premise that the work is important to our
national well-being and security. The comprehensive
approach proposed here is perhaps costly, but should
insure success in the smallest increment of time; time
rather than money being considered of prime
importance. The problem was approached from two
viewpoints. (1) the ambitious, and (2) the
conservative. Since time is important, we put
emphasis on the ambitious approach; however, the
conservative is there for backup. The proposed
research work includes the simultaneous development
of the conservative and the ambitious approaches in
order to more assuredly meet short-range as well as
long-range goals.
In figures 4 through 8, we include time and money
for the fixed, fluid, and entrained bed gasifiers,
miscellaneous gasifier support, and gas cleanup
development. The estimates show time and cost
required to develop the various concepts to a
commercially acceptable state-that is, to develop the
process to a point where industry will accept it. The
costs and time frames required for the combined
cycles cases do not include gas turbine development,
or power plant capital and operating cost
requirements.
In figure 4, the developmental effort for the fixed
bed gasifier is shown to be nominal, approximately
319
-------
INnUSTRIAl. HFATINC I ADVANCED COMBINED CYCLE POWER
•\-1000 ppm H2S In fuel gas S ISO Btu/scf co yield 1.2 Ib S02/MM Btu input
PARTICULATE
i0.2gr/scf in fuel gas ^
ALKALI METALS
2-6 MICRON: 0.001 gr/scf in the
combustor expansion gas with 6
microns upper limit: on particle
size
40 ppb maximum allowable limit in
eonbustor expansion gas H ———
HOx*
I
0.2 Ib/KH Btu heat input (based on gasj
0.7 Ib/MM Btu heat input (based on coal)
* Logically, standard could be based on either gas or coal as fuel.
Figure 2. Environmental and/or process restrictions - gas effluents
CYANIDE
PHENOL
AMMONIA
B.O.D.**
SULFIDE
OIL 6 CREASE
TSS***
pH
Maximum for any one day
Ib/ton coal*
0.0006
0.0011
0.0237
0.0474
0.0009
0.0237
0.0237
Within the range of 6.0 Co
Maximum Average for Any
30 Consecutive days
Ib/ton coal*
0.0003
0.0006
0.0120
0.0237
0.0003
0.0120
0.0120
9.0
* E.P.A. Standards for by-product coke manufacture. Adjusted from coke
to coal by dividing by 0.7.
** Biological oxygen demand.
*** Total suspended solids.
Figure 3. Environmental restrictions - water effluents
320
-------
To Commerrially Demonstrate
Estimated Cost
In 197-4 Dollars
$MM
A. Coal Feed Capability*
1. Caking Coal
2. Coal Fines
B. Non-Water Jacket Construction*
(Hi-press.)
C. Large Diameter (assume 18 ft,
Low-press.)
TOTAL ESTIMATED COST (Gasifier
Islands Only)
*10 ft diameter gasifier.
Estimated Time
Frame, Years
4-6
8-10
8-10
2.5
3.4
7.1
13.0
Figure 4. Fixed bed gasifier improvement
$13 million. Developmental effort for the fluidized
bed gasifier, figure 5, and the entrained bed gasifier,
figure 6, is considerable, $103 and $125 million,
respectively. In addition to costs for the gasifier
proper, miscellaneous support development (figure 7)
was estimated at approximately 25 percent of the
total gasifier proper development, $70 million. In
figure 8, the time and money requirements for cold
gas cleanup application and hot gas cleanup
development are shown at approximately $5 and $30
million, respectively. In summation of the above, over
the next 10 to 15 years, research and development
effort to accomplish the proposed goals would place
overall costs in the neighborhood of $350 million.
We Americans have great expectations, and in our
short history we have generally realized our
expectations in a relatively short time. Unfortunately,
research and development in the field of coal
conversion will require both time and money. We
could not forsee the difficult problems concerning
energy and the environment, so now we are faced
with crash programs. However, coal conversion
development is very difficult and will not proceed as
quickly as many would like. With coal conversion
processes, we are immersed in the real and dirty
world, and we must yield processes that perform
reliably for 20 to 30 years.
Since our energy demands are here, we should
implement the commercially available processes for
coal conversion wherever possible and proceed, this
time, with a realistic research and development
program to let us be prepared for the future. Since we
were behind before we started, the crash development
approach is necessary, however, for backup we should
also concurrently proceed with the conservative
approach to insure against complete failure in the
event that we are unable to attain the ambitious
goals. We feel that onsite generation of low-Btu gas is
an attractive coal conversion approach that should be
fully investigated to determine its role m supplying
our energy needs.
Acknowledgmen t
We would like to thank the Office of Coal
Research, Department of the Interior, for its
cooperation in the writing of this paper.
REFERENCES
1. G. P. Curran, C. E. Fink, and E. Gorm,
"Production of Low-Sulfur Boiler Fuel by
321
-------
CO
K>
ro
To Comncrclally Dennnstr.ite
Estimated Cost
In 1974 Dollars
SUM
Estimated Tine
Frame. Years
4 - 6
A. One Stage Atmospheric Caslfler*,
1 unit
1. High carbon utilisation
2. Air as oxldlzer
B Two Stage Atmospheric Cp-lfler*,
!• unit 6-8
1. Hot chnr recycle
2. Air as oxldlzer
C. One Stage Pressure Goslflcr 10 - 12
(300-500 pslg)**, 1 unit
1. Caking coal feed capability
2. Conl feed and ash removal
capability
3. Non-water jacket construction
4. Air as oxldlzer
D. TWo Stage Pressure Gaslfler 12 - 15
(300-500 pslg)**, 2 units
1. Hot char recycle
2. Caking coal feed capability
3. Cool feed and ash removal
capability
4. Non-water jacket construction
5. Alt' as oxldlzer '
TOTAL ESTIMATED COST (Gaslfler Islands Only)
25
70
103
* 5 ton/hr gaslfler for Industrial heating application
** Gaslfler Island to supply thermal output for a 100 MW power plant
To Commercially Pgrom.itratc*
Estimated Time
Frame. Years
4-6
6 -
12 - 14
A. One Stage Atmospheric Uimfler,
1 unit
1. High carbon utilization
2. Air as oxldlzer
B. Two Stage Atmospheric Caslflcr,
1 unit
1. Hot char recycle
2. Air as oxldlzer
C. One Stage Pressure Gaslfler,
(300-500 pslg). 1 unit
1. Coal feed and slag removal
capability
2. Non-water jacket construction
3. Air as oxldlzer
D. Two Stage Pressure Caslflet
(300-500 pslg). 2 units 14 - 16
1. Hot char recycle
2. Coal feed and slag removal
capability
3. Non-water jacket construction
4. Air as oxldlzer
TOTAL ESTIMATED COST (Caslfler Islands Only)
Lstlmaled Lost
In 1974 Dollars
15
70
25
65
125
* Caslfler Island to supply thermal output for a 100 MW power plant
Figure 5. Fluid Bed Gasifier Development
Figure 6. Entrained Bed Gasifier Development
-------
CO
A.
a.
Hoc Clinr Valvos
Hocalltirgy
1. Prosnuro vessel containment
2. Corrosion-erosion studios
To Commercially Demonstrate
Kilt Imnli'd Gout
Bndmntcd Time In 197* Dollars
PrnnfjrpnrM SMM
C. Refractory
1. SlnuHlns stags application
2. Salacclan and installation
D. Pressure Systems
1. Hoc clmr rucyel*
2. Coal food
3. Sluti runiovul
E. Surge Volume and Concrola for Comblnad Cyclea
P. Caalflar Ralaeod Inacrumencacion and Control Devices
G. Hoc Can Valvoo and Klangea
II. Klnutlc-lliuraoilynunlc Scudloa
I. Syucum licoiiomle and Opuraclon Scudlaa
J. rnwlronmuncal Impact
K. Sufucy Anulyul*
Entlnata coat at 23 percent of goelfler loland development,
$70 MM.
Figure 7. Miscellaneoua eupport development
Cold One Cleanup*
1. Sulfur removal (H2S, COS.
C&2) systems, 2 unlea
2. Parcleulate removal •yatani.
2 untto
3. Wanto water cleanup systems,
2 units
TOTAL USTIMATBD COST
B.' Hot Can Cluunup - Prosouro Syeterns**
1. Hoc sulfur ramovnl (l^S, COS,
€82) syucuma, 2 unit*
2. Hoc pnrciculace romoval iiyacorns,
2 units
TOTAL ESTIMATED COST
4-6
4-6
4-6
10 - 14
10 - 14
2.4
0.8
4.8
20
Coat and tlma frnines Included In gaalfler island development.
2 yuiir duiuoitHtruilou on Clxud bud units.
Estimated
*• Added cose co RaslClor Island tlovolopmcnt for prosnuru no-Car producing
100 MW electric power output capacity coal goo producers.
Figure 8. Gas cleanup application/development
-------
Two-Stage Combustion-Application of CO2
Acceptor Process," paper II1-1 presented at the
Second International Conference on Fluidized
Bed Combustion, Hueston Woods, Ohio, October
4-7, 1970.
2 P S. Lewis, R. V. Belt, and A. J. Liberatore,
"Low-Btu Fuel Gas for Power Generation,"
paper presented at the 1973 Lignite Symposium,
Grand Forks, North Dakota, May 9-10, 1973.
3. H. H. Lowry, Chemistry of Coat Utilization,
Supplementary Volume, John Wiley & Sons,
N.Y., 1963, p. 966.
4. H. C. Hottel and J. B. Howard, New Energy
Technology-Some Facts and Assessments, The
M.I.T. Press, Cambridge, Massachusetts, 1972, p.
159.
5. J. Frank Farnsworth, et al., "Production of Gas
from Coal by the Koppers-Totzek Process,"
presented at the Clean Fuels From Coal
Symposium. Institute of Gas Technology,
Chicago, Illinois, September 10-14, 1973.
6. Discussions with Paul Lewis. U.S. Bureau of
Mines, Morgan town Energy Research Center,
Morgan town. West Virginia.
7. "Application of El Paso Natural Gas Company
for a Certificate of Public Convenience and
Necessity-Docket No. CP73-131." Vol. II.
Federal Power Commission, November 7, 1972.
8. Private conversation with John Gallagher of
American Lurgi Corporation, New York, New
York.
9. I. N. Banchik. 'The Winkler Process for the
Production of Low-Btu Gas from Coals,"
presented at the Clean Fuels From Coal
Symposium, Institute of Gas Technology,
Chicago, Illinois. September 10-14, 1973.
10. "Environmental Protection Agency-Standards of
Performance for New Stationary Sources,"
Federal Register, Vol. 36, No. 247, Part 'll.
(December 23, 1971), pp. 24878-24879.
11. Reported by Westmghouse to the Office of Coal
Research in the gas turbine fuel specifications for
a 1,950°F inlet gas turbine temperature, using a
low-Btu fuel gas. Received permission from D.
Archer, Westinghouse on February 19, 1974 to
include in paper.
12. "Environmental Protection Agency-Iron and
Steel Point Source Category, Proposed Effluent
Limitations. Guidelines, and Standards"; Subpart
A. Byproduct Coke Subcategory, Section 420.14
Standards of Performance for New Sources,
Federal Register, Vol. 39. No. 34. Part II
(February 19. 1974).
13. R. A. Ashworth and G. W. Switzer, Jr., "Low-Btu
G as if iact ion : High Temperature-Low
Temperature H2S Removal Comparison Effect
on Overall Thermal Efficiency in a Combined
Cycle Power Plant," Office of Coal Research,
Department of the Interior, R&D Report No.
79-lnterim Report No. 2, January 1974.
14. R. H. Moore, "Removal of Sulfur Compounds
and Fly Ash from Low-Btu Gases," Battelle
Memorial Institute. Pacific Northwest
Laboratories. Publication BN-SA-210.
15. L. A. Ruth, A. M. Squires, and R. A. Graff,
"Desulfurization of Fuels with Half-Calcined
Dolomite: First Kinetic Data," Environmental
Science & Technology, Vol. 6 (November 1972),
pp. 1009-1014.
16. K. C. Lee, R. Pfeffer, and A. M. Squires, 'The
Panel Bed Filter for Simultaneous Removal of
Dust and Sulfur," paper presented at American
Chemical Society, Division of Fuel Chemistry,
Chicago, Illinois, August 26-31, 1973.
324
-------
ENVIRONMENTAL ASPECTS OF COAL LIQUEFACTION
P. M. Yavorsky and Sayeed Akhtar*
Abstract
The flow system and all effluents will be described
for the SYNTHOIL process, as typical of any
coal-to-oil conversion plant that incorporates sulfur
removal from the product. Disposal of sulfur, waste
off-gas, and waste solid residues will be discussed. The
potential hazards of contaminants in product oil and
in any teachable residues will be examined to show
where chemical data and/or process design
alternatives may be needed.
INTRODUCTION
The urgency of developing processes for converting
coal into clean liquid fuels is widely recognized and
research has advanced to the stage that substantial
private funds may soon be forthcoming for
development. Unfortunately, research on the
environmental pollution problems arising from coal
liquefaction has received little attention. The
significance of this shortcoming can hardly be
overemphasized; lack of technology for the control of
pollutants will seriously impede the development of
coal liquefaction. The siting of even small pilot and
first generation plants may present monumental
difficulties. It is the purpose of this paper to review
the sources of pollution in coal liquefaction, the
status of control technology, and the' areas of
research and development. Research in some of these
areas may also be helpful in advancing the science and
technology of coal liquefaction itself.
COAL LIQUEFACTION
The basic steps in a coal liquefaction process are
shown in figure 1. Although drawn for the
SYNTHOIL process of the U.S. Bureau of Mines, the
figure with minor modification can be made to
represent other coal liquefaction processes as well.
The pollution problems of the pyrolytic processes for
making liquid fuel from coal are not a part of this
study.
The object of the SYNTHOIL process is a convert
coal to a low-sulfur fuel oil. The novel feature of the
'Both authors are with the Pittsburgh Energy Research
Center. Bureau of Mines, U.S. Department of the Interior,
Pittsburgh, Pa.
process is that the liquefaction and
hydrodesulfurization are conducted in a
turbulent-flow packed-bed reactor (refs. 1,2,3).
Slurries of coal in recycle oil and H2 are passed
concurrently through a reactor packed with pellets of
Co-Mo/Si02-AI2O3 catalyst at 450°C and 2.000 to
4,000 psi. The flow of H2 through the reactor is
turbulent, which prevents plugging of the reactor,
promotes H2 transfer to reaction sites, and facilitates
heat removal. Coal is thus liquefied and desulfurized
in one step. The product stream from the reactor is
cooled and led to a gas disengager to separate the
gases from the liquids and unreacted solids. The
separated gases, after purification, are recycled to the
reactor, and the liquids are centrifuged to remove the
unreacted solids. The centrifuged liquid product is a
low-sulfur, low-ash fuel oil, a portion of which is
recycled to convey more coal to the reactor, while
the rest is available as the net product. The solids are
pyrolyzed to yield an additional quantity of
nonpolluting fuel oil. The total yield of oil is thus
about 3 bbl/ton of coal (as received): 2.5 bbl from
the centrifuge and 0.5 bbl from the pyrolyzer. The
carbonaceous residues from the pyrolyzer and some
coal are gasified to product H2 for the process
requirement.
ENVIRONMENTAL IMPACT
The sources of pollution from a coal liquefaction
plant and the R & D needs are as follows:
Gaseous Effluents
The off-gas from a coal liquefaction reactor
contains a number of impurities which must be
scrubbed before recycling the gas. Accurate analytical
data on the impurities are not available, but the
principal impurities are known to be CH4, C2H6,
H2S, NH3, and H2O. A suitable scrub liquid for H2S
and NH3 is water, and for the gaseous hydrocarbons,
an oil. Scrubbing will be conducted at the plant
pressure, and the dissolved gases will be recovered
from the scrub liquid by a pressure and/or
temperature swing. The recovered gases will be
processed to separate NH3 as a salable byproduct,
while H2S will be converted to elemental S for ease
of storage. The hydrocarbon gases will be
325
-------
COAL-
Mixer
Recycle oil
Moke up
Ho
H20,02-
Gosifier ond
shift converter
Ash
Hydrocarbon
__ Gases
Recycle H2
Slurry
Feed stream
Reactor
Gas purification
system
Gases
NH3,H2S,H20
Product
stream
Gas
disengager
Carbonaceous
residues
Pyrolyzer
Solids
Liquids and
unreacted
solids
Solids
separator
NON-POLLUTING
FUEL OIL
Liquids
NON-POLLUTING
FUEL OIL
1
Figure 1. Synthoil process
326
-------
Gasifier
Venturi
scrubber
To shift
'converter
Oil wash
Water wash
Waste water
Figure 2. Raw product gas scrubbing
-------
steam-reformed to generate makeup H2. The
technologies for conversion of H2S to S and for
stream-reforming of hydrocarbon gases are
commercial, but the rest of the system needs to be
developed.
Another source of gaseous effluents will be the
impurities in the gasification products of
carbonaceous residues and coal. The Bureau is
currently conducting an intensive investigation of
these impurities and methods of scrubbing them (ref.
4). Figure 2 is a diagram of the scrubbing system
being installed on the SYNTHANE pilot plant The
scrubber consists of two sections: a water scrubber to
remove the N- and S-contammg compounds, and an
oil scrubber to remove the hydrocarbon gases and
vapors. The system will operate at 1,000 psi. The
recovered gases from this source may be combined
with those recovered from the recycle gas for
processing.
The liquefaction plant will also have gaseous
effluents from the mixer, the solids separator (the
flash gases), and the pyrolyzer. These will consist
mainly of hydrocarbon gases and vapors, H2. NH3,
and H2S. They will be added to the gasification
products of carbonaceous residues and coal to scrub
the impurities and utilize the H2 as makeup gas.
Liquid Effluents
The liquefaction plant will have scrub-water and
scrub-oil effluents from the recycle gas purification
system and from the makeup H2 generation section.
Development of suitable methods for purifying these
waste liquids for reuse is essential for both
environmental and economic reasons. Analytical data
for the waste water from the gasification of different
coals have recently been published by the Bureau and
work on treatment of the water is in progress (ref. 4).
Similar studies of the waste water from recycle gas
scrubbing and of the waste scrub oils are necessary to
develop purification systems.
As shown m figure 2, there will also be some by
product tar from the gasifier for makeup H2.
Depending upon the type of gasifier and the rank of
the coal gasified, the yield of tar is 60 to 80 Ib/ton of
coal. Also, depending on the coal, the S content of
the tar is 1.1 to 2.8 percent (ref. 4). We have found
that the tar can be hydrodesulfunzed to an
environmentally acceptable fuel by the SYNTHOIL
process. The properties of a sample of tar from the
SYNTHANE gasifier and of the hydrodesulfunzed oil
from it are given in table 1. The product contained
0.56 percent S, compared with 1.8 percent S in the
tar. The yield of oil was 90 percent by weight of the
tar, and H2 consumption was 1,088 scf/bbl of oil.
The hydrodesulfurization was conducted at the
relatively mild conditions of 2,000 psi and 425°C. An
oil containing 0.1 to 0.2 percent S can be obtained by
hydrodesulfunzmg the tar at 4,000 psi and 450°C,
but the H2 consumption will be appreciably higher.
Table 1. Hydrodesulfurlzatlon of
SYNTHANE gasifier tar
Temperature: 425° C
Pressure: 2,000 psi
Catalyst: Co-Ho/SlO.-Al.O.
(1/8-lnch x 1/8-lnch
pellets)
Tar
S, vt pet 1.8
Viscosity, SSF at 77* F 251
Specific gravity,
60° /60" F 1.119
Calorific value, Btu/lb 14,920
Hydrodesulfurlzed
oil
0.56
15
1.040
16,375
Yield: 90 pet by vt
Consumption of HZ: 1,088 scf/bbl of oil
Solid Wastes
There will be two types of solid wastes from a coal
liquefaction plant: ash and sulfur. Until large new
markets for sulfur develop, we are inclined to classify
it as a waste. Both ash and sulfur may be disposed of
in worked-out coal mines. Alternatively, the ash may
be used as a landfill. The question of water-solubles in
ash is therefore important and should be studied.
Trace Metals in Oil
A knowledge of the trace metals in coal-derived
liquid fuels is important, since the metals will end up
in stack gases during combustion. The information is
also relevant to problems of fireside corrosion.
An analysis of the metals in a sample of
SYNTHOIL is given in table 2. The oil was ashed at
550°C, and the ash was analyzed for silica and metals.
The concentrations are reported as ppm in the oil.
Silica is present in highest concentration, followed by
iron and aluminum.
Dust
Finely divided solids will become airborne during
328
-------
Table 2. Trace metals in SYNTHOIL
S in oil, wt percent
Ash in oil, wt percent
0.22
0.03
Concentration
in oil, ppnr
Silica
Iron
Aluminum
Potassium
Sodium
Calicum
Magnesium
Molybdenum
Cobalt
135.5
67.4
29.1
5.0
2.9
2.3
2.2
<0.2
<0.1
(1) transfer of coal from delivery trains to storage
hoppers, (2) pulverization of coal, and (3) transfer of
ash and S from storage hoppers to disposal trains. The
methods of coal dust control, to the extent that they
are currently practiced, are based on the use of
baghouse filters (widely used in coal-crushing
facilities), suction devices (frequently installed
between conveyor belts and in closed areas), and
water sprays (for suppressing dust from coal piles).
Among these, the baghouse filter is the most efficient
device; although we are not aware of its application
to transfer operations of types (1) and (3) above, we
do not consider such applications major problems of
development.
Carcinogens in Coal Liquefaction Products
Coal liquefaction products have long been
suspected to contain carcinogenic compounds, but no
definitive studies are reported. With the list of
carcinogens published by OSHA as a guide, their
presence in coal liquefaction products should be
investigated and appropriate recommendation for
occupational safety developed.
ACKNOWLEDGMENTS
We are thankful to Mr. A. J. Forney and Mr. A. W.
Deurbrouck of Pittsburgh Energy Research Center for
helpful discussions. To Mr. Forney we are also
thankful for permission to use figure 2. The analysis
of SYNTHOIL for trace metals was conducted by Dr.
Richard C. Diehl of Calgon Corporation. The
complete results of our studies with Dr. Diehl will be
published separately.
REFERENCES
1. Paul M. Yavorsky, Sayeed Aktar, and Sam
Friedman, "Process Developments: Fixed-Bed
Catalysis of Coal to Fuel Oil," Presented at the
65th Annual AlChE meeting, November 26-30,
1972. New York. N.Y.
2. Sayeed Akhtar, Sam Friedman, and Paul M.
Yavorsky, "Low-Sulfur Liquid Fuels From
Coal," Presented at the Symposium on Quality of
Synthetic Fuels, ACS, April 9-14, 1972, Boston,
Mass.
3. Sayeed Akhtar, Sam Friedman, and Paul M.
Yavorsky, "Process for Hydrodesulfurization of
Coal in a Turbulent-Flow, Fixed-Bed Reactor,"
Presented at the 71st National Meeting of the
AlChE, February 20-23, 1972, Dallas, Texas.
4. Albert J. Forney. William P. Haynes, Stanley J.
Gasior, Glenn E. Johnson, and Joseph P. Strakey,
Jr., "Analysis of Tars, Chars, Gases, and Water
Found in Effluents From the SYNTHANE
Process," Bureau of Mines TPR 76. January
1974.
Disposal of liquefaction
plant waste
Material
Method
Sulfur Claus conversion to ele-
mental form. Surface
fill or storage, inert.
Off-gass Reprocess through hydro-
gen generating gasifier.
Solid Land fill or mine fill,
residue like ash.
329
-------
Liquefaction processes differ only in reactor subsystems
1. Synthoil - Direct coal hydrogenation in fixed bed of catalyst.
2. H-coal - Direct coal hydrogenation in ebullated bed of catalyst,
SRC -
3.
Hydrogen transfer solvent extraction of coal with H2
added to solvent in reactor.
4. Consol-SF - Extraction with separate hydrogenation of solvent and
heavy extract.
Common to all are: coal prep., oil handling, residue disposal.
Anticipated environmental concerns-
specific for coal liquefaction plants
Plant effluent
Potential pollutant Needed research
Product oil
Product oil
Product oil
Vapor leaks in
slurry prep.,
residue take-off
Inorganic residue
disposal
Dissolved gases
in scrub water
Organic carcinogens
Metal compounds
Inhalable vapors
As above
Leachable inorganic
compounds
HCN, Se, As, F
A. Analyze for known
carcinogens.
B. Test oils on animals.
A. Analyze for metals.
B. Analyze for organo-
metallics.
Analyze for health
hazards.
As above.
Analyze for soluble
metals, sulfur, halides,
etc.
Analyze liquor.
330
-------
POTENTIAL BYPRODUCTS FORMED FROM MINOR AND
TRACE COMPONENTS IN COAL LIQUEFACTION PROCESSES
Philip S. Lowell and Klaus Schwitzgebel*
Abstract
Simplified concepts are given for coal liquefaction
processes which broadly define processing conditions
and objectives. The fate of trace elements in coal
liquefaction will be determined by the interaction of
coal constituents and process conditions.
Minor components such as sulfur, nitrogen, and the
trace element selenium were used as examples for
identifying the problems associated with determining
the fate of trace elements in liquefaction processes.
Some research areas for the trace element problem
can be specified at this time. These specific areas will
lead to treatment process problem definitions. The
research needs for actual development of treatment
processes cannot be detailed at this time.
INTRODUCTION
The need for an environmentally acceptable form
of coal has been amply justified. The major
objections to the direct use of coal as a fuel in the
United States today are the paniculate and sulfur
oxide emissions.
There are many processes for converting coal to
liquid or gaseous products. Each process has various
features that may be more or less advantageous in any
given situation.
Yavorsky (ref. 1) listed the following distinguishing
advantages for liquefaction processes:
(1) The carbon/hydrogen ratio must only be
increased slightly (0.9 to perhaps 1.1);
(2) Liquid products are easily storable;
(3) Liquid products can serve as chemical feed
stocks as well as fuels.
The developers of liquefaction processes are
dedicated to optimizing the principle process goal;
the production of the liquid products. For these
products to be saleable, the sulfur and nitrogen
contents must be below certain levels. Therefore,
considerable effort has been directed toward sulfur
and nitrogen removal.
The fate of the various trace elements in coal is not
in the "mainstream" of process development. This is
probably rightfully so in the initial stages. But the
time has come when coal processing plants must solve
•Philip S. Lowell and Klaus Schwitzgebel are with the
Radian Corporation, 8500 Shoal Creek Blvd.. Austin, Texas.
these problems in order to be environmentally
acceptable themselves. The chemical form and the
streams in which minor and trace elements appear
will be determined by the interaction of their
chemical combination in the coal with the processing
conditions. The problem faced now is to have
treatment processes available when they are needed.
To define the research and development needs for
the environmental aspects of trace elements in coal
liquefaction processes, we should perhaps look at a
liquefaction plant as we envision the way it will be
built and work backwards to where we are today.
When a vast coal processing complex (ref. 2) is finally
built, we would like to be able to know in which
outgoing streams and in what form all of the
incoming trace elements will leave the process. Some
elements may leave in a harmless form with the solid
waste ash (e.g., phosphorus as phosphates). Others
may leave with the product, in concentrations low
enough to be harmless and/or in nontoxic chemical
forms. Others may be converted to highly toxic or
odorous forms and require removal processes. With
this information, the design engineer would like to
get out his design manual, with its tabulations of
physical and chemical data, and design the required
pollutant removal processes.
Development of trace element treatment processes
cannot logically be started or the scope defined until
the stream conditions and chemical form are
established. The development of sampling techniques
and analytical chemistry methods is a necessary step.
The sampling and analysis methods must be used on
pilot plants to determine these data.
We are in a "chicken and the egg" situation. We
must know in what streams, in what concentration,
and in what chemical form the trace elements will
appear so that we can develop sampling techniques
and analytical methods to measure them
quantitatively. The starting point then is a prediction
of the course of phase separations and chemical
reactions for the trace elements. Several iterations
will be required before success is finally reached.
Another aid in defining research needs is to
consider the few elements in coal for which a level of
understanding does exist and then to extrapolate this
data to the other unknown elements. For instance,
the amount of information on sulfur in coal is
considerable (although the difficulty of the problem
331
-------
is also great). The types of sulfur bonds have been
classified (refs. 3,4,5) and pure compound catalytic
and noncatalytic desulfurization tests (ref. 6) have
been made.
On the other hand, the knowledge of nitrogen
structures in coal is very sparse (ref. 3). This is
surprising in view of the amount of nitrogen present.
Model compound reactions are only in rudimentary
stages.
The level of knowledge of most trace elements in
coal is very low. The research needs for liquefaction
processes in this paper will be identified in the
following manner:
(1) We will trace what is known about sulfur and
nitrogen with respect to pollution control.
(2) We arbitrarily choose selenium as an example
of a trace element and try to determine its
fate. The problems identified in this attempt
will aid in defining the research needs.
(3) We will attempt to generalize from the above
specific examples.
SIMPLIFIED PROCESS OBJECTIVES
The primary objectives of coal liquefaction plants
•are to produce a product that is (or has):
(1) a liquid (plus some gases);
(2) a low ash content product;
(3) a low sulfur content;
(4) other (e.g., end use as fuel, chemical feed
stock, etc.).
Coal may be classified arbitrarily as consisting of
organic and inorganic fractions. Modern coal
liquefaction processes slurry the pulverized coal in a
hydrogen donor solvent (usually recycle solvent
derived from the process itself) and treat the slurry
with hydrogen gas, possibly in the presence of a
catalyst. Solids consisting of inorganic material from
the coal and the undissolved heaviest organic portion
of the coal are removed by physical means such as
filtration or centrifugation. The liquid portion from
this physical separation is the product and may be
used as fuel or processed as a synthetic crude oil. The
solid from this physical separation contains
significant heating value and in many process designs
will be burned to provide process heat (ref. 7) or
subjected to a gasification process to provide process
hydrogen (ref. 2). These solids can be expected to
contain not only the trace elements from the
inorganic portion of the coal but a large fraction of
many of the minor components and trace elements in
the organic part of the coal. The sulfur content of
this solid is very high (typically 6 percent), so sulfur
recovery processes are envisioned. Determination and
control of the fate of trace elements in the units of
the coal refinery complex processing this material will
provide one of the major challenges for the trace
element program.
To illustrate the liquefaction process, consider the
"demonstration" coal molecule of figure I. In order
to convert this large, solid molecule to a liquid, the
"bridges" must be broken. The aromatic clusters will
be liquids or low-melting solids.
Sulfur and nitrogen are each represented with two
different bond types. As will be shown later, the
ability of the process to remove these minor
components depends on the relative amounts of bond
type.
SIMPLIFIED PROCESS CONDITIONS
The liquefaction processes operate through the
mechanism of breaking the connecting bridges or
linkages between aromatic clusters. These bridges can
be aliphatic or they may contain oxygen, sulfur, or
other elements. Attacking these groups in bridges is
desirable.
Hydrogenation of olefinic and aromatic carbon, or
nonlinking oxygen is undesirable since it consumes
hydrogen but does not contribute to liquefaction.
Breaking of carbon bonds that result in coking is also
undesirable.
Thermodynamically, all of the above reactions are
feasible at 300°C. Kinetically they do not proceed
rapidly enough to be feasible (ref. 20). Aromatic
structures become thermodynamically stable at
higher temperature with respect to hydrogenation to
form saturated compounds. The free energy change
for benzene hydrogenation to cyclohexane is -5.2
Kcal at 227°C and +13.6 Kcal at 427°C. Processing
conditions are normally set as hot as possible without
excessive rupturing of carbon-carbon bonds to
produce coke. This has been found experimentally to
be in the range of 450° to 460°C.
Catalysts can play a key role in several areas. One is
in breaking the desired bridges without excessive
hydrogenation of aromatics and unsaturated
compounds. Another is release of undesirable
elements in the ring structures, e.g., sulfur. Obviously
the type of catalyst used will influence the physical
and chemical properties of the product as well as the
hydrogen consumption required to attain
liquefaction. Present catalysts are kinetically active at
about 370°C and above. Hence, the normal
temperature range of liquefaction processes are 400°
to 450°C.
332
-------
Figure 1. Coal molecule
Table 1. Typical processing conditions
Process
Solvent Refined Coal (SRC)
Plttaburg and Midway
H-Coal
Hydrocarbon Research, Inc.
Syneholl
Bureau of Mine*
Temperature
°C
440
(825)
455
(850)
450
(840)
Hydrogen
Preeaure
Atiaoaphare*
(PSD
70
(1000)
170
(2500)
270
(4000)
Catalvae
None
Cobalt Molybdate
Cobalt Molybdate
on activated
S1O--A1-O.
333
-------
High hydrogen partial pressure is of value in
increasing kinetics as well as in giving a better
thermodynamic potential. As will be seen later, this is
necessary in some cases.
Process conditions for three important liquefaction
processes are summarized in table 1.
PREDICTIONS OF REACTIONS
Experimental data and thermodynamic calculations
are presented for sulfur, nitrogen, and selenium as
examples of what may be expected.
Sulfur
Sulfur exists in several forms in coal. Two bond
types, a model compound having this type bond, and
the Gibbs free energy for the model compound
reacting to give H2S are tabulated in table 2. The free
energies were estimated by the van Krevelen and
Chermin method (refs. 8,9). The reaction mechanism
proceeds through sulfur removal first. Saturation of
resulting olefins follows this step (ref. 10).
Experimental data indicate that almost all of the
sulfide sulfur will be converted to H2S at 400°C in a
hydrogen atmosphere. At 400°C and 100 atm
hydrogen pressure, very little thiophene sulfur is
removed unless a catalyst is used. Workers at the
Bureau of Mines have reported excellent sulfur
removal from a distillate fuel oil product using a fixed
bed of cobalt molybdate catalyst (refs. 1,11,12).
Johnson et al. (ref. 13) report overall desulfunzation
of 90 percent using an ebullated bed of cobalt
molybdate catalyst in the H-coal process.
In laboratory studies of model compounds, the
sulfur in thiophene and benzothiophene can be easily
removed to 95+ percent with a catalyst (ref. 6). The
addition of a methyl group next to the sulfur on the
thiophene ring reduces sulfur removal to a percentage
in the mideighties under the same conditions.
Apparently the decrease in catalyst efficiency is a
steric hindrance problem because the free energy
changes for the two compounds are almost the same
(see table 2). Dibenzothiophene is much less reactive
than the less highly substituted thiophenes (refs.
14,15).
Sulfur appears to follow somewhat predictable
rules. The sulfides have the greatest free energy and
are most subject to attack. The free energy change of
the thiophenes are all of the same order of
magnitude. The aromatic sulfur structures are fairly
stable except under catalytic attack. Steric factors
influence the rate and type of desulfurization.
Nitrogen
Considerably less seems to be known about
nitrogen in coals. Nitrogen is more difficult to remove
by hydrogenation than sulfur. Possible structure
reactions to give ammonia, and free energy changes
for the reactions are given in table 3.
It is of interest to note that the "ease of removal"
is in the same order as the free energy changes at
400°C.
AG
400°C
Real
sulfide (S)
amine (N)
ring (S)
ring (N)
-30.3
-20.7
% 0.0
+ 7.9
Thermodynamics will be of help in several ways.
First, it can be used to define temperature and
pressure areas of interest. Second, it can be used to
predict compounds for which one should look. Third,
it gives an indication of where catalyst development
research would be of value.
Selenium
Selenium is one of the trace components of interest
because of its toxicity and malodorous compounds.
Chemically, selenium is very similar to sulfur.
Selenium compounds analogous to sulfur are known
to exist.
H2S
CS2
COS
SO 2
so"
Se
H2Se
CSe2
COSe
Se02
334
-------
TABLE 2. SULFUR FORMS AND REACTIONS
en
TYPE OF BOND
SULFIDE
CONJUGATED
RINGS
(THIOPHENES)
MODEL COMPOUND REACTIONS
H
&
C
H
H
^
^^
AGR,KCal
25°C 400°C
-25,8 -30.3
-1.7 +3.8
-7.3 -1.2
-7.5 -2.0
-------
Table 3. Nitrogen forms and reactions
TYPE OF BONO
AMINE
MODEL COMPOUND REACTION
NH2
H.
+NH,
AGR,KCg|
25°C 400°C
-iai -20.7
CONJUGATED
3H2
H H
H
-8.4 *7.9
1.0
1500
Se LIQUID
OR SOLID
-0.0
B
C/J
1000
500
100
Figure 2. Hydrogen selenide decomposition
336
-------
The chemical form of selenium in coal is basically
unknown. Attari (ref. 16) has reported that selenium
leaves the solid phase as gasification proceeds during
the HyGas process.
The strengths of the C-Se (ref. 17) and H-Se bonds
are less than the corresponding sulfur bonds. DeBerry
{ref. 18} has estimated that the free energy of
reaction of selenium-carbon compounds to give H2Se
will be less negative by about 5 Kcal than the
corresponding sulfur compounds to give H2S. This
indicates that the difficulty of selenium removal as
H2Se should be estimated to be between N and S
compounds. This assumes that selenium will exist in
the same form as sulfur.
Hydrogen selenide is known to be unstable at room
temperature. It decomposes to hydrogen and metallic
selenium. The vapor pressure of selenium metal is
about 3 mm Hg at 400°C. The equilibrium between
reactions is reported by Flogel (ref. 19). Ftogel's
results at 1 atm are summarized in figure 2.
At the high temperatures characteristics of gasifiers.
only gaseous H2 and Se2 would exist. We have not
investigated compounds such as CSe2, etc. At coal
liquefaction process temperatures, H2Se will be the
predominant species. Cooling the mixture further
results in decomposition to H2 and liquid or solid
selenium.
One would expect some of the selenium to be in
the inorganic fraction as selenides, selenites, or
selenates. The organically bound selenium will
probably leave the process in the liquid product as
well as H2Se in the gas phase.
The gas phase sampling and analysis will be a
difficult operation at best. The H2Se can decompose
to metallic selenium (which can have a significant
vapor pressure). Should it not decompose, it must be
remembered that hydrogen selenide is water soluble
(about 2,000 times stronger acid than H2S) and is a
moderate reducing agent (ref. 17). The actual
chemical analysis technique may well be simple
compared to getting a truly meaningful sample in
proper condition in a proper container to place
before an instrument.
RESEARCH AND DEVELOPMENT NEEDS
Research programs in energy must be designed to
fulfill two important requirements. The information
developed must be useful to those who are providing
overall management and leadership to the
development of energy sources; and the information
must be placed in the hands of those who must
ultimately implement or commercialize new energy
technology.
Both goals can be achieved by a contract research
and development program administered by the
Federal Government. Leadership and management
can be supplied by the appropriate Federal agency,
and the participation of industry in the development
of new technology will insure the implementation of
that technology in the private sector.
In addition to defining research areas it is almost as
important to define the type of organization most
suited to do the work. This will be indicated also.
Organic/Inorganic Portions
For every trace element the relative amounts that
are contained in the organic and inorganic fractions
should be determined. Those trace elements that are
removable to an acceptable level by pretreatment
processes will require only minor additional research.
For process or site conditions opting for no
pretreatment, further work will be required. This
should be done by an industrial organization.
Development and Testing of Sampling and Analytical
Methods
An iterative procedure of estimating the form and
concentration of trace elements, developing sampling
and analysis procedures, testing these procedures,
attempting to account for the material balance,
revising the estimates, etc., must be done for each
process and each trace element. While the material
balance should be quantitative, the compound
identification will only be tentative.
The bulk of this work should be industrial, but
universities have a contribution to make in basic
reactions and phenomena upon which analytical
methods can be based.
Structure Identification
After the broad outlines of the material balance
have been fixed, the actual compounds involved must
be identified. Trace element form in the product
streams must be identified so that treatment
processes may be developed as soon as possible. The
trace element structures in coal are of value too.
Bothe industry and universities should participate
in the general structure analysis, e.g., cyclic
structures, reactive groups, etc. Universities should
have prime responsibility for model compound
synthesis and reactions. Industry should be concerned
with the treatment process aspects.
337
-------
Development of Catalysts
Historically, catalysts prepared from various
combinations of Group VIM and Group VI-B oxides
and sulfides have been used as desutfunzation
catalysts in the petroleum industry. Their
effectiveness in cleaning liquid fuels from coal
liquefaction processes must be investigated and new
catalyst development initiated for selective
desulfurization of heavy, coal-derived liquids. This
may well require the development of radically new
catalytic systems.
Catalysts for nitrogen and trace element removal
should also be investigated. For the most part, this
will be virgin territory.
This task should be done by both industry and
universities. It is an excellent example of an area in
which joint industry/university efforts could be
particularly advantageous.
Physical and Chemical Properties
Thermodynamic properties and physical data must
be gathered and generated for the basis of accurate
process designs. The bulk of this research should be
done by universities, although industry may have to
generate significant portions because of time
constraints.
Treatment Process Development
This important task can be identified but, due to
lack of knowledge, cannot be defined at this point
because too little is known. Because of time
considerations, the initial effort will be by industry.
Universities will contribute to second generation
processes through the work done in "Structure
Identification" and "Physical and Chemical
Properties."
ACKNOWLEDGMENTS
The authors express their appreciation for the help
of Dr. D. W. DeBerry and Ms. C. M. Thompson. These
people contributed to the formulation of ideas as well
as the gathering of information.
REFERENCES
1. P. M. Yavorsky et al., "Converting Coal Into
Non-Polluting Fuel Oil," CEP, Vol. 69, No. 3
(1973). P. 5MYA-034).
2. M. E. Frank, and B. K. Schmid, -'Design of A
Coal-Oil-Gas Refinery," CEP, Vol. 69. No. 3
(1973), p. 62, (FR-080).
3. G. L. Tingey et al.. Coal Structure and
Reactivity, Battelle Pacific Northwest Labs.,
Richland, Wash., 1974, (TI-022).
4. Karl D. Gundermann et al., "Organic Sulfur
Bonding in Coal," Erdoel Kohle. Erdgas,
Petrochem. Brennst. Chem. Vol. 25, No 2
(1972), pp. 58-61, (GU-040).
5. A. D. Barar.skii et al., "Organic Sulfur of Coals,"
Khim. Tverd. Topi. 1973, No. 1, pp. 50-56.
(BA-193).
6. Edwin N. Givens et al., "Hydrogenolysis of
Benzo [b] Thiophenes and Related
Intermediates Over Cobalt Molybdena Catalyst,"
ACS Div. Fuel Chem. Preprints, Pt. 2, Vol. 14,
No. 4 (1971), p. 135. (GI-038).
7. B. K. Schmid et al., "Production of Ashless,
Low-Sulfur Boiler Fuels from Coal," Amer.
Chem. Soc. Div., Fuel Chem., Preprint Vol. 15,
No. 2 (1971), pp. 38-49, (SC-142).
a D. W. Van Krevelen and H. A. G. Chermin,
"Estimation of the Free Enthalpy (Gibbs Free
Energy) of Formation of Organic Compounds
from Group Contributions," Chem. Eng. Sci., 1,
66 Vol. 1 (195D, PP. 66. (VA-080).
9. D. W. Van Krevelen and H. A. G. Chermin,
"Erratum Estimation of the Free Enthalpy
(Gibbs Free Energy) of Formation of Organic
Compounds from Group Contributions," Chem.
Eng. Sci., Vol. 1, No. 5 (1952). p. 238,
(VA-081).
10. Jerry March Advanced Organic Chemistry,
McGraw-Hill, N.Y., 1968. p. 557ff, (MA-276).
11. Sayeed Akhtar, Sam Friedman, and Paul M.
Yavorsky, Low-Sulfur Fuel 'Oil from Coal,
Bureau of Mines Coal Desulfurization Program
Technical Progress Report 35, 1971, NTIS
PB-203889, (AK-004).
12. G. Alex Mills, "Future Catalytic Requirements
for Synthetic Energy Fuels," ACS, Div. Fuel
Chem. Preprints Vol. 16, No. 2 (1972), p. 107.
(MI-113).
13. C. A. Johnson et al., "Coal Gasification Scale-Up
Factors in the H-Coal Process," CEP, Vol. 69.
No. 3 (1973), pp. 52-54, (JO-098).
14. Robert H. Ebel, "Recent Advances in Fuel
Desulfurization Technology," ACS, Div. Petrol.
Chem. Prepr., Aug. 1972, C-46-C-55, (EB-004).
15. W. F. Arey, Jr., et al., "Advances in
Desulfurization of Residual Fractions and
Asphalts," Proc. 7th. World Petroleum Congress
1970. (CAR-031).
338
-------
16. A. Attari, Fate of Trace Constituents of Coal Corp., 19 April 1974, (DE-104).
During Gasification, Inst. of Gas Technology. 19. Peter von Flcgel, "Zum Gleichgewicht zwischen
Chicago, III.. 1973. NTIS PB-223 001, (AT-042). Selen und Wasserstoff bei 400°C." Z Anorg.
17. Arne Fredga "Organic Selenium Chemistry. Pt. 1. Allg. Chem., Vol. 388, (1972). pp. 218-28,
Synthesis and Properties of Organic Selenium and (FL-037).
Tellurium Compounds," Annals N.Y. Acad. Sci., 20. Wendell H. Wiser "Kinetic Comparison of Coal
Vol. 192, (1972), pp. 1-9. (FR-087). Pyrolysis and Coal Dissolution," Fuel (London).
18. D W. DeBerry, Private Communication, Radian Vol. 47, No. 6 (1968). pp. 475-86, (WI-088).
339
-------
340
-------
OIL SHALE AND ITS POTENTIAL UTILIZATION
G. U. Dinneen*
Abstract
The large deposits of off shale in the Green River
Formation in Colorado, Utah, and Wyoming offer a
potential source of significant quantities of liquid
fuels. This paper discusses the location and potential
of the resource; the present state of technology for
producing shale oil by both aboveground and in situ
processes; the characteristics of shale oil;
environmental aspects of oil-shale utilization, and
recent developments, particularly results of the
Department of the Interior's Prototype Oil Shale
Leasing Program, that suggest inauguration of
commercial oil-shale processing.
INTRODUCTION
Oil shales of the Green River Formation in
Colorado, Utah, and Wyoming comprise one of the
largest deposits of hydrocarbons in the world and are
a potential source of significant quantities of liquid
fuels. They are sedimentary rocks containing solid
organic material that can be decomposed by heat to
yield an oil which can be refined to yield the
products normally obtained from petroleum.
Various attempts have been made since before
World War I to develop commercial processes for
utilizing Green River oil shale. Most of these have
involved mining the shale and processing it in
aboveground equipment; but recently, in situ
processing has received considerable attention. The
first approach is reasonably well developed and will
probably be used where the shale can be readily
mined. The second approach requires more research,
but it may have an economic advantage; it may be
applicable to deposits of various grades and
thicknesses that do not readily lend themselves to
mining, and it avoids the problem of disposing of
large amounts of spent shale. Both approaches have
potential environmental effects that must be taken
into consideration.
Although there is no present oil-shale industry in
the United States, the current status of oil-shale
technology and the country's need for new energy
sources suggest that the start of such an industry may
*G. U. Dinneen is with the Lara/me Energy Research
Center, Bureau of Mines, U.S. Department of the Interior,
Laramie, Wyoming.
be imminent. This paper describes the availability and
potential of oil shale, the current technology for
producing and utilizing shale oil, the potential
environmental effects of oil-shale utilization, and
recent developments suggesting commercial
development.
LOCATION AND POTENTIAL OF OIL SHALE
Oil shales are widely distributed throughout the
United States, but the largest and richest deposit is in
the Green River Formation. Hence, most efforts to
utilize oil shale have been on material from this
formation, and it will thus be the one considered in
this paper. The formation, whose location is shown in
figure 1. covers an area of about 17,000 square miles
in four principal basins: The Piceance Creek Basin of
Colorado, the Uinta Basin of Utah, and the Washakie
and Green River Basins of Wyoming In this
formation, oil-shale intervals that are at least 10 feet
thick and that yield at least 25 gallons of oil per ton
have a potential oil yield in place of 600 billion
barrels as shown in table 1 (ref. 1). If thinner shale as
lean as 10 gallons per ton were used, the potential oil
yield would increase to some 2 trillion barrels.
Although the Piceance Creek Basin, as shown in
figure 1, contains only a small part (about 10
percent) of the area covered by the Green River
Formation, it contains about 80 percent of the richer
oil shale (table 1). The oil shale crops out in cliffs
(fig. 2) along the southern edge of this basin. The
Mahogany zone, which is the best known interval of
the Green River Formation, is about 75 feet thick in
the lower part of the cliff just above the talus slope.
The rich oil shale thickens toward the center of the
Piceance Creek Basin so that in some places
continuous sections of oil shale averaging more than
25 gallons of oil per ton are hundreds of feet thick
(ref. 2). However, these are generally under several
hundred feet of overburden and therefore may not be
as readily mined as the outcrops which have received
most attention in the past. In Utah and Wyoming, the
sections of rich shale are not as thick as those in
Colorado, and in Wyoming they are often
interspersed with alternating beds of lean shale.
Hence, somewhat different recovery techniques may
be required for these shales than for those in the
Piceance Creek Basin.
A major problem in utilization of oil shale is the
341
-------
necessity of handling large amounts of rock than
contain only moderate amounts of organic material,
as indicated in table 2. Fortunately, the organic
matter is fairly high in hydrogen so that about
A major problem in utilization of oil shale is the
necessity of handling large amounts of rock than
contain only moderate amounts of organic material,
as indicated in table 2. Fortunately, the organic
matter is fairly high in hydrogen so that about
two-thirds of it can be converted to oil by heating.
Unfortunately, it has a rather high content of
nitrogen which appears in the oil and must be
removed by special techniques before the oil can be
considered a desirable refinery feedstock.
TECHNOLOGY
Shale oil may be recovered from the Green River
Formation by two general approaches. The first
includes mining, crushing, and aboveground retorting;
this approach has been used in various parts of the
world for over 100 years for the commercial
production of shale oil and has been studied in this
country for many years. It will probably be used for
PICEANCE
CREEK
BASIN
1001020 30
SCALE, MILES
Figure 1. Three-State map.
342
-------
Table 1. Potential shale oil in known deposits of the Green River Formation
Billions of barrels of oil in place
Colorado Utah Wyoming Total
Intervals 10 or more feet thick averaging
25 or more gallons of oil per ton
Intervals 10 or more feet thick averaging
10 to 25 gallons of oil per ton
Intervals 10 or more feet thick averaging
10 or more gallons of oil per ton
480 90
800 230
30
600
1,280 320
400 1,430
430 2,030
Table 2. Composition of mahogany
zone shale of Colorado and Utah
Weight
percent
Mineral matter:
Content of raw shale
Estimated mineral
constituents:
Carbonates, princi-
pally dolomite
Feldspars
Illite
Quartz
Analcite and others
Pyrite
Total
Organic matter:
Content of raw shale
Ultimate composition:
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
Total
86.2
50
19
15
10
5
1
100
13.8
80.5
10.3
2.4
1.0
5.8
100
initial development of the Green River Formation.
The second is in situ processing, which has received
serious consideration only in the last few years, but
which has potential economic and other advantages
that make efforts to develop a feasible method
worthwhile. It might be used where the shale is
deeply buried, where it occurs in relatively thin
intervals, where it consists of alternating intervals of
rich and lean shale, or where various other
circumstances exist so that mining cannot be readily
applied. In addition, the technique has the advantage
of leaving the mineral residues in place, thus
eliminating the disposal problem associated with the
aboveground approach. However, it may introduce
environmental effects of its own, such as adding
soluble materials to groundwaters.
Mining and Aboveground Processing
Many attempts have been made to mine and retort
Green River oil shale. A simplified schematic
representation of this approach is shown in figure 3.
So far, all attempts have been made on a pilot-plant
scale, and no prototype commercial unit has been
operated. Five of the more extensive investigations
that have been conducted or are being conducted are
those by (1) the Bureau of Mines, (2) a group of six
oil companies utilizing Bureau of Mines facilities, (3)
the Paraho Development Corporation. (4) Union Oil
Company of California, and (5) the Colony
Development Operation.
Investigations of mining and retorting oil shale and
of refining shale oil were conducted by the Bureau of
Mines near Rifle, Colorado, from 1944 to 1956. A
demonstration mine was opened in a 73-foot
mineable section of the Mahogany zone, and it was
shown with fair assurance that low mining costs and
343
-------
I
Figure 2. View of cliff.
-------
Oil-shale mine
Crushing plant
Shale storage
Screening plant
Crude shale oil
Spent shale
Mineral extraction
and/or disposal
Figure 3. Schematic of oil shale surface processing.
high recovery in a room-and-pillar operation were
possible (ref, 3). Refining research provided assurance
that petroleum refining technology would be
adaptable to shale oil.
During the Bureau's program, retorting research led
to development of the gas combustion retort (ref. 4),
which was considered the most promising of the
retorting methods investigated. This retort, which is
shown schematically in figure 4, is a vertical,
refractory-lined vessel through which crushed shale
moves downward by gravity. Recycled gases enter the
bottom of the retort and are heated by the hot
retorted shale as they pass upward through the vessel.
Air is injected into the retort at a point
approximately one-third of the way up from the
bottom and is mixed with the rising hot recycled
gases. Combustion of the gases and some residual
carbonaceous material from the spent shale heats the
raw shale immediately above the combustion zone to
retorting temperature. Oil vapors and gases are cooled
by the incoming shale and leave the top of the retort
as a mist. The manner in which retorting.
combustion, heat exchange, and product recovery are
carried out gives high retorting and thermal
efficiencies. The process does not require cooling
water, an important feature since the shale deposits
occur in semiarid regions. The development program
utilized pilot plants having capacities of 6, 25, and
150 tons per day, but was terminated before
operability of the largest of these had been
completely demonstrated. However, the process
appeared to offer the possiblity of large-scale
operation.
The gas combustion retorting system was developed
further during the period 1964 to 1968 when the
Colorado School of Mines Research Foundation
leased the Bureau of Mines Rifle facilities and
operated them under a research contract with six oil
companies: Mobil (which acted as Project Manager),
Humble, Phillips, Sinclair, Pan American, and
Continental. The research was conducted in two
stages, each of which lasted approximately 2 years.
The first stage was devoted primarily to investigating
the gas combustion retorting process itself in the two
345
-------
Product
gat
RttoMId
•Doll
Figure 4. Gas combustion retort.
smaller pilot plants that had been constructed by the
Bureau (ref 5). The second stage included research
on both mining and retorting. The mining involved
development of a room-and-pillar method similar to
that of the Bureau of Mines except that somewhat
smaller pillars were used. During this stage it was
demonstrated that the largest gas combustion pilot
plant could be operated using feed rates of 500
pounds per hour per square foot of cross-sectional
bed area, about double the rate previously achieved
by the Bureau of Mines, while maintaining oil yields
in excess of 85 percent of Fischer assay. Although the
results indicated a significant advance in development
of the process, some operating problems were not
fully resolved (ref. 6).
A modified version of the gas combustion retorting
system, designated as to the Paraho retort and
successfully applied to calcining limestone, is
presently being tested on oil shale in a program
supported by 17 companies (ref. 7). Major
modifications to the process involve the charging and
discharging mechanisms for the retort and the gas
injection and process control systems. The test
program, which started late in 1973, is scheduled to
last 30 months and will cost $7.5 million. Two
retorts, a pilot plant 2% feet in diameter and a
semiworks plant 8% feet in diameter, will be
constructed at the Bureau of Mines Rifle facilities,
which have been leased by the Paraho group for their
test program.
A retorting system developed by Union Oil
Company of California also consists of a vertical,
refractory-lined vessel. However, it operates on a
downward gas flow principle and the shale is moved
upward by a charging mechanism ususally referred to
as a rock pump. Heat is supplied by combustion of
the carbonaceous residue remaining on the retorted
shale and is transferred to the oil shale, as in the gas
combustion retort, by direct gas-to-solids exchange.
The oil is condensed on the cool incoming shale and
flows over it to an outlet in the bottom of the retort.
This process also has the advantage of not requiring
cooling water. The system was tested from 1956 to
1958 on a demonstration scale of about 1,000 tons
per day. It was subsequently announced that
operation of the plant had yielded enough
information so that the process could be
commercialized whenever energy demand and
economic conditions warranted (ref. 8). Several
recent announcements in the press have indicated
that Union may start construction of a commercial
plant relatively soon, but the announcements did not
give details of the processing scheme that will be
used.
The process that appears to be nearest to
commercial utilization is the TOSCO II system, which
is based on a rotary kiln utilizing ceramic pellets
heated in external equipment to accomplish retorting.
Shale feed which is ground to less than % inch in size,
is preheated by flue gases from the pellet-heating
furnace and introduced into the kiln with pellets
heated to 1,200°F. In the kiln, it is brought to a
retorting temperature of 900°F by heat exchange
with the pellets. Passage of the kiln discharge over a
trommel screen permits recovery of the pellets from
the fine shale for reheating and recycling. Oil vapors
are recovered, and the spent shale is routed to
disposal.
The TOSCO II process together with a
room-and-pillar mining method has been under
investigation for several years in a semiworks plant
having a capacity of about 1,000 tons per day. The
Colony Development Operation—originally composed
of the Standard Oil Company of Ohio, the Oil Shale
Corporation, and Cleveland-Cliffs Iron Company, but
subsequently including Atlantic Richfield Oil
Company as Project Manager—conducted this
investigation, which terminated in April 1972. During
the investigation, a considerable research effort was
also expended on environmental aspects of oil-shale
operations, particularly in regard to stabilizing and
vegetating spent-shale deposits. After the pilot plant
346
-------
I Compreiied air
.' njeclion veil
Oil and got 4
producing well J_.
-Burned shote-
Relor ted (L Retorting f L ^om
shale " ' ion*
shale-
Figure 5. Schematic diagram of an in situ oil shale retorting process.
was shut down, results were evaluated and design of a
commercial plant having a capacity of about 50,000
barrels of oil per day was started. The engineering
design for this plant will be completed later this year,
and it has been announced that plant construction
could start probably in October if other phases of the
project, such as obtaining a permit for a pipeline from
the shale plant location to the Four Corners area, can
be completed by that time (ref. 7).
In Situ Retorting
The process of retorting oil shale in place has been
receiving increased attention in recent years because
it may have a number of advantages: it may be more
economical than the traditional approach; it may be
applicable to deposits of various thicknesses, grades,
and amounts of overburden that are not readily
amenable to mining; and it eliminates the necessity of
disposing of large quantities of spent shale. However,
it may introduce other environmental problems such
as the possibility of groundwater leaching the soluble
retorting products left underground. In spite of its
potential advantages and the recent interest in it, only
a relatively small amount of research has been done
on in situ processing; consequently, technology is
generally in the early stages of development.
In situ retorting might be accomplished by passing
gases and liquids either horizontally or vertically
through fractured shale. The horizontal approach is
illustrated schematically in figure 5. One application
of this approach consists of drilling a predetermined
pattern of wells into the oil-shale formation, creating
permeability among the wells if naturally occurring
permeability is low, igniting the shale in one or more
of the wells, pumping compressed air down the
ignition well to support combustion of some of the
oil shale, forcing the hot combustion gases through
the oil shale to convert the solid organic matter in it
to oil, and recovering the oil thus generated from
other wells in the pattern.
An early investigation of this concept was made by
Sinclair Oil and Gas Company, now a part of Atlantic
Richfield Oil Company, which conducted
experiments in 1953 and 1954 at a site near the
southern edge of the Piceance Creek Basin (ref. 9).
The results of these experiments indicated that
communication between wells could be established
through induced or natural fracture systems, that
wells could be ignited successfully although high
pressures were required to maintain injection rates
during the heating period, and that combustion could
be established and maintained in the shale bed.
Additional experiments were made some years later
at a depth of about 1,200 feet in the north central
part of the Piceance Creek Basin. These latter tests
were only partially successful, at least in part because
of an inability to obtain the required surface area for
heat transfer (ref. 10).
347
-------
A modification of the concept shown in figure 5
was studied by Equity Oil Company of Salt Lake City
(ref. 11). The medication consisted of injecting hot
natural gas into the shale bed rather than having an
underground combustion zone. A five-spot pattern of
one injection well and four producing wells was used
in an area of the Piceance Creek Basin having
naturally occurring permeability and porosity due to
the leaching of soluble salts. Based on results of the
experiment and a mathematical model developed
from them, it appeared that the technique was
feasible and potentially an economic method for
recovering shale oil. However, the economics are
strongly influenced by the cost of natural gas and the
amount required for makeup.
The only field experiment presently in progress
utilizing the concept in figure 5 is being conducted by
the Bureau of Mines at a site in southwestern
Wyoming between the towns of Rock Springs and
Green River. In this area, an oil-shale interval about
20 feet thick and yielding from 20 to 25 gallons of oil
per ton is relatively shallow—50 to 400 feet deep.
Over a period of several years, 10 experiments
concerned with various fracturing and recovery
methods have been conducted at the site (refs.
12,13). In the 11th experiment, which is presently in
progress, three hydraulic fractures approximately 10
feet apart have been created. A slurned or liquid
chemical explosive will be detonated m these
fractures to break up the shale preparatory to an
underground combustion experiment for the recovery
of shale oil. Hopefully, this last phase of the
experiment will start next summer or fall.
An in situ experiment where the broken shale is
retorted vertically rather than horizontally is being
conducted by Garrett Research and Development
Company on the southwestern edge of the Piceance
Creek Basin. In this technique, sufficient shale is
mined from the lower part of a room to provide the
desired porosity when the shale above the mined
portion is fractured by explosives and collapsed into
it (ref. 14). The broken shale in the room is then
ignited on the top, and a combustion zone is forced
down through it by supplying air to the top of the
room. The hot gases ahead of the combustion zone
retort the shale, and products are removed from the
bottom of the room. One such room holding several
thousand tons of broken shale was prepared and
retorted during 1973 apparently with very
satisfactory results. However, a commercial-scale
application of this technique will presumably require
rooms several times the size of the one completed last
year and some additional development work.
A nuclear explosive, rather than partial mining,
could be used to prepare a cavity filled with broken
shale for in situ retorting. The concept has been
discussed since the late 1950's, and a number of
detailed plans for a field test have been
developed—the latest in September 1973 (ref. 15)
However, no field test of this technique is presently
scheduled.
To furnish appropriate data for improving in situ
techniques, the Bureau of Mines conducts both
laboratory studies and pilot scale simulation of
underground operations. The laboratory studies
concern the effects of variables such as the reaction
of oxygen with oil shale at subretorting temperatures.
the mechanisms of formation and transport of oil out
of oil-shale particles, and the effects of pressure on
the retorting process. For the simulation studies, two
vessels—one with a capacity of 10 tons and the other
with a capacity of 150 tons—are used to study such
variables as the rate of combustion front travel, gas
flows through broken shale, grade of shale, and
particle size distribution. The larger of the two pilot
plants is shown in figure 6, which also shows in the
left foreground the type of random-sized oil shale
used for some experiments. This material ranges in
size from sandlike particles to pieces weighing a ton
or more. For experimental purposes, the retort is
filled and retorting is started by igniting the shale at
the top with a natural gas burner. After the burner is
turned off, combustion is maintained by injecting air
and recycle-gas, if used, into the top of the retort.
The combustion zone travels down through the bed,
retorting the oil shale ahead of it. A tank mounted on
load cells is used to collect the liquid products so that
a continuous record of retort output can be
maintained. Gaseous products from the retort, which
contain some oil and water, are passed through
packed towers to remove most of the entrained
materials. After passing through a blower, some of
the gas stream may be recycled back into the retort,
while the remainder vents through a stack equipped
with a natural gas burner to oxidize combustible
components. In a number of experiments run in this
manner to evaluate the effects of retorting gas
velocity and composition, yields up to 65 percent of
Fischer assay have been obtained (ref. 16). These are
thought to be promising considering the wide range in
size of material being retorted and the heat losses
inherent in the equipment used.
Oil-Shale Products
The fuels and chemicals normally produced from
petroleum can also be obtained from shale oil.
348
-------
Figure 6. 150-ton retort.
349
-------
Table 3. Properties of crude shale oils
Retort
Gas combustion
10-ton
150-ton
In situ
Specific
gravity,
60/60° F
0.937
.923
.909
.885
Pour
point, Viscosity,
°-F 100° F SUS
80 543
60 112
60 98
40 78
Nitrogen,
wt pet
2.16
1.57
1.59
1.36
Sulfur,
wt pet
0.60
.79
.94
.72
However, an adaptation of petroleum technology
based on the properties peculiar to shale oil is
required. Shale oil produced by some surface retorts,
such as the gas combustion retort, is usually a dark
viscous material with a relatively low sulfur content
but with a high pour point and a high nitrogen
content (table 3). A high pour point requires that the
oil receive some pretreatment before the oil is
amenable to pipeline transportation. The high
nitrogen content complicates the refining of the oil,
so it appears that hydrotreatmg of the oil or some of
its fractions will be required to lower the nitrogen
content to acceptable levels for processing by refining
methods such as catalytic cracking. In situ processing
and some surface retorting systems may yield oils
with low enough pour points to materially ease the
problems of handling.
Environmental Considerations
Environmental effects directly associated with
oil-shale processing are expected to be from retorted
or burned shales, waters that have been produced or
used in processing, and gases. The present interest in
in situ processing is partly because this technique
would obviate the necessity of disposing of large
quantities of retorted or burned shale. However, to
prove in situ processing to be feasible, one must
determine what effect leaching of the in place
retorted shale and produced waters will have on
groundwater. A start toward investigating this
problem has been made by the Bureau of Mines at its
Rock Springs field site where a program of well
drilling and water sampling is in progress.
Although in situ processing offers some potential
advantages, many portions of the Green River deposit
appear to be most amenable to mining and
aboveground processing as means for recovering shale
oil. Hence, industry and government are both
investigating problems associated with disposal of
retorted or burned shale. In particular, the Colony
Development Operation has done a substantial
amount of work on the vegetation of retorted shale
from the TOSCO II process and has shown that this
revegetation can be accomplished. In another study
Colorado State University in a program sponsored by
industry and government, both State and Federal,
established spent shale test plots at two elevations in
the Piceance Creek Basin during 1973. These plots
were designed to establish the requirements for
germination of selected plant species and the survival
rate under natural conditions.
Retorting oil shale produces water both from
heating the shale and from burning the fuel when the
process uses internal combustion. This water will
generally be in the range of 3 to 10 gallons per ton of
shale retorted. Because it has been in contact with
shale oil, it contains substantial amounts of organic
material in addition to inorganic ions from the
minerals in the shale. Some studies of this water and
suggestions for its treatment have been made (ref.
17), but additional studies will be required as more
specific plans for utilization of oil shale are
developed.
Gases from oil-shale processing are not expected to
have a unique composition, so gas-treating methods
being developed by other industries to comply with
environmental requirements should be applicable to
oil shale gases. However, to confirm this, postulation
gases from pilot plant developments, such as those
being conducted by the Bureau of Mines, should be
sampled and analyzed.
In addition to the direct effects of oil-shale
processing on the environment, there will be other
effects from the development of an industry.
350
-------
particularly from the accompanying influx of people
to a semiand, sparsely populated area (ref. 18).
RECENT DEVELOPMENTS POINTING TO
COMMERCIAL UTILIZATION
Because the oil-shale deposits are about 20 percent
privately owned and about 80 percent Government
controlled, there is an opportunity for development
on both types of land. However, since the
government-controlled lands were withdrawn from
leasing by President Hoover in 1930, no procedure
has been developed to provide for their industrial
development. In an effort to overcome this barrier,
the Department of the Interior developed over the
past several years a ptototype leasing program which
resulted in offering two leases in each of the three
States—Colorado, Utah, and Wyoming—where the
Green River Formation occurs. These leases, each of
which is a little over 5,000 acres in size, are being
offered on a monthly basis, starting with the first bid
opening on January 8, 1974. The successful bidder on
the first tract, which is in Colorado, was a
combination of Standard Oil Company (Indiana) and
Gulf Oil Corporation, with a bonus bid of a little over
$210 million. The second tract, also in Colorado,
went to a combination of Atlantic Richfield
Company, Ashland Oil Company, Shell Oil Company,
and the Oil Shale Corporation for a bonus of over
$117 million. The third tract, which is in Utah, went
to a combination of Phillips Petroleum Company and
Sun Oil Company for a bonus bid of over $75
million. The size of these bids seems to indicate a
genuine intention to develop the leases in the
foreseeable future. However, this will of course
deoend on the future energy situation which
presently is difficult to predict.
There have been two recent announcements
indicating some intention to proceed with
development on privately held land. The Colony
Development Operation has applied for a number of
the permits that will be required in order to start
construction of a plant when engineering design is
completed in the fall of this year. Union Oil
Company of California has also announced its
intention to start construction of a plant in the
foreseeable future.
SUMMARY
Green River oil shale in the States of Colorado.
Utah, and Wyoming has the potential of supplying
significant quantities of fuel to help fulfill the
Nation's needs. Past attempts to utilize the oil shale
have generally involved mining, crushing, and
retorting shale aboveground. It appears that this
approach will probably be applied successfully in the
foreseeable future. In addition, attention is presently
being given to developing in situ techniques which
may have advantages, particularly from an
environmental standpoint. One technique has been
operated successfully in a field test and should be
ready shortly for commercial-scale demonstration.
The range of fuels and chemicals presently produced
from petroleum can also be obtained from shale oil, if
techniques appropriate to its particualr composition
are used. Bids recently made on leases of oil-shale
land offered by the Department of the Interior and
announcements made by companies holding private
land both suggest that commercial development of oil
shale is imminent.
REFERENCES
1. Donald C. Duncan and Vernon E. Swanson,
"Organic Rich Shale of the United States and
World Land Areas," U.S. Geological Survey
Circular, No. 523, 1966, 30p.
2. L. G. Trudell, Thomas N. Beard, and John Ward
Smith. "Green River Formation Lithology and
Oil-Shale Correlations in the Piceance Creek
Basin, Colorado," Bureau of Mines Report of
Investigations 7357. 1970, 240 p.
3. J. H. East, Jr. and E. D. Gardner, "Oil Shale
Mining, Rifle, Colorado, 1944-56," Bureau of
Mines Bulletin 677,1964, 163p.
4. Arthur Matzick et al., "Development of the
Bureau of Mines Gas-Combustion Retorting
Process," Bureau of Mines Bulletin 635, 1966,
199p.
5. J. R. Ruark, H. W. Sohns, and H. C. Carpenter,
"Gas Combustion Retorting of Oil Shale Under
Anvil Points Lease Agreement: Stage I," Bureau
of Mines Report of Investigations 7303, 1969,
109p.
6. J. R. Ruark, H. W. Sohns, and H. C. Carpenter,
"Gas Combustion Retorting of Oil Shale Under
Anvil Points Lease Agreement: Stage II,"
Bureau of Mines Report of Investigations 7540,
1971.74p.
7. Jim West. "Drive Finally Building in US. to
Develop Oil Shale," Oil Gas J.. Vol. 72, No 8
(Feb. 25, 1974), pp. 15-19.
8. Harold E. Carver, "Conversion of Oil Shale to
Refined Products," Colorado School of Mines
351
-------
Quarterly, Vol. 59, No. 3 (July 1964). pp.
19-38.
9. B. F. Grant, "Retorting Oil Shale
Underground-Problems and Possibilities,"
Colorado School of Mines Quarterly, Vol. 59.
No. 3 (July 1964), pp. 39-46.
10. A. L. Barnes and R. T. Ellington, "A Look at
Oil Shale Retorting Methods Based on Limited
Heat Transfer Contact Surfaces," Colorado
School of Mines Quarterly, Vol. 63, No. 4 (Oct.
1968), pp. 83-108.
11. P. M. Duggan, F. S. Reynolds, and P. J. Root.
'The Potential for In Situ Retorting of Oil Shale
in the Piceance Creek Basin of Northwestern
Colorado," Colorado School of Mines Quarterly,
Vol. 65, No. 4 (Oct. 1970), pp. 57-72.
12. H. E. Thomas. H. C. Carpenter, and T. E.
Sterner, "Hydraulic Fracturing of Wyoming
Green River Oil Shale: Field Experiments, Phase
I," Bureau of Mines Report of Investigations
7596, 1972, 18p.
13. E. L. Burwell, T. E. Sterner, and H. C.
Carpenter, "In Situ Retorting of Oil
Shale—Results of Two Field Experiments,"
Bureau of Mines Report of Investigations 7783,
1973, 41p.
14. Donald E. Garrett, "In Situ Process for
Recovery of Carbonaceous Materials from
Subterranean Deposits," U.S. Patent 3,661,423,
May 9, 1972.
15. A. E. Lewis, "Nuclear In Situ Recovery of Oil
from Oil Shale," USRL-51453. Sept. 14, 1973,
5lp. (Available from NTIS, Springfield,
Va. 22151.)
16. A. E. Harak. L. Dockter. and H. C. Carpenter,
"Some Results from the Operation of a 150-Ton
Oil-Shale Retort," Bureau of Mines Technical
Progress Report 30, 1971, 14p.
17. A. B. Hubbard, "Method for Reclaiming Waste
Water from Oil-Shale Processing," Preprints,
Division of Fuel Chemistry, ACS, Vol. 15, No. 1
(1971), pp. 21-24.
18. Staff, U.S. Department of the Interior, "Final
Environmental Statement for the Prototype
Oil-Shale Leasing Program," Vol. I-VI. 1973,
3,200p.
352
-------
OIL SHALE DEVELOPMENT-
SOME ENVIRONMENTAL CONSIDERATIONS
C. Blaine Cecil*
Abstract
The primary deposits of oil shale in the United
States are found in western Colorado, eastern Utah,
and Southern Wyoming. The sedimentary material
now referred to as "oil shale" was originally
deposited over 50 million years ago in inland lakes.
As a result of a complex geologic history, these
sediments have been converted into sedimentary
rocks rich in solid hydrocarbons. The hydrocarbon
portion of the rock decomposes to oil upon heating.
Development of oil shale as an energy source will
involve mining, crushing, and retorting. The primary
products of these operations will be lowsulfur oil of
commercial value and processed shale byproduct.
One of the environmental considerations of oil
shale development consists of revegetation of
processed shale; studies have shown that revegetation
is feasible. A second consideration is the impact of
development on water quality and quantity. Research
has shown that the first commercial plant will not
have a significant impact on the Colorado River
system. Further data indicate that there may be as
much as 400,000 acre-feet of water annually available
for a mature oil shale industry in Colorado, if water
rights are converted from agricultural use to industrial
use. The impact of development on air quality is a
third environmental consideration. Preliminary
studies by the Colony Development Operation
indicate that potential contaminant levels should be
acceptable to both State and Federal officials.
As a result of technological developments in oil
shale processing, coupled with environmental
programs, oil from shale represents a new energy
source which is available for immediate
commercialization.
The phrase "oil shale" has been used for many
years to describe fine grained rocks which will yield
oil when heated. "Oil shales" oncur throughout the
world on every continent and in at least 30 States of
the United States. The world's richest reserves occur
in the Eocene Age Green River Formation of
Colorado, eastern Utah, and southern Wyoming as
shown in figure 1.
"Oil shales" of this region are not shale, nor do
they contain oil. Instead, they are more properly
•Environmental geologist. The Oil Shale Corporation, 1600
Broadway, Denver, Colorado 80202.
referred to as kerogen-bearing marlstone. These
marlstones are clayey, fine-grained carbonate rocks
with minor amounts of quartz and feldspars. Kerogen
is the insoluble hydrocarbon protion of "oil shale"
which decomposes upon heating to yield a
paraffin-type "synthetic" crude oil.
Organic rich sediments which are now referred to as
the Green River Formation were deposited in a lake
or lakes approximately 50 million years ago. Through
diageneses, these sediments were lithifield into
marlstones rich in solid hydrocarbons. The organic
fraction was not subjected to geologic conditions
necessary for conversion to petroleum. Instead, the
original organic material was transformed into the
solid hydrocarbon known as kerogen.
The Green River Formation has a total area) extent
of some 17,000 square miles. The U.S. Geological
Survey has estimated that the total oil shale reserve of
the Green River Formation in Colorado, Utah, and
Wyoming is more than 600 billion barrels of oil m
deposits at least 10 feet thick averaging 25 gallons or
more of oil per ton of oil shale. The U.S. Department
of Interior has also estimated that 80 billion barrels
of this reserve are recoverable by modern mining
methods. This later total is approximately twice the
present domestic crude oil reserve in the United
States, exclusive of Alaska, and represents
approximately 75 percent as much oil as the United
States has produced since the Civil War.
The Piceance Creek Basin, which will be the subject
of the remainder of this paper, has an area! extent of
approximately 1,250 square miles in Garfield and Rio
Blanco counties in western Colorado. The Piceance
Creek Basin is the richest single area of recoverable oil
shale in the United States. This basin alone contains
some 480 billion barrels of shale oil in reserves which
are more than 10 feet thick and averaging more than
25 gallons of oil per ton of rock.
The Piceance Basin is part of the high Colorado
Plateau geomorphic province with surface elevations
in excess of 8,700 feet in some areas. The northern
part of the basin is largely drained by Piceance Creek,
which empties into the White River which in turn
drains into the Green River. At the southern edge of
the basin. Roan Creek and Parachute Creek dram the
basin into the Colorado River. The basin is semiarid
and the terrain consists of plateaus dissected by
streams which have cut canyons over 2,000 feet deep
353
-------
o
WYOMING
iCOORA
Figure 1. Extent of the Green River Formation in Colorado, Utah, and Wyoming.
354
-------
Figure 2. The upper reaches of Parachute Creek Valley, on the southern edge of the Piceance Creek Basin.
SOUTH
NORTH
Roan Plateau
Mahogany Ledge
Whita
River
X. ."i'.o.i'O, -' ••^Z^FZ-r&.-yrrn-.
S-j-.'.-1'. • • ','•• .,- -\rn^A,•-?1"- \T-
?>>e <-;rt--' avw»?,-..- ?<••:-•; ;%
Green River Formation
Evacuation Creek member
Wasatch formation
jffiji'ffirj Parachute Creek member
I//////J Garden Gulch member
i—' —_-\ Douglas Creek member
Figure 3. Idealized cross section of Green River Formation, Piceance Creek Basin (after Nielson),
355
-------
in the southern part, as illustrated by the Parachute
Creek Valley shown in figure 2.
The stratigraphy of the Piceance Basin is illustrated
in figure 3. This highly simplified cross section
indicates the stratigraphic position of the
kerogen-rich Parachute Creek member of the Green
River Formation. The Parachute Creek member
contains the oil shale of greatest economic interest.
As the diagram illustrates, the Parachute Creek
outcrops around much of the margin of the basin and
is in the subsurface in the interior of the basin.
Therefore, virtually all of the oil shale zone of the
Piceance Basin will be developed by underground
extraction methods.
The three major components of shale oil
production are mining, crushing, and retorting. A
facility being planned for the Parachute Creek region
by the Colony Development Operation will serve as a
model for oil shale processing for the remainder of
this paper. The Colony Development Operation is a
joint venture consisting of four companies: T.ie Oil
Shale Corporation, Shell Oil Company, Ashland Oil,
Inc., and Atlantic Richfield Company, Operator.
Conventional room-and-pillar mining will generally
be utilized to extract oil shale for retorting facilities,
as currently planned. The shale will be extracted from
the mine, crushed, and transported by conveyor to
the retorting and upgrading complex.
Retorting will be accomplished by using the
TOSCO II process, the development of which began
in 1956. Based on the research conducted by the
Denver Research Institute of Denver. Colorado, for
The Oil Shale Corporation, the first pilot plant was
built near Littleton, Colorado, in 1957. In 1964, a
1,000-ton-per-day semiworks retort was constructed,
and a full-scale pilot mine was started on Colony
property in Middle Fork Canyon of Parachute Creek
approximately 17 miles north of the town of Grand
Valley, Colorado. The semiworks plant and mine
were operated from 1965 through the fall of 1967.
As a result of these operations, the design of a
commercial oil shale complex was undertaken.
Further testing of the semiworks plant was required
to complete this design. The additional testing was
undertaken in 1969 under the direction of Atlantic
Richfield Company as Operator for the joint venture
In addition to design modifications made to the
TOSCO II process, various types of pollution control
equipment were evaluated. A multimilhon dollar
environmental program was also initiated to assess
potential environmental impacts relating to air, land,
water, wildlife, vegetation, and socioeconomic
conditions which could result from construction and
operation of an oil shale complex.
In the TOSCO II process, crushed raw shale is
preheated by dilute phase fluid bed techniques. The
preheated shale is then transported to a pyrolysis
drum where it is mixed with hot ceramic balls.
Conversion of the kerogen to hydrocarbon vapors is
substantially complete when the shale reaches a
temperature of approximately 900°F. Pyrolysis
vapors are then condensed, fractionated, and piped to
the upgrading facility for refining into final
commercial products. A mixture of processed shale
and ceramic balls leaves the pyrolysis drum and is
conveyed to a trommel screen. The cooled ceramic
balls pass over the trommel screen and are returned to
a ball heater. The processed shale is cooled.
moisturized, and transported to the disposal area.
The production of shale oil by retorting will
generate large volumes of waste material consisting
chiefly of spent shale or "processed shale." The
processed shale from TOSCO's retorting process is a
fine, black, powder-like material. The dark color is
attributable to a small amount of residual carbon
which coats the dust particles. It is powder-like
because the processing temperatures are not high
enough to produce the clinker-type chunks
characteristic of other pyrolysis process waste
materials. Because of the physical characteristics and
low fertility of processed shale, special treatment of
the surface embankment will be required prior to
re vegetation.
The environmental studies in processed shale
disposal have included analyses of the permeability of
the processed shale embankment, leaching
characteristics of processed shale, the structural
integrity of processed shale compacted to various
densities, the erosion potential of processed shale,
and the liquefaction potential of the embankment.
The design of the embankment has been influenced
substantially by the findings and recommendations
set forth in these studies (ref. 1).
As an alternative to surface disposal, several studies
have analyzed the potential use of processed shale for
a variety of commercial purposes, including the
manufacture of building blocks, concrete, road
substrate, bricks, and paneling material. At the
present time, none of these alternatives are
economically feasible.
Revegetation of plants on the processed shale
embankment is important to surface stability,
reduced erosion potential, proper water balance,
preservation of esthetic values, and restoration of the
area to a balanced environment. For these reasons, a
considerable number of revegetation studies have
356
-------
been conducted at the semiworks site since 1965.
These programs include seven separate plot studies on
processed shale which continue to provide useful
information on such effects as varying slope, soil
cover, mulch, and irrigation; the migration of salt
through root zones; and the suitability of various
local and foreign plant species for use in the ultimate
vegetation process. It has been learned that regular
watering during the first year is important to a rapid
establishment of vegetation. Results indicate that
only infrequent supplements to natural rainfall are
required during the second growing season. After two
seasons, the vegetation may require no further
watering (ref. 1).
Successful growth of native woody plants, such as
juniper, skunkbush, and four-winged saltbush in more
recently established plots, indicates that these species
may maintain continued growth and vigor as well as
some grasses and shrubs have done in the past. The
satisfactory growth of native and exotic species
should not be surprising in view of the fact that
processed shale is somewhat similar to the native soils
derived from weathered shale. The natural soils have
had many years to weather and leach; consequently,
they support a wide variety of plants and vegetation
types. In order to establish vegetation quickly on
processed shale, the weathering and leaching process
must be accelerated. This can be done by
supplemental watering for a limited period of time to
create a satisfactory soil medium.
Potential Impact on Water Quality & Quantity
The proposed plant will use about 3.3 barrels of
water per barrel of major products (fuel oil and a
special quality liquefied petroleum gas) produced.
Total water use will be approximately 170,000
barrels of water per day or about 11 cfs. Urban water
use requirements, resulting indirectly from the
population growth accompanying a commercial plant,
will amount to an additional 10 to 20 percent. During
normal flow of the Colorado River, this total
quantity of water will be available for appropriation.
During periods of low flow, unappropriated water
will be obtained from other sources such as the Green
Mountain Reservoir (ref. 1).
Studies of water usage have revealed that although
the proposed plant is designed to be totally
consumptive of water and without any effluent
discharge, two potential water quality impacts may
occur. Under upset or disaster conditions, discharges
of effluents from the plant and mine to existing
streams and aquifers could occur In addition, slight
increases in downstream Colorado River salinity
concentration could result from the withdrawal of
about 11 cfs for use in the plant. To the extent that
this consumptive use replaces water uses which are
salt loading, the net result could be a decrease in
downstream salinity.
The primary use of water in the disposal operation
will be to moisten processed shale, to insure
maximum stability of the embankment, and to
suppress dust. Colony has conducted detailed
investigations of the relationship between various
concentrations of water and the stability of the
embankment. Preliminary studies indicate that the
low permeability of compacted processed shale
should minimize migration of water used to moisten
the shale into subsurface aquifers. A catchment dam
will be constructed below the embankment to
confine runoff which may contain concentrations of
salt and other dissolved solids leached from the
processed shale. The confined water will be circulated
back to the active disposal area for moistur.zing
purposes (ref. 1).
Development of oil shale in Colorado, Utah, and
Wyoming may affect water quality and quantity in
the Colorado River drainage basin downstream of
each development site.
The historic use of water in the Colorado River
Basin for various purposes including industrial
development, irrigation, residential use, storage,
power generation, recreation, eastern slope diversions,
etc., has reduced the quantity of purer water
contributed by upstream water sources and
tributaries and increased the amounts of dissolved
solids entering the river. As a result, salinity in the
lower main stem of the river has increased steadily
over the years. For example, storage of water in
reservoirs throughout the basin increases evaporative
loss of water by increasing the total surface area of
water exposed to the atmosphere. Irrigation practices
also increase the loss of water through increased
evaporation and transpiration. In addition, irrigation
water which is not retained within root zones or lost
to deep percolation normally leaches substantial
amounts of soluble salts from irrigated soil. The salt
loading effect of leaching produces higher salinity in
irrigation flows returned to parent streams. The
totally consumptive use of water for any purpose in
the upper reaches of the basin tends to increase
downstream salinity levels. This is because reductions
in the total amount of the relatively purer water
attributable to upstream sources lead to
corresponding reductions in the diluting effect of this
water downstream. Water diverted for
357
-------
nonconsumptive industrial municipal, and residential
purposes is normally returned to the parent streams
with a higher salinity concentration than at the
original point of diversion. The concentrating effect
of the evaporative losses and salt loading related to all
of these uses currently threatens to diminish the
range of uses to which lower basin water can be
applied.
Despite the fact that the general sources of
increased salinity have been identified, cause and
effect relationships between specific upstream uses of
water and increased downstream dissolved solid
concentrations are difficult to define precisely.
Because of the mingling of water from separate
sources in basin reservoirs and the release of water
stored in these reservoirs for varying lengths of time,
the specific impact of any single upstream facility or
use is difficult to isolate. According to the
Department of State (ref. 2), the resulting storage
"damping" effects of upstream actions on
downstream water quality may be spread over several
years. Therefore, it may be impossible to identify the
specific effect of any individual upstream use in any
quantifiable way downstream.
The potential deterioration of water quality in the
lower main stream of the Colorado River has become
the subject of continuing negotiations between the
United States and Mexico. In order to insure
compliance with the various agreements between
these countries on salinity, the Department of State
has considered various alternative for controlling
salinity concentrations at the United States-Mexican
border. The environmental impacts of each of these
alternatives have also been compared and evaluated
(ref. 2). Subject to the passage of enabling Federal
legislation, the Department of the Interior has elected
to construct desalting facilities in the lower portion
of the basin as the best solution to the problem at
this time. Various international, Federal, multistate,
and State advisory groups are searching for
independent solutions. The following salinity policy
statement, issued by the Seventh Session of the
Enforcement Conference on Pollution of the
Colorado River, has received favorable comment from
various Federal and State agencies:
"A salinity policy be adopted for the Colorado
River System that would have as its objective
the maintenance of salinity concentrations at or
below levels presently found in the lower main
stem. In implementing the salinity policy
objective for the Colorado River system, the
salinity problems must be treated as a
basin-wide problem that needs to be solved to
maintain Lower Basin water salinity at a below
present levels while the Upper Basirt continues
to develop its compact-apportioned waters."
(ref. 3)
As yet, neither the Federal Government nor the
State of Colorado has established maximum values or
standards for salinity concentrations in natural water
bodies or for effluents from industrial, municipal, or
agricultural sources. Because the Environmental
Protection Agency presently has the authority to
prescribe standards for most types of discharge, it is
expected that regulation of effluents (including
irrigation return flows) will precede regulations
applicable to the indirect effects of totally
consumptive diversions.
A comparison of the volume of Colony's expected
diversion for the proposed plant north of Grand
Valley, Colorado, with the volume of other existing
or proposed uses, is helpful to the overall evaluation
of the significance of the impact of the Colony
project. Colony presently intends to consume less
than 9.000 acre-feet of water per year at the
proposed plant and mine. According to the Denver
Water Board, the City and County of Denver plan to
divert up to 183,000 acre-feet of water per year from
the Colorado River Basin by 1980 and up to 338,000
acre-feet per year by the year 2000. Evaporative loss
of water per year from Lake Mead exceeded 700,000
acre-feet during the years 1970, 1971, and 1972.
Considering the magnitude of evaporative losses from
other basin reservoirs, such as Lake Powell and at
Imperial Dam, the salinity impact of the Colony
project will be negligible (ref. 1).
Based on the previously quoted recommendations
of the Enforcement Conference on Pollution of the
Colorado River, Skogerboe (ref. 3) has proposed a
policy of nondetenoration of present salinity levels
by maintaining a net salt balance at the point of
diversion in Grand Valley equivalent to the present
mean annual salinity concentration at Hoover Dam.
Inherent in this proposal is the assumption that the
salinity level at Hoover Dam should be the controlling
value; depending upon the goal of any particular
user's policy, other control values could be selected.
The possibilities include the mean annual
concentration at Imperial Dam. at other downstream
locations in the watershed, or the value at any point
in the basin which constitutes the limiting value for
any specific existing use.
Nondeterioration is only one of a number of
alternate methods for controlling downstream
358
-------
salinity. These methods include the construction of
desalting facilities, more efficient use of water in
irrigation operations and substitution of water
obtained from sources outside the basin (refs. 3,4).
As indicated previously, the Federal Government has
selected the alternative of desalting plants. This
alternative has the advantage of preserving the full
range of existing uses of water in the upper portion of
the basin.
In view of the complexity of the issue of salinity
control, the likelihood of future regulation, and the
number of alternate control methods, it is inadvisable
for an individual water user to make significant
expenditures to implement any single alternative at
this time. As a result. Colony intends to continue
monitoring the development of salinity controls and
to evaluate further the need for mitigating the slight
impacts of the proposed plant before commitmg itself
to any particular solution.
Substantial quantities of ground water are believed
to exist under the two Federal test lease tracts of the
Piceance Basin. It may be possible to use the water
produced by mine de water ing in plant operations
associated with the Federal lease tracts. If this is
possible, consumptive use on lease tracts from surface
drainages may be substantially reduced.
The question concerning water availability for
various uses in the Colorado River Basin is ongoing.
This question has also been asked regarding the new
oil shale industry. Sparks (ref. 4) concluded that
250,000 acre-feet of water can be made available to
support a mature oil shale industry in Colorado. This
amount could perhaps be increased to as much as
400,000 acre-feet with a corresponding loss in
agricultural production, because most of the available
water supplies in Colorado are devoted to agriculture
according to Sparks (ref. 4).
The possible environmental impact of an oil shale
processing facility on air quality will consist of minor
effects such as slightly higher local surface
temperatures, increased local humidity, minor
interference with existing diurnal wind patterns, and
a slight reduction in local solar radiation. In addition,
there may be increases in ambient levels of sulfur
oxides, nitrogen oxides, particulates, hydrocarbons,
and carbon monoxides resulting from plant stack
emissions as well as the generation of fugitive dust.
However, the Colony Development Operation
believes that air contaminants which may be released
from a commercial plant will be acceptable to both
Federal and State authorities. Such conclusions are
based on studies which were carried out at Colony's
site on Parachute Creek {ref. 1).
Due to limited time, there are various
environmental considerations which have not been
discussed in detail in this paper. However, past studies
have been numerous and comprehensive. With the
leasing of Federal lands in the Piceance and Unita
Basins, numerous new detailed studies are being
undertaken by the various companies involved in the
leasing program. The past and ongoing studies have
and will continue to define potential problems as well
as plausible solutions. The result of all the
environmental research will allow maximum
development with minimum impact. As a result of
technological developments coupled with
environmental considerations, oil shale now
represents a viable alternative energy source which is
available for immediate commercialization. The
low-sulfur fuel oil which will likely be produced by
the initial commercial plant (expected to under
construction in Colorado within a year) has obvious
environmental benefits in the regions of the country
where it will be consumed. The companies directly
involved with oil shale development believe that oil
from shale is a partial solution to the current energy
crisis.
REFERENCES
1. An Environmental Impact Analysis for a Shale
Oil Complex at Parachute Creek Colorado;
Colony Development Operation, 1974.
2. Final Environmental Impact Statement: Possible
Options for Reducing the Salinity of the
Colorado River Water Flowing to Mexico, U.S.
Department of State (USDS), Washington, D.C.,
1972.
3. G. V. Skogerboe, Colorado River Salinity
Impact of Parachute Creek Oil Shale Plant and
Alternatives for Mitigation, Colony Development
Operation, Denver, Colorado. 1974.
4. F. L. Sparks, "Water Prospects for the Emerging
Oil Shale Industry," 7th Oil Shale Symposium,
Colorado School of Mines, Golden, Colorado,
April 18, 1974.
359
-------
360
-------
OVERVIEW OF R & D NEEDS ON ENVIRONMENTAL ASPECTS
OF COAL-CONVERSION PROCESSES
A. A. Jonke and W. Podolski*
Abstract
This paper gives an overview of the environmental
factors related to all of the various types of
coal-conversion processes, and it considers the R & D
needs for alleviating environmental concerns. The
research requirements for avoiding serious
environmental abuse are vast and range from
improvements in coal mining methods to the
problems of disposing of waste products and heat.
The conversion of coal to liquid or gaseous fuels does
not automatically assure an improved environment.
Pollutants, such as ash and sulfur, must be removed
from the coal-derived fluids to levels even lower than
those corresponding to the emissions from
conventional coal-burning power plants. Unless more
efficient power cycles are developed, the overall
thermal effects of coal conversion may be greater
than those for conventional power plants. The
quantification of the environmental problems for
each coal-conversion process is needed, and the
commonalities and differences of the various
processes must be weighed. A systems analysis study
will be needed to provide the basis for intelligent
planning for the utilization of coal energy with
minimum adverse environmental, health, and safety
effects.
INTRODUCTION
The expected emphasis on and drive toward
national energy self-sufficiency implies a very real
possibility for large scale environmental degradation.
There is great concern, on the one hand, that
unabated growth in energy production and utilization
will cause irreparable harm to the environment and,
on the other hand, that measures to protect the
environment may further exacerbate the current
supply problems faced by the energy industry. The
environmental costs of vastly increasing domestic
energy supplies are hard to calculate, but they are
potentially severe.
It is now generally recognized that the Nation must
use coal over the next few decades at rates that are
•The authors are with the Argonne National Laboratory,
Argonne, Illinois; A. A. Jonke is Senior Engineer, and W.
Podolski is an Assistant Chemical Engineer.
double or treble our current levels. Our ability to
actually achieve such an expansion of production and
utilization is in serious doubt, mostly due to
uncertainties about environmental impacts. The
research requirements for avoiding serious
environmental abuse are vast and range from needed
improvements in coal-mining methods to the
problems of disposing of waste products and heat. We
should first recognize, however, that many of the
er ironmental problems may not yet be known.
T e major emphasis in coal conversion R & D. thus
far, as been on the solution of technical problems; as
a co''sequence, there are large gaps in our knowledge
of the fundamental processes that are involved in coal
extraction, conversion, and utilization. Most of the
schemes for producing clean forms of fuel from coal
that have progressed beyond the pilot-plant stage are
based on upgraded technology of the 1930's, and
many of the potentially attractive schemes for
conversion of coal to alternative fuels are still at a
bench scale. In many cases, we are building pilot
plants and designing demonstration plants on the
basis of empirical art. This can lead to unforeseen
environmental consequences when the processes are
scaled up.
Pilot plants are generally operated over a limited
range of variables in order to optimize operating
conditions and to provide economic data for
subsequent commercial-scale operation. However, the
information needed for determining all of the
necessary environmental ramifications may not be
obtainable from pilot-plant programs on a timely
basis. Hence, one important need related to
environmental impact of coal conversion will be a
carefully thought-out fundamental program,
including bench-scale studies, aimed at identifying
and quantifying all of the environmental problems
that require solution.
Although it now appears that substantial Federal
and private funding will become available to conduct
needed R & D, trained manpower with experience in
this field is in short supply. Consequently, there will
be a need to utilize scientists and engineers from
related fields. A cooperative effort that employs
Federal laboratories, private industry, and universities
in the most effective manner will be highly desirable.
This paper is intended to present an overview of R
& D requirements for coal conversion processes. But
361
-------
to avoid repetition and conflict with other
presentations in this symposium, we will concentrate
on selected areas and overall systems requirements
that are common to all coal conversion and
utilization schemes. Specific R & D needs associated
with various fossil-fuel conversion schemes are
covered by several very competent speakers in this
session.
THE IMPORTANCE OF ADVANCED POWER CYCLES
The conversion of coal to liquid or gaseous fuels
does not automatically assure an improved
environment. Pollutants, such as ash, sulfur, and
nitrogen compounds, must be removed from the
coal-derived fluids to levels even lower than those
corresponding to the emissions from conventional
coal-burning power plants. A substantial R & D effort
will be needed to accomplish the cleanup of these
fuels in an efficient and economical manner.
Consider, also, the matter of waste heat. The
realization that the Nation's sources of water for
cooling may not be great enough to fill energy
requirements in the decades ahead makes the waste
heat problem one of increasing concern. A modern
fossil-fuel power plant operating at 41 percent
efficiency gives off 1.4 kW of waste heat for each kW
of electricity produced. If we convert the coal to a
fluid fuel at a thermal efficiency of perhaps 85
percent the amount of waste heat emitted jumps to
nearly two units per unit of electricity. Fuel
requirements increase in like manner.
Hence, the use of coal conversion schemes in
conjunction with conventional steam-power cycles
does not appear to be one of the most attractive
options, except perhaps on an interim basis. Instead,
major incentives exist for a large R & D effort to
develop more efficient power cycles that take full
advantage of the potential of clean fuels.
Advanced power cycles, if successfully developed,
would conserve our fuel resources and decrease air,
water, and thermal pollution. But what types of
advanced power cycles should we develop? A number
of systems have been under study and currently are in
various stages of development. These include:
combined gas/steam cycles, potassium topping cycles,
Rankine bottoming cycles, closed cycle helium
turbine systems, plasma MHD, liquid metal MHD,
supercritical CO2 cycles, and others. Although their
advantages and disadvantages have been discussed in
the literature, it is not possible, from the information
available, to assess the relative merits of the various
concepts. A number of studies have been made that
allege to compare the various conversion cycles.
However, conditions are generally picked to
emphasize positive results of a specific system that is
being promoted, whereas, minor changes in the
ground rules of such studies could change the
conclusions reached.
The first important need, therefore, is for a
comprehensive and careful systems analysis of all the
important concepts and fuel alternatives. The
objective of such a study would be to provide
guidance in evaluating the advanced conversion
options, establish program priorities, and develop
funding requirements. This study should be designed
to evaluate the competitive positions of the various
concepts based on a comprehensive, consistent set of
evaluation factors. Such evaluation factors might
include the probable performance of the technology,
the utility of the technology, the R & D
requirements, the resources required to achieve
utilization, and the impacts of the technology.
On the basis of a recent advertisement in the
Commerce Business Daily, it appears that an
evaluation study of advanced energy-conversion
systems is about to be launched under management
of the NASA Lewis Research Center. After priorities
are established, R & D to develop the improved cycles
should be carried forward expeditiously. There is a
real expectation that cycle efficiencies of 50 percent
or more can be achieved.
We need also to explore the practicality of new
bottoming cycles, using working fluids like ammonia,
isobutane. nitrogen tetroxide, etc. This technique
might further reduce fuel requirements, waste heat
emissions, and other environmental effects. Although
such bottoming cycles have been considered in the
past, the changing energy picture warrants a new look
at this concept.
SOME COAL EXTRACTION CONSIDERATIONS
We turn now to another serious problem area that
is common to all processes that utilize coal—namely,
extracting it from the earth. Deep coal mining, as
presently practiced, is a dirty and hazardous business.
Strip mining can be a disaster to the landscape. As the
scale of mining activities increases, the problem
becomes of increasing national concern.
Consider, for example, a hypothetical situation in
which all the Nation's energy were supplied by
strip-mined coal. The demand would be about 5
million tons per day. For example, if an 18-inch thick
seam (a very worthwhile deposit) were processed,
about 3 square miles per day would be overturned to
362
-------
supply the demand, and a comparable amount might
be destroyed by spoil banks, access road, etc., under
present practices (ref. 1).
The consequences of surface mining practices are
well known. In the eastern part of the country,
exposed seams and spoil banks cause acid drainage
that ruins waterways and spoils fishing. The fragile
land may be softened by rainfall thus causing whole
disturbed hillsides to slide, scarring large areas. In the
West, alkaline soils and insufficient rainfall and
nutrients to insure vegetation are the chief problem.
The very thin topsoils in the West cannot easily be
segregated for reuse, or if that problem is solved, they
cannot be held in place.
Cost factors, to a large extent, will determine the
future of strip mining because of stringent
reclamation requirements that must be imposed on
these operations. New concepts need to be developed
in order for the surface mining industry to meet its
environmental obligations. Research and development
needs can be grouped into two categories: first,
mining methods and equipment development, and
second, improved land reclamation measures.
In the area of improved mining techniques, several
methods (ref. 2) could have a positive environmental
effect. One of these is the use of highly mobile
draglines in conjunction with bulldozers in order to
level the tops of spoil banks and to decrease the time
lag between mining and reclamation. A second
method may be to use a belt transfer system to move
the spoil around the working areas. Each of these
methods and many others not mentioned will need
specialized pieces of equipment, often on a
site-specific basis. A large scale development effort is
needed here.
Special effort is needed to develop the means to
mine the very thick western seams. These seams are
too thick to provide sufficient roof support for
underground mining, and they stress the limits of
conventional surface-mining equipment.
Combinations of surface and underground mining and
improved open-pit mining operations should be
investigated.
Extensive development needs exist in the area of
reclamation and reuse of surface-mined lands. In a
way, this may be fortunate because large increases in
coal production are likely to be from surface mines,
and the environmental effects from these mining
methods are reasonably well known and can be
controlled, albeit at a high cost. Land reclamation is
also likely to be site specific, thus adding to the cost.
For the western States, research needs to be done on
the possibility of providing artificial soils with various
agents such as enzymes and bacteria to enable plants
to grow. Fast growing plants capable of growing in
highly alkaline soils need to be developed. In the
East, it will be necessary to develop low-cost means
of neutralizing acid soil. Some small scale work is
being done (ref. 3) on the use of sewage sludge in
conjunction with agricultural lime to assess the ability
to reclaim surface-mined land in Illinois. Since this
effort has shown promise, an expanded effort is
needed to develop new techniques for revegetating
spoil areas.
Since the development of environmentally sound
surface mining techniques will be very costly, it is
essential that models and simulations of strip-mining
operations be developed. Since equipment is mostly
site specific, a model would enable variables in
surface mining to be optimized as they relate to a
given region. By simulating surface mining operations,
land reclamation costs can be included, and
development costs can be minimized. Limited field
studies will be necessary to provide quantitative data
for use in the simulations. These studies should all be
part of an overall evaluation of the alternative means
of obtaining energy coupled with intelligent land and
resource use planning.
There are perhaps as many areas for potential
research related to underground mining as there are
for surface mining. Details on many of these areas
have been discussed in the report of the
Carnegie-Mellon workshop on Advanced Coal
Technology (ref. 4). While the environmental effects
of surface mining are reasonably well understood, as
mentioned above, the long-term effects from surface
subsidence resulting from underground mining are
neither well understood nor readily predictable. It is
necessary to investigate the causes and factors
affecting surface subsidence in order to be better able
to predict its occurrence and effects. Development of
techniques for flushing or backfilling is also
necessary. The benefits that would ensue are the
general structure of the land would be preserved, and
communication between surface and subsurface water
would be cut.
A major investigation is needed that would be
directed at preventing the formation of acid mine
water to avoid the need for the remedial type
treatment now used. Other areas needing research
work include development of techniques for
recovering coal fines to improve coal economics and
reduce air pollution, improving sulfur removal at the
coal preparation plant, perhaps by chemical means
such as leaching, and finally finding means for high
volume utilization of solid mine wastes.
363
-------
OVERALL SYSTEMS NEEDS
Systems planning for the conversion of coal into
alternative fuels presupposes that a decision has been
made to utilize the Nation's coal resources in a
particular manner. In fact, however, a need exists to
develop an overall plan on both a national and
regional basis for the utilization of our fossil fuel
resources. Regional plans could then provide answers
concerning the best use of Colorado River water and
the ultimate use for the reclaimed land. Long-term
plans could be made, for instance, to return western
lands to grazing pasture or recreational purposes or
even to eliminate certain coal lands from production.
Intelligent, long-range land and resource use plans
need to be formulated, at least on a regional level,
and it is in the framework of regional planning that
waste heat disposal and water utilization are best
placed. Here, research in setting up integrated models
or projects is desirable, and a high priority should be
given to such efforts.
As an illustration of the systems needs, means of
predicting the effects of waste heat disposal is
obviously needed, for, in the face of this uncertainty,
very strict water temperature standards are being
adopted at an enormous cost. Thus, high priority
items are (ref. 5) research to predict water
temperatures in a specific zone that result from
various discharges and the biological effects
associated with such changes. Some intelligent
criterion must also be developed to weigh the cost of
possible damages against the cost of preventing any
damages.
Research should also be encouraged to find
beneficial uses of waste heat. Possible applications,
which need more investigation, are the use of heat to
enhance fish culture or to use it in agricultural
applications.
The availability of water will undoubtedly limit the
growth of a coal conversion industry in the western
States. The problem can only be addressed on a
regional basis. Questions concerning what happens to
the water supply if large quantities of coal are
removed from the ground must still be answered.
Much development is needed to minimize the
consumptive use of water in converting coal to
alternative fuels. Dual purpose utilization of water
may have to be instituted. For example, water
destined for irrigation might first be used for process
cooling water. It is clear that conventional economic
factors and market action will not be enough to bring
about the necessary improvements in efficiency.
Technical, economic, and environmental impact
assessments covering the entire field of coal-based
energy technologies are urgently needed. The
optimum utilization of coal energy cannot be
accomplished without examining the total energy
picture and identifying the relative impacts that coal
will have.
CONCLUSION
We have briefly touched on some areas relating to
coal conversion research and development needs, and
we have been by no means exhaustive, but rather
selective, in their treatment. It is very probable, as we
have pointed out, that the size of a coal-conversion
industry will be limited not so much by
environmental objections to the processes themselves,
but by limitations placed on related areas such as
mining capacity in the face of stringent land
reclamation requirements. The chief emphasis of our
presentation is that research relating to overall
systems concepts should be given the highest priority,
otherwise development of a coal conversion industry
will be on a haphazard basis, and it will experience
many delays while contributing little to increased
utilization of our fossil fuels. The delays currently
being experienced by the nuclear power industry, as a
result of environmental concerns, should be kept in
mind.
Finally, many of the problems that we have
discussed relating to coal conversion also apply to the
increased utilization of our oil-bearing shale
formations. Land use and water availability problems
are even more severe for shale utilization, so that
overall systems planning is exceedingly important.
REFERENCES
1. D. Rose. Lecture notes from a short-course on
"Energy, A Unified View," M.I.T., July 1973.
2. An Analysis of Strip Mining Methods and
Equipment Selection. Report to Office of Coal
Research by Coal Research Selection, College of
Earth and Mineral Sciences, the Pennsylvania
State University, Contract No. 14-01-0001-390,
May 29, 1974, pp. 15-127.
3. R. P. Carter, R. E. Zimmerman, and A. S.
Kennedy, Strip Mine Reclamation in Illinois,
Prepared for Illinois Institute for Environmental
Quality by Energy and Environmental Studies
Division, Argonne National Laboratory, Contract
No. 31-109-38-2687, December 1973, p. 51.
4. S. W. Gouse, Jr., A Program of Research,
Development, and Demonstration for Enhancing
364
-------
Coal Utilization to Meet National Energy Needs. 5. S. H. Schurr, Energy Research Needs, National
Prepared for NSF-RANN by Carnegie-Mellon Technical Information Service, PB-207 516.
University Workshop on Advanced Coal October 1971. pp. 1X18-1X49.
Technology, October 1973, pp. III-1-III-48.
365
-------
TECHNICAL REPORT DATA
(Please read Instructions on the revtne before completing)
1 REPORT NO
EPA-650/2-74-118
3 RECIPIENT'S ACCESSION NO.
4 TITLE AND SUBTITLE
Symposium Proceedings: Environmental Aspects of
Fuel Conversion Technology (May 1974, St. Louis,
Missouri .
5 REPORT DATE
October 1974
E PERFORMING ORGANIZATION CODE
r AUTHORCS)
Franklin A. Ayer (Compiler)
8 PERFORMING ORGANIZATION REPORT NO
9 PERFORMING ORGANIZATION NAME AND ADDRESS
Research Triangle Institute
P. O. Box 12194
Research Triangle Park, NC 27709
1O. PROGRAM ELEMENT NO
1AB013; ROAPs 21ADD/21AFJ
11 CONTRACT/GRANT NO
68-02-1325, Task 6
12 SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
13 TVPE OF REPORT AND PERIOD COVERED
Final
14 SPONSORING AGENCY CODE
15 SUPPLEMENTARY NOTES
16 ABSTRACT
This document is the final report covering EPA's symposium held at the Chase-Park
Plaza Hotel, St. Louis, Missouri, on May 13-15, 1974. The principal objective of
the symposium was to review and discuss environmentally related information of
coal conversion technology. More specifically, papers were presented that covered
environmental quality and standards, fuel contaminants, environmental aspects of
specific fuel conversion systems, fuel utilization and total environmental assessment,
and research and development needs.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b IDENTIFIERS/OPEN ENDED TERMS
c COSATI Field/Croup
Air Pollution
Fossil Fuels
Conversion
Water Pollution
Fuel Contamination
Coal Gasification
Liquefaction
Oil Shale
Air Pollution Control
Stationary Sources
Solid Waste
13B, 07D
21D, 08G
13H
8 DISTRIBUTION STATEMENT
19 SECURITY CLASS (T\isReport)
Unclassified
21 NO OF PAGES
374
Unlimited
20 SECURITY CLASS {Thispage)
Unclassified
22 PRICE
EPA Form 222O-1 (9-73)
366
------- |