EPA-650/2-74-009-m
October 1975 Environmental Protection Technology Series
EVALUATION OF POLLUTION CONTROL
FOSSIL FUEL CONVERSION
PROCESSES
LIQUEFACTION: SECTION 3. H-COAL PROCESS
\
LLJ
U.S. EnvironinHnial Piotaclion Agency
Office of Rfisuatch and Development
Washington, D. C. 20460
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EPA-650/2-74-009-m
EVALUATION Of POLLUTION CONTROL
IN FOSSIL Fill CONVERSION
LIQUEFACTION: SECTION I. H-COAl PROCESS
by
C . E . Jahnig
Exxon Research and Engineering Company
P. O. Box 8
Linden, New Jersey 07036
Contract No. 68-02-0629
ROAP No. 21ADD-023
Program Element No. 1AB013
EPA Project Officer: William J . Rhodes
Industrial Environmental Research Laboratory
Office of Energy , Minerals, and Industry
Research Triangle Park, North Carolina 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH AND DEVELOPMENT
WASHINGTON. D.C. 20460
October 1975
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EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection
Agency and approved for publication. Approval does not signify that
the contents necessarily reflect the views and policies of the Environ-
mental Protection Agency, nor does mention of trade names or commer-
cial products constitute endorsement or recommendation for use.
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development. U.S. Environ-
mental Protection Agency, have been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These series are:
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOCIOECONOMIC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
Publication No. EPA-650/2-74-009-m
11
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TABLE OF CONTENTS
1. SUMMARY 1
2. INTRODUCTION ...-..'. ........ 2
3. PROCESS DESCRIPTION. . . 4
3.1 Coal Preparation and Feeding 4
3.2 Liquefaction Section • • 4
3.3 Gas Separation and Cleanup 6
3.4 Liquid Product Recovery 6
3.5 Hydrogen Manufacture 7
3.6 Auxiliary Facilities 7
4. EMISSIONS TO ATMOSPHERE 12
4.1 Coal Preparation and Feeding 12
4.2 Liquefaction Section 24
4.3 Gas Separation and Cleanup 24
4.4 Liquid Product Recovery 25
4.5 Hydrogen Manufacture 26
4.6 Auxiliary Facilities 28
5. EFFLUENTS - LIQUIDS AND SOLIDS 32
5.1 Coal Preparation and Feeding 32
5.2 Liquefaction Section 32
5.3 Gas Separation and Cleanup 33
5.4 Liquid Product Recovery 34
5.5 Hydrogen Manufacture. 35
5.6 Auxiliary Facilities 36
6. SULFUR BALANCE 39
7. THERMAL EFFICIENCY 41
8. TRACE ELEMENTS 43
9. TECHNOLOGY NEEDS 47
10. PROCESS DETAILS 51
11. QUALIFICATIONS 56
12. BIBLIOGRAPHY 57
iii
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LIST OF TABLES
No._ I^
1 Inputs to H-Coal Plant 10
2 Outputs from H-Coal Plant 11
3 Description of Streams for H-Coal
Liquefaction Plant 14
4 Sulfur Balance H-Coal Plant 40
5 Thermal Efficiency H-Coal Plant 42
6 Example of Trace Elements That May
Appear in Gas Cleaning Systems 45
7 Technology Needs 48
8 Steam Balance H-Coal Plant 52
9 Electric Power Required in H-Coal Plant 53
10 Water Balance for H-Coal Plant 53
11 Make Up Chemicals and Catalyst Requirements 54
12 Potential Odor Emissions 55
13 Potential Noise Problems. 55
iv
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No.
LIST OF FIGURES
Page
Block Flow Plan for H-Coal Plant
for Coal Liquefaction
Effluents and Emissions from H-Coal
Liquefaction Plant 13
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TABLE OF CONVERSION UNITS
To Convert From
Btu
Btu/pound
Cubic feet/day
Feet
Galions/minute
Inches
Pounds
Pounds/Btu
Pounds/hour
Pounds/square inch
Tons
Tons/day
To
Calories, kg
Calories, kg/kilogram
Cubic meters/day
Meters
Cubic meters/minute
Centimeters
Kilograms
Kilograms/calorie,kg
Kilograms/hour
Kilograms/square centimeter
Metric tons
Metric tons/day
Multiply By
0.25198
0.55552
0.028317
0.30480
0.0037854
2.5400
0.45359
1.8001
0.45359
0.070307
0.90719
0.90719
vi
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- 1 -
1. SUMMARY
The H-Coal Process of Hydrocarbon Research Inc., Is reviewed from
the standpoint of its effect on the environment. Quantities of solid, liquid
and gaseous effluents are specified where this is possible, as well as the
thermal efficiency of the process. Techniques for controlling pollution are
outlined and discussed. For the purpose of reducing environmental impact,
a number of possible modifications or alternatives are presented for con-
sideration. In some areas existing information or control systems are
inadequate, therefore technology needs are pointed out covering such areas,
together with approaches to improve efficiency and conservation of energy
or water.
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- 2 -
2. INTRODUCTION
Along with improved control of air and water pollution, the
country is faced with urgent needs for energy sources. To improve the
energy situation, intensive efforts are under way to upgrade coal, the
most plentiful domestic fuel, to solid, liquid and gaseous fuels which
give less pollution. Other processes are intended to convert liquid
fuels to gas. A few of the coal gasification processes are already com-
mercially proven, and several others are being developed in large pilot
plants. These programs are extensive and will cost millions of dollars,
but this is warranted by the projected high cost for commercial gasifica-
tion plants and the wide application expected in order to meet national
needs. Coal conversion is faced with potential pollution problems that
are common to coal-burning electric utility power plants in addition
to pollution problems peculiar to the conversion process. It is thus
important to examine alternative conversion processes from the standpoint
of pollution and thermal efficiencies, and these should be compared with
direct coal utilization when applicable. This type of examination is
needed well before plans are initiated for commercial applications.
Therefore, the Environmental Protection Agency arranged for such a study
to be made by Exxon Research and Engineering Company under Contract No.
EPA-68-02-0629, using all available nonproprietary information.
The present study under the contract involves preliminary design
work to assure that the processes are free from pollution where pollution
abatement techniques are available, to determine the overall efficiency
of the processes, and to point out areas where present technology and
information are not available to assure that the processes are nonpolluting.
This is one of a series of reports on different fuel conversion processes.
All significant input streams to the processes must be defined,
as well as all effluents and their compositions. This requires complete
mass and energy balances to define all gas, liquid, and solid streams.
With this information, facilities for control of pollution can be examined
and modified as required to meet environmental objectives. Thermal
efficiency is also calculated, since it indicates the amount of waste heat
that must be rejected to ambient air and water and is related to the total
pollution caused by the production oif a given quantity of clean fuel.
Suggestions are included concerning technology gaps that exist
for techniques to control pollution or conserve energy. Maximum use was
made of the literature and information available from developers. Visits
and/or contacts were made with the developers to update published infor-
mation. Not included in this study are such areas as cost, economics,
operability, etc. Coal mining and general offiste facilities are not
within the scope of this study.
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- 3 -
Previous studies in this program to examine environmental aspects
of fossil-fuel conversion processes covered various methods for gasifying
coal to make synthetic natural gas or low Btu gas. Reports have been
issued on the Koppers, Synthane, Lurgi, C02 Acceptor, Bigas, Hygas, U-Gas
and Winkler processes (1,2,3,4,5,6,7,8). In addition, an environmental
study was made of the Meyers Process, which uses extraction to remove
inorganic sulfur from coal (9).
In the area of coal liquefaction, reports have been issued on
the COED Process of FMC (10) to make gas, tar, and char, as well as on the
SRC Process of Pittsburg & Midway Coal Mining Company to make a heavy liquid
clean boiler fuel (11).
These studies have now been extended to include coal liquefaction
using the H-Coal process being developed by Hydrocarbon Research Inc. The
present report covers our evaluation of environmental aspects of the H-Coal
process. Considerable information is available in the literature on the
products from the process as well as raw materials consumed, together with
their properties and compositions (12,13,14,15,16). Our study is based
primarily on reference 15, for the case making synthetic crude from
Illinois coal, using 18,600 SCF of hydrogen per ton of coal. As in previous
studies of this series, a complete and self-sufficient plant has been
defined, avoiding for example purchased power which would cloud the basis
for evaluating thermal efficiency and environmental effects. Since details
on utilities consumption for the process are not given in the publications,
these were roughly estimated and the necessary facilities included,
together with fuel supply and environmental controls etc.
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- 4 -
3. PROCESS DESCRIPTION
In the H-Coal process, coal is reacted catalytlcally with hydrogen
in a slurry system to make synthetic crude. The process can also be used
to make low sulfur fuel oil by operating at lower severity. For syncrude
operation, reaction conditions are about 850°F and high pressure, such as
2000 psig. Syncrude production is 91,240 barrells/day for the plant
feeding 25,000 tons/day of dry coal to the H-Coal reactor. An overall
flowplan for the process is .shown in Figure 1.
An ebullating bed reactor is used wherein the slurry of coal
and catalyst in oil is agitated by bubbling hydrogen gas through it. Size
of the catalyst is large relative to the coal, so that although the catalyst
is fluidized, it is retained in the reactor and is not carried out with the
liquid oil sidestream leaving the reactor. In addition, a gas stream is
withdrawn separately from the reactor top. Further details on the H-Coal
system are given in reference 15.
The following subsections describe the various operations in the
overall plant. These can be conveniently grouped into several areas cover-
ing coal preparation and handling, coal liquefaction, gas separation and
cleanup, liquid product recovery, hydrogen manufacture, and auxiliary
facilities such as utilities, water treating, oxygen plant, and sulfur
plant. This grouping will be followed through the report.
3.1 Coal Preparation and Feeding
This study assumes that cleaned coal is delivered to the plant,
consequently the facilities and environmental concerns associated with coal
cleaning will be at a different location, and therefore will not be covered
in the present report. Coal cleaning generates considerable amounts of
solid refuse to dispose of and"wash water to be cleaned up for reuse as
discussed in previous studies (5,11). A very large coal storage pile is
included, having 30 days supply for example.
Coal feed having a nominal 10% moisture is sent first to a dryer
where essentially aM moisture is removed, and the coal is then crushed
through 40 mesh. Crushed coal is mixed with recycle oil to form a slurry
that can be pumped into the high pressure hydrogenation system. In addition,
part of the dried coal goes to the gasifier so that hydrogen production can
be increased to balance consumption, and dried coal also supplies the fuel
used on the utility boiler.
3.2 Liquefaction Section
The coal slurry, together with makeup and recycle hydrogen, goes
to a preheat furnace and then to the H-Coal reactor where hydrogenation takes
place in the presence of an ebullating bed of coarse catalyst particles.
About 96% of the carbon in the coal is converted to liquid or gas products,
while the remaining carbon is retained in the ash which is withdrawm as a
sidestream from the reactor in the form of a slurry with product oil. Part
of this slurry is recirculated to the bottom of the reactor to maintain
desired flow conditions.
-------
Dryer
Vent
Gas
5486
Coal Feed T
Illinois No. 6 |
Coal to
Utility Boiler
3020
33,289 ^ Coal | 25,000 ^ Coal Slurry^
tion
Coal _^
1940
Vacuum Bottoms:
Oil 2253
Carbon 1171 _
Ash 2/i7S~-^^^^ G^Riflpr M^^
5899 -* ' * Reparation
1 — * "-I—
dry coal
Recycle Hydrogen
Lique-
faction
t
Recycle Oil
50,000
Hydrogen
1104
Sulfur „,,,,.
*^ Removal ^ ^
Gas
Cleanup
Gas and Vapors Sor>flrBfflT.,
•
Light Oil ^Spur Wai
\ '
Recycle Liquid |
Oil ^f— — — Distribu- r~"~"
tion 1
HeavyT Oil
Vent Gas: |
CO? 13,019
^ 2 900 l^..^^ Vacuum
13,257
Steam \f f If T
2134 Ash H,S Stream Steam Sour Water Bottoms Slurry
2667 3498 12,243 6658 to Gasifier
5899
4968 Nitrogen Sulfur Gas Agh fo^t Air Bloudown Water m^ Water
16'353 12*5 37,451 299 2,655,400 5100 8820 205 37,680 Sludge
ft V t t i t t ft
Oxygen Sulfur
plant Plant
Utility Cooling
Boiler Tower
Waste
Water
Treating
Makeup Q11
e - Storage
t f f t f t T .f
Air H2S Stream Coal Limestone Air Makeup Waste Water Water
21,321 4640 3020 473 .2,630,000 .Water 9025 37,'680
To. Plant Fuel:
Coal Dryer 270
"• Preheat Furnace 790
Tail Gas Incinerator 140
^ Gas | ^
Net Clean
Fuel Gas
:er 1 (64 MM sc£d)
f (900 Btu/c.f.)
H2S Stream
1142
I
i
Synthetic Crude
14,416 "
Sulfur 0.19 wt. %
Nitrogen 0.68 wt. 7.
Hydrogen 9.48 wt. %
HHV 18,290 Btu/lb
31,700
Figure 1
Block Flow Plan of H-Coal Plant for Coal Liquefaction
Note: Numbers are flow rates in tons/day.
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- 6 -
Gases are withdrawn as a separate stream from the top of the
reactor - part of the gas being recycled to the reactor inlet after cleanup
to remove sulfur compounds. The remaining gas is withdrawn as a product
from the process, and part of it is used to supply clean fuel to the coal
dryer, reactor preheat furnace, and tail gas incinerator on the Glaus plant.
In the gas cleanup operation, water and oil are condensed from the gases
leaving the reactor. The resulting sour water is sent to waste water
treating while the oil is combined with the main liquid product.
The main oil product is withdrawn from the reactor via a liquid
phase settling zone within the reactor so that the large catalyst particles
are separated from the oil product and retained in the reactor. The with-
drawn liquid contains ash and unreacted coal particles which are segregated
by vacuum distillation into the heaviest bottom fraction of the oil. This
vacuum bottoms is used to make hydrogen for the process by gasification with
oxygen and steam.
Heat is recovered from the hot effluents leaving the reactor, and
used to preheat feed streams or to make steam. Hydrogenation is an exothermic
reaction, giving an estimated heat release for this study case of 700 MM
Btu/hr, corresponding to 7700 Btu/lb hydrogen consumed, which heat is also
recovered and used.
3.3 Gas Separation and Cleanup
A gas and vapor stream is withdrawn from the top of the liquefaction
reactor, above the liquid level. It is substantially free of entrained
liquid, and therefore contains little or no solids. Upon cooling, oil and
water condense out and are separated. The sour water is sent to waste water
treating, while part of the oil is recycled to form a slurry with the coal
feed and the remainder of the oil is included in the final syncrude product.
The gas after condensation is cleaned up to remove sulfur compounds
which are sent to sulfur recovery. Part of the clean gas is recycled to the
H-Coal unit to supply hydrogen, and the rest is available as byproduct fuel
gas or for plant fuel. The process used for removing sulfur from the gas
is assumed to be scrubbing with an aqueous solution of amine, although hot
carbonate could be used instead.
3.4 Liquid Product Recovery
A liquid stream is drawn off separately from the reactor, consisting
of a slurry of ash and unreacted coal in heavy oil. This slurry is distilled
under vacuum to produce a clean light distillate oil, part of which is
recycled for slurrying the coal feed while the remainder is withdrawn as
syncrude product along with some of the light oil condensed from the gases
leaving the reactor.
Heavy bottoms from the vacuum tower, containing ash and unreacted
coal, is used to make hydrogen in a partial oxidation gasifier.
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- 7 -
3.5 Hydrogen Manufacture
A partial oxidation system is used for manufacturing hydrogen (17),
consuming as raw material the slurry of vacuum bottoms which may otherwise
present a disposal problem. The developer has indicated that a Texaco type
partial oxidation process is used, since this type of gasifier is expected
to be able to handle such a feedstock whereas some alternative processes
may not be able to.
The amount of vacuum bottoms is not sufficient to make all of the
hydrogen needed, so some coal feed is also sent to the gasifier, adding to
the coal consumption for the plant. Oxygen for gasification is supplied by
an onsite oxygen plant, while the required steam is provided from waste
heat boilers. The gasification reactor operates at slagging conditions,
over 2000°F, and 500 psig pressure.
Raw gas is quenched and then scrubbed with water to remove
particulates including ash and soot. Water condensed at this point contains
a wide spectrum of contaminants including ammonia, HCN and other nitrogen
compounds, various sulfur compounds, phenols, etc., this sour water is sent
to waste water cleanup.
Sulfur compounds are removed from the gas in the ,next processing
step by scrubbing with amine. Some C02 is also removed but this is
incidental. Amine solution from the absorber is regenerated in a stripping
tower with reboiler. The sulfur containing gas stream from amine regeneration
is sent to a Glaus plant for sulfur recovery. Tail gas cleanup is included,
as is common practice, so that the sulfur plant will meet emission require-
ments.
Due to -the high hydrogen pressure existing in the hydrolique-
faction system it is expected that sulfur in the gas will be as H2S
rather than COS, but analyses should be obtained to determine the forms
of sulfur present. Hydrogen for the process is manufactured by gasifica-
tion using steam and oxygen, which will no doubt result in significant
COS formation. It may be desirable to provide a hydrolysis step to con-
vert COS to H2S and C02 prior to-acid gas removal. This reaction is known
to be catalyzed by bauxite or alumina. Alternatively hydrogen might be
made by conventional steam reforming of clean byproduct gas, in which case
the byproduct char and tar could be used as boiler fuel with stack gas
cleanup, or the char could be gasified to make clean fuel gas.
The clean desulfurized gas is reheated and mixed with supplemental
steam for processing in the shift conversion reactor. After shifting, the
gas is cooled, and scrubbed to remove C02 using one of the available con-
ventional systems such as hot carbonate. The C02 stream is vented to the
atmosphere as a waste product. Environmental aspects of this stream are of
particular concern, in that the flow rate is very large.
Finally, the product hydrogen is compressed and fed to the hydro-
liquefaction reactor which operates at about 2000 psig.
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- 8 -
3.6 Auxiliary Facilities
The discussion so far has described the basic processing units
used in a plant for hydroliquefaction of coal. In addition, auxiliary
facilities are needed such as an oxygen plant, sulfur plant, and utilities
systems to supply steam, electric power, and water. Waste water treating
is also required. In addition to contributing effluents and emissions, these
auxiliary facilities may also consume additional fuel in the form of coal
or clean products from the process.
Oxygen is made by liquefaction of air, giving a waste stream of
nitrogen that is clean and can be vented directly to the atmosphere. 'A
sulfur plant is needed to recover by-product sulfur from the various
sulfur compounds removed in the gas cleanup operations on the H-Coal unit
and in hydrogen manufacture. A Glaus type sulfur plant is used, with tail
gas cleanup in order to meet environmental requirements. Total sulfur
production amounts ot 1295 tons/day.
In order to make the plant self-sufficient, utility steam and
electric power are generated for use in the process so that purchase of
utilities is avoided. This is a basic modification of the original
published case (15) in which over 200,000 KW of electric power was purchased
or supplied from offsite.
Utility steam is generated at 1000 psig pressure and used to
drive the turbogenerator and compressors. In some cases, bleeder turbines
are used in order to balance out the generation and consumption of steam at
600 psig and 70 psig (see Table 8). Coal is used as fuel in the utility
boiler, on the basis that stack gas cleanup will be provided to control
emissions of sulfur and participates. As shown in Figure 1 the amount of
coal used in the boiler is 3020 tons/day on a dry basis, giving 299 tons
of ash to dispose of.
Water is used for cooling, primarily to condense steam from tur-
bines or for overhead condensers. Cooling water is recirculated at 200,000
gpm through a cooling tower where about three-quarters of the heat is
dissipated by evaporation, and the remainder is taken up as sensible heat
of the air passing through. The cooling tower is an area of major environ-
mental concern in that a very large volume of air flows through the tower,
and every effort should be made to see that it does not become contaminated
due to leaks in exchangers, etc.
Waste water from the hydroliquefaction section, commonly called sour
water, contains a wide range of pollutants including H2S and other sulfur
compounds, nitrogen compounds such as ammonia, HCN, pyridines, etc., phenols
and other oxygenated compounds, plus suspended solids, oil, and tar. It
would not be acceptable to discharge such water directly from the plant;
therefore it is cleaned up and reused. Cleanup of waste water involves
the following operations:
• Settling and filtration to remove solids.
• Extraction of phenols using a suitable solvent.
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- 9 -
• Sour water stripping to remove H2S, NH3, and other
low boiling materials.
• Oil removal by API type separator and froth flotation.
• Biological oxidation (biox) to consume residual small
amounts of various contaminants, which are converted to
cellular sludge.
• Activated carbon adsorption, if needed, for final polishing.
• Possibly special treatment for trace elements.
Ammonia will be recovered as a by-product, amounting to 205 tons/day while
other contaminants removed from the waste water, such as I^S and phenols
can be sent to the sulfur plant for incineration, or returned to the process
where they can be converted and destroyed.
Treated waste water is used as cooling tower makeup, supplemented
by boiler blowdown and fresh water. Slowdown from the cooling tower con-
stitutes the net water discharge from the plant amounting to 5100 tons/day
(850 gpm). This blowdown, together with drift loss from the cooling tower,
serves to purge dissolved solids from the system so as to prevent excessive
buildup in the cooling water circuit.
Fresh water makeup is supplied to the cooling tower, as well as
to boiler feed water preparation. Combined, these amount to 37,680 tons/day
or 6300 gpm, which is the overall water consumption of the plant. Treating
of makeup water includes lime softening and clarification, plus demineraliza-
tion on the portion going to boiler feed water.
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- 10 -
Table 1
Inputs to H-Coal Plant
Illinois No. 6 Coal Feed
Coal to H-Coal reactor
Coal to gasifier to make H2
Coal to utility boiler
Makeup water
Tons/Day
(dry basis)
25,000
1,940
3,020
29,960
37,680
Coal Analysis, dry basis
Volatile matter
Fixed carbon
Ash
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
Ash
Wt>.%
42.0
48.1
9.9
100.0
70.7
5.4
1.0
5.0
8.0
9.9
100,0
High heating value, dry, Btu/lb
12,983
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- 11 -
Table 2
Outputs from H-Coal Plant
(Based on reference 15, Table 2)
Synthetic Crude (91,240 B/D)
Net Byproduct Gas
Sulfur
Ammonia
Ash;
from gasifier
from utility boiler
Treated waste water from plant
L4,416 tons/day
1,210 tons/day
1,295 tons/day
205 tons/day
2,667 tons/day
299 tons/day
2,966 tons/day
5,100 tons/day
Synthetic Crude Inspections
Gravityi °API
Hydrogen, wt. %
Sulfur, wt. %
Nitrogen, wt. %
25.2
9.48
0.19
0.68
Byproduct Gas
Free hydrogen, est. vol. % 56
C^C. hydrocarbons, est. vol. % 44
High heating value, ave. Btu/lb 24,000
(900 Btu/c.f.)
Yield Basis, wt. % on m.a.f. Coal
C1~C3 Hydrocarbons 10.7
C4 - 400°F 17.2
400 - 650°F
650 - 975°F
975°F + Residual oil
Unreacted ash free coal
H20, NH3, H2S, CO, C02
28.2
18.6
10.0
5.2
15.0
104.9
Hydrogen consumption 4.9 (18,600 scf/ton m.aof„ coal)
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- 12 -
4. EMISSIONS TO ATMOSPHERE
All streams entering or leaving individual units of the plant are
shown in the block flow diagram Figure 2 and described in Table 3. Some of
these streams are returned to other processing units and thus do not leave
the plant directly. Those streams that are specifically discharged to the
environment are indicated by dashed lines in Figure 2 and by asterisks in
Table 3. Environmental aspects of a conversion process are primarily
related to emissions to the.air from the plant, or effluents of liquids
and solids. For discussion purposes this grouping is used and emissions to
the atmosphere are covered in this section of the report.
4.1 Coal Preparation and Feeding
On the block flow diagram in Figure 2 the first emission to the
atmsophere is from the coal storage, handling, and preparation area.
Cleaned coal is delivered by rail or truck and moved to and from storage
using conveyors, stackers, and unloaders. Mechanical conveyors can be a
source of undesirable noise and dust, so suitable precautions should be
taken. Solids handling operations will normally have a dust problem,
and careful consideration and planning is required for control. Covered
conveyors should be provided wherever possible; even so, there may be
vent streams or leaks that could release dust. If needed, a dust collection
system could be used operating at slightly below atmospheric pressure to
collect vent gas and pass it through bag filters.
The coal storage pile is also of concern in that wind can pick
up and disperse fine particles. Evaluation is needed for each specific
situation in order to provide proper control measures. Proposals for
dust control have been made such as spraying oil or asphalt on the surface
of the pile, or covering it with plastic. The amount of coal handled is
so large that a loss of even a small fraction of a percent could be
excessive.
A further consideration on any coal storage pile is the possibility
of fires and spontaneous combustion which would result in evolution of
odors, fumes, and vdlatiles. One control measure is to compact the pile by
layers as it is being formed. In any event, plans and facilities should be
available for extinguishing fires if they occur (18).
It can be expected that there will be spills in the coal preparation
area and that these will create a dust nuisance when they are disturbed by
the wind or by trucks. Again this calls for plans and facilities for cleaning
up dust and for flushing to the storm sewers.
Noise control should be carefully considered since it is often a
serious problem in solids handling and size reduction. If the grinding
equipment is within a building, the process area may be shielded from undue
noise, but additional precautions are needed for personnel inside the
building.
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1
Co
Note;
al Feed
Gasifier
ttt'
39 40 41
46
1
i
Oxygen
Plant
2345
A A A *
1 1 1 1
til1
Preparation Cr
tttt
18 19 20 21
30
A
1
j
Oust
^ separation
42
47 48 49
1 1 1
1 1 \
Sul fur
Plant
— f 14
8 \ 10 11 12 L3 —*.,(.
, ,- t \ t ttf
"
ushed Coal Feeding Slurry
t
22
2
31 32 Hydroge
t t
Sulfur <.h.f.
— *~ Removal ^ ^
Gas and Vapors Gas .^ , ,
faction Cleaning Clean
Oil Slurry Gas
^ T 25 27 |
?6 ^ « ninrrlhii-
tion
33 34 35 36 t t 38
Iff fs,f
ill .1..... '
29 _^
Gas Vacuum Synthetic Crude
Cleanup ^ Distillatio
t t f
43 44 45
50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72
• M ' t11! 1 1 1 1 ! !! it'1 t
| | | i, 1 1 1 L ''nil' ' ' I' •*•••! 1 1
. , . Waste . Makeup
Utility Cooling Water Water 011
Boiler Tower Treating Treating Storage
t tttt tttt tttt |t IT t
73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90
Actual effluents and emissions to environment Fi ur 2
are indicated by heavy dashed lines; other streams — •"
f" Italia ° process' ee a e Effluents and Emissions from H-Coal Liquefaction Plant
(Numbered streams are described in Table 3)
-------
- 14 -
Table 3
Description of Streams for
H-Coal Liquefaction Plant
(see Figure 2 for numbered streams)
Stream
Number
*2
*3
*5
6
8
*9
10
Identification
Coal feed
Wind
Rain
Flue gas
Flow Rate
Tons/Day
33,289
eg 6" in 24 hrs.
5486
Coal dust
Coal to gasifier
Coal fuel
Flash gas
Target 0.65 max.
1940 (dry)
3020 (dry)
Spent catalyst
Sour water
2162
Comments
Illinois No. 6 cleaned coal,
10% moisture. See Table 1 for
details.
Wind action in coal preparation
area may cause dust problem.
Rain runoff from coal storage
area can carry suspended solids
and dissolved materials.
Vent gas from dryer using clean
gas fuel and 10% excess air.
Dust control needed - possible
odor.
Residual dust in dryer vent gas
leaving bag filters.
Supplemental coal needed as raw
material in gasifier to make all
of the hydrogen used in the plant.
Dry coal used as fuel in utility
boiler.
Oil vapor and moisture flashed off
when recycle oil is depressured
and slurried with coal feed.
Should be collected and returned
to system.
Rejected catalyst from liquefaction
containing contaminant deposits
including titania, boron, sulfur,
etc. and possibly major amounts of
molybdenum and cobalt.
Water condensate from cooling gas
and vapors leaving H-Coal reactor.
Will contain wide range of sulfur,
nitrogen, and oxygenated compounds.
-------
- 15 -
Table 3 (Cont'd)
Stream
Number
11
12
Identification
H2S Stream
Flow Rate
Tons/Day
Comments
1142
Recycle gas
*13 Chemical
14 Fuel gas
see Table 11
140
(542 MM Btu/hr)
15 Fuel gas
16 Fuel gas
17 Product gas
18 Wind
19 Rain
20 Fuel gas
21 Air
790
270
1210
eg 6" in 24 hrs,
140
5216
Concentrated H2S stream from
acid gas removal in gas cleanup
sent to sulfur plant. May also
contain some C02 and light
hydrocarbons.
Product gas after removing
liquids and sulfur compounds,
which is recycled to liquefaction
reactor to supply hydrogen.
Estimated H2 content is 56 vol. %.
Volume of gas recycled may be
4-5 times the makeup hydrogen
rate of 420 MM scfd.
Purge stream of chemicals used in
gas cleanup system.
Part of product gas used as fuel
in coal dryer. Estimated com-
position is 56 vol. % hydrogen
and 44 vol. % Ci~C^. High heating
value 900 Btu/c.f. or 24,000
Btu/lb.
Product gas burned in reactor
preheat furnace - see item 14 for
details.
Product gas burned in tail gas
incinerator on Glaus plant -
see item 14 for details.
Net clean gas available for sale
after plant fuel uses. See item
14 for gas characteristics.
Wind action on coal storage and
handling area.
Rain onto coal storage and
handling area.
Fuel gas to coal dryer - see
item 14.
Air for combustion of fuel gas
to coal dryer, including 10Z
excess.
-------
- 16 -
Table 3 (Cont'd)
Stream
Number Identification
Flow Rate
Tons/Day
22 Recycle oil
50,000
23 Hydrogen
24 Recycle gas
25 Heavy oil slurry
1104
26 Recycle oil
27 Light oil
50,€00
28 Chemicals
see Table 11
29 Synthetic Crude
Product
*30 Ash
14,416
2667
31 H-S Stream
3498
Comments
Product oil recycled to form
slurry with coal feed for
pumping to high pressure - based
on 2 Ibs oil/lb coal.
Pure hydrogen makeup to liqui-
faction system.
Clean product gas recycled to
reactor to give desired total
gas flow rate - see Item 12.
Heavy liquid product wthdrawn
as a side stream from liqui-
faction reactor,. Contains ash
and unconverted coal.. Is sent
to vacuum distillation to recover
clean heavy distillate.
Mixture of light oil and heavy
vacuum distillate recycled for
slurrying coal feed..
Oil condensed from gases leaving
liquifaction reactor - part is
recycled (see item 26) and
remainder is included in synthetic
crude product.
Chemical makeup used in gas
cleanup and sulfur removal
(e.g. amine, etc.). May also
include additives and corrosion
inhibitors.
Final clean product oil for sale
or further processing. See Table
2 for inspections.
Ash and slag removed from raw gas
leaving gasifier. May contain
soot. Can be wetted for dust con-
trol.
From sulfur removal following
gasifier. Stream contains 248
tons/day I^S in C02 and goes to
sulfur plant.
-------
- 17 -
Table 3 (Cont'd)
Stream
Number Identification
34
*35
36
37
43
Flow Rate
Tons/Day
*32 Chemicals
see Table 11
*33 CO- vent gas
13,257
Water
Chemicals
6658
see Table 11
Vacuum bottoms
5899
Vacuum distillate
*38 Vent gas
39 Bottoms to gasifier
40 Coal to gasifier
41 Steam to gasifier
42 Oxygen to gasifier
Chemicals
5899
1940 (dry)
2134
4968
see Table 11
Comments
Purge of chemicals as required
to maintain capacity and
activity in sulfur removal
system. May contain amine, etc.
CC>2 removed from hydrogen after
water gas shift. Is discharged
to the atmosphere. Includes
238 tons/day moisture.
Water condensed in gas cleanup
after shift conversion and sent
to waste water system.
Chemical purge from scrubbing to
remove C02 - may contain alkali
carbonate and may go to waste
water treating.
Heavy bottoms oil and particulates
remaining after vacuum distillation
goes to gasification for hydrogen
manufacture. See Figure 1 for
composition.
Clean light oil from vacuum tower.
Part is recycled for slurrying
coal feed and remainder is
included in syncrude product.
Small amount of flash gas removed
by pump used to maintain vacuum
in tower. Can go to sulfur plant
or be incinerated in furnace.
See item 36
See item 6
For gasification - based on 50%
steam conversion.
Supplies all heat requirement
on gasifier.
Makeup chemicals to sulfur
removal system, which must neces-
sarily then show up in effluents
from plant.
-------
- 18 -
Table 3 (Cont'd)
Stream
Number
44
45
Identification
Steam
Chemicals
*46
*47
Nitrogen
Sulfur
*48
Tail gas
Chemicals
*50 Flue gas
*51 Ash
52 Steam
*53 Spent limestone
Flow Rate
Tons/Day
Comments
12,243
see Table 11
16,353
1295
9533
see Table 11
37,451
299
26,136
e.g. 473
54 Cooling water
200,000 gpm
Added to give CO conversion in
shift reactor.
Makeup chemicals for C02 removal
e.g., alkali carbonate. May
also include additives or
activators.
Waste nitrogen from oxygen plant -
vented to atmosphere.
By-product sulfur made from all
collected sulfur streams,
including recycle from tail gas
cleanup.
Final treated vent gas from
sulfur plant after incineration
and tail gas cleanup.
Chemical purge from tail gas
cleanup process. There will also
be spent Glaus catalyst when it
is replaced.
Stack gas from utility boiler
after stack gas cleanup.
From coal used as fuel for steam
production. May be wetted and
used as landfill.
Steam at 1000 psig made for use
in the plant so that it is self-
sufficient in utilities and
electric power.
Used to remove sulfur from
utility furnace flue gas. Exact
form and amount will depend on
operation and excess limestone
used. May be in form of a water
slurry.
Water from cooling tower recir-
culation for use in plant.
-------
- 19 -
Stream
Number Identification
*55 Air
Table 3 (Cont'd)
Flow Rate
Tons/Day
2,655,400
*56 Mist
1200
*57 Slowdown
5100
Comments
Moist air from cooling tower
includes 25,400 tons/day of
evaporation from cooling water
passing through tower.
Drift loss or spray carried out
with air. Will contain dis-
solved solids which may cause
deposits in nearby areas.
Water purged from cooling water
circuit to control dissolved
solids. May contain additives
such as chromates9 chlorine,
etc.
58 Treated water
8820
59
*60
61
Ammonia
Phenols
205
62
Oil
*63
Sludge
e.g. 100
Treated waste water reused in
plant as makeup to cooling
water. Must be sufficiently
clean so that residual con-
taminants do not give excessive
pollution of air flowing through
cooling tower.
H2S in sour water to waste water
treating is removed in sour
water stripper and sent to Glaus
plant.
NH3 in sour water is recovered
by stripping and purified for
sale as a byproduct.
Small amount of phenols may be
recovered by solvent extraction
and/or destroyed in biological
oxidation system.
Traces of oil in sour water are
removed in API type oil separator
and returned to process or incin-
erated .
Cellular material generated when
contaminants are converted in
biological oxidation. Some is
recycled in biox unit and the net
sludge product may be incinerated
or possibly used as landfill.
-------
- 20 -
Table 3 (Cont'd)
Stream
Number
*64
Identification
Trace Elements
Flow Rate
Tons/Day
see Table 6
*65 Chemicals
see Table 11
*66 Evaporation
67 Makeup water
68 Boiler feed water
*69 Sludge
*70 Backwash
20,720
16,960
e.g. 50
71
Oil
14,416
*72
Vapors
73
74
Air
stream
21,321
4640
75
Fuel gas
140
Comments
Considerable amounts of trace
elements may be volatile and
separation and/or deactivation
operations may be needed - see
discussion in Section 8.
Various chemicals may be used
in treating waste water and
consequently show up in plant
effluents.
Ponds and settlers can lead to
evaporation and odor problems.
Net fresh makeup water needed
for cooling water system.
Makeup to boiler feed water
supply after crediting recover-
able condensate.
From treating to cleanup water
makeup to plant - e.g. lime
precipitation.
Acid and caustic used to
regenerate ion exchange resins
in deminerlization to prepare
boiler feed water can be com-
bined, neutralized, and sent
to waste water treating.
Syncrude product to sale or use.
May have intended losses associat
with oil storage and handling dui
to leaks or spills.
Incidental vapor release or flasl
ing associated with oil storage
and handling could cause odor
problems.
Air used in oxygen plant to make
pure oxygen for gasifier.
Gas stream containing 1390 tons/
day H2S in C02, recovered from
gas cleanup systems on liquefact
and on gasifier.
Part of clean product gas is use
in incinerator for tail gas clea
up on Glaus plant.
-------
- 21 -
Table 3 (Cont'd)
Stream
Number Identification
Flow Rate
Tons/Day
Comments
76 Air
77 Chemicals
78 Coal fuel
79 Air
80 Boiler feed water
81 Limestone
82 Cooling water
83 Makeup water
84 Air
85 Chemicals
86 Waste water
6048
see Table 11
3020 (dry)
34,700
26,136
473
200,000 gpm
31,700
2,630,000
see Table 11
8820
Total combustion air for sulfur
plant including tail gas incin-
eration. See items 74 & 75.
Chemicals used in tail gas
cleanup system.
Coal fired to furnace generating
steam needed in plant. Part of
the high sulfur coal feed is
used, after drying.
Air for combustion of coal fired
to utility boiler, see item 77.
Includes 10% excess air.
Used to make steam in utility
boiler. See item 51, Table 8,
and Table 10.
Used for stack gas cleanup, for
example in a throwaway process.
This is theoretical amount and
actual use may be higher.
Cooling water returned from
process to be cooled for reuse.
Total makeup water to balance
blowdown, evaporations, and drift
loss in cooling tower. Supplied
from waste water treating (8820
tons/day) boiler blowdown
(2160), and fresh water makeup
(20,720).
Air flow into cooling tower.
Additives and chemicals used in
cooling water system, for example
to control corrosion, fouling, or
foaming.
Sour water etc. sent to waste
water treating. See items 10 and
34.
-------
- 22 -
Table 3 (Cont'd)
Stream Flow Rate
Number Identification Tons/Day Comments
87 Chemicals see Table 11 Chemicals, additives, etc. used
in treating waste water require
consideration of possible
associated disposal problems.
88 Water 37,680 Plant makeup water to be treated
for use in cooling water system,
and as boiler feed water.
89 Chemicals see Table 11 Used for water treating. See
comments on item 87„
9Q 0±1 14,416 Synthetic crude product to
: storage and handling. Vapors
may flash off on depressuring
and should be collected for
return to process.
Streams indicated by asterisk are actually emitted directly to the environment,
Other streams are returned to the process.
-------
- 23 -
Coal is next fed to a dryer where essentially all moisture is
removed by contacting the coal with hot flue gas. To avoid releasing
volatiles, temperature of coal particles at any point in the operation should
not exceed 500°F. Therefore the hot combustion gases are tempered to about
1000°F by recycling cooler stack gas before being mixed with coal. Fuel
efficiency is maximized by designing the heater for minimum excess air
(e.g., 10%). While this increases the moisture content of the dryer offgas
to perhaps 50% and tends to make the drying operation slightly more dif-
ficult, it is justified by the saving in fuel and the decreased volume of
offgas to be cleaned up. In order to compensate for high moisture in the
drying gas, the coal could be heated to a somewhat higher temperature, for
example 210°F instead of 200°F, so as to dry to the same moisture content.
In view of high fuel costs, design of drying facilities should be
reoptimized, as discussed more fully in a previous study (4). In general,
it will be desirable to maximize the preheat temperature on the coal feed,
and to preserve this sensible heat so as to reduce heat load on the
reactor. Preheat temperatures as high as 500°F have been used without
substantial evolution of volatile matter from coal but limitations such as
handling and slurry pumping must also be considered.
Dust control is needed on the dryer vent gas. One conventional
approach uses bag filters, with proper precautions to avoid condensation
of moisture. Alternatives to consider are wet scrubbing and electrostatic
precipitation. Recovered fines can be disposed of by including them in the
coal slurry fed to the hydroliquefaction reactor, or the fines could be
included in the coal fuel sent to the utility boiler.
Coal feed rate to the dryer is so large that a loss of only a
fraction of one percent could be excessive. Thus a loss of 0.01% on coal
feed would correspond to about 3 tons/day of dust in the dryer vent gas,
which would result in a very noticeable dark plume. Therefore a very
efficient and reliable dust control system is needed for this service.
Clean gas fuel is fired to provide heat for coal drying in this
study case, since clean gas is available as a by-product. Cleanup of the
dryer vent gas is thereby simplified in that sulfur removal is not needed,
and bag filters should be suitable for dust control. Other fuels could be
used such as coal, product oil, or some of the vacuum bottoms, although
sulfur removal from the vent gas may then be needed, at least when using
high sulfur coal as fuel. Fuel fired to the dryer is 542 tffij Btu/hr based
on removing a nominal 10 wt. % of moisture.
The dried coal is crushed through 40 mesh and sent to slurry
preparation for feeding to the liquefaction system. Some dried coal also
goes to gasification and to the utility boiler.
In slurry preparation the coal is mixed with recycle oil so that
it can be handled and pumped to high pressure. Since the coal may contain
some residual moisture, at least at times, it can be expected that steam
or vapors may flash off when the coal is heated by mixing with recycle oil.
Provision should be included to contain and collect any such vaporss so
that they can be recovered or returned to the system and not allowed to
become an effluent from the plant.
-------
- 24 -
4.2 Liquefaction Section
Slurry fed to the liquefaction section at high pressure is heated
to the proper temperature in a preheat furnace. Part of the clean product
gas is used as fuel on the preheat furnace (1580 MM Btu/hr) so that stack
gas cleanup to remove sulfur or particulates is not needed.
However, emissions of NOx must also be defined and controlled in
any specific application of the process. The amount will depend on the fur-
nace design, use of staged combustion, fuel nitrogen content, etc. In
general, NOx production can be decreased by designing for a lower flame
temperature and by using low excess air (19). Processes are being developed
to remove NOx from flue gas, and a satisfactory process will probably be
available soon. These comments are also applicable to stack emissions from
the coal dryer and the utility furnace.
Since the preheat furnace operates on a high pressure slurry, there
is a possibility of tube failure which could result in serious emissions to
the atmosphere, so consideration should be given to suitable monitoring and
control techniques.
On the hydroliquefaction reactor there are no specific effluents
or emissions that are intentionally released to the environment. However,
this high pressure system is again subject to leaks or failures that call
for very careful and thorough planning. Leaks of gases and vapors could
cause objectionable odors from sulfur, phenols, etc. Spills of liquid
could also cause a nuisance and might be handled by having a separate
"oily water" sewer system with appropriate cleanup facilities.
4.3 Gas Separation and Cleanup
Gases and vapors withdrawn from the top of the reactor go to
a cooling and recovery system. They are first cooled in exchangers to
recover a maximum of useful heat. Oil vapors are thereby condensed and
recovered before condensing water which might cause emulsion problems.
Recovered oil is separated and withdrawn as product, or recycled for making
a slurry with the coal feed to liquefaction. The gas cleanup system is
enclosed, with no normal emissions to the environment except that liquids
condensed at high pressure will be saturated with light gases which can
flash off when the liquid is depressured. Therefore provision is needed
to separate such flash gases and return them to the process, or to a
furnace for incineration. Similar considerations are needed on handling
all high pressure liquid streams in the plant.
Final cooling of gases from the reactor gives condensation of
a large volume of sour water, which is sent to waste water treating for
cleanup. This sour water will contain considerable ammonia, plus
phenols, light oil, and possibly suspended solids.
-------
- 25 -
The remaining cooled gas goes to acid gas removal where sulfur
compounds, particularly H2S, are removed and sent to the sulfur plant for
recovery. Some carbon oxides may be present in the gas but the amounts
are small, and for this study have not been removed since fuel uses of the
gas would not be affected. Unlike coal gasification, hydroliquefaction
does not generate a large C02 stream at this point to be vented to the
atmosphere. Instead, a large amount of C02 is vented from the system used
to manufacture hydrogen. In the liquefaction route, combined oxygen in
the coal feed is primarily reacted with hydrogen rather than combining
with carbon, and thus appears in the sour water.
In general, the reactor section of the plant is completely
enclosed and no streams are normally discharged to the atmosphere. However,
the reactor operates at 2,000 psig, so that any leaks on valves or other
equipment can result in serious pollution problems. For example, the air-
fin coolers used on the gas and liquid products have fans to move a very
large volume of air over the exchangers, and it is apparent that any leakage
will be dispersed in this large air stream. Further consideration of this
problem is needed to assure that the plant operations will be environmentally
satisfactory (20).
Indirect heat exchange versus recirculated cooling water is also
used in the high pressure reaction section as well as in other parts of
the plant. It is common to find a small amount of leakage on conventional
exchangers in this type of service, particularly at high pressures such as
2000 psig. Materials that leak into the cooling water can circulate to
the cooling tower where they will be stripped out by the large volume of
air passing through the tower. Special attention to this problem has been
given in the case of oil refineries and this experience should be reviewed
and applied in coal conversion operations (20,21).
Startup and shutdown of the plant, as well as maintenance,
depressuring, and purging of equipment all call for special attention to
control emissions. A special collection system should be used to contain
and cleanup all purge and vent gas streams.
4.4 Liquid Product Recovery
As mentioned in the preceding section, some light oil is recovered
from the gases leaving the reactor and is withdrawn as part of the product
oil The heavier portion of product oil leaves as a sidestream from the
liquefaction reactor, and contains particulates such as ash and coal which
must be removed in order to have a clean product. In this design vacuum
distillation is used to make the necessary separation. Oil which Is
distilled overhead is clean. Part of it is recycled to use in making a
slurry with the coal feed, the rest of the vacuum distillate is combined
with the light oil to give the total syncrude product. Syncrude product
is quite low in sulfur, 0.19 wt. %, but the nitrogen content of 0.68 wt. %
is high relative to petroleum stocks. The high nitrogen content would tend
to increase NOX production if the product use involves combustion, while if
it is subsequently refined the high nitrogen tends to interfere in catalytic
operations.
-------
- 26 -
Heat for distillation is supplied by sensible heat in the oil
coming from the liquefaction reactor; consequently, no furnace is used with
its attendant emissions to the atmosphere. The stream removed from the
bottom of the vacuum tower contains the heaviest portions of liquid together
with particulates, and is sent to hydrogen manufacture where it is gasified.
A major environmental concern on the vacuum distillation operation
is the system used to maintain a vacuum in the tower. One conventional
system is to use an overhead condenser operating at low enough temperature
so that the vapor pressure of the distillate at the existing overhead tem-
perature corresponds to the desired vacuum. With the heavy oil that is
distilled in this design, temperature in the overhead condenser may then
be roughly 100-150°F. Heat of condensation can be removed by indirect
exchange to cooling water or by air cooling. Potential leaks in exchangers
must be considered. In contrast to most services, the cooling water or air
is now the higher pressure stream, so that any leakage will be inward into
the process stream. In the case of water cooling the water leakage will
mix with the oil and tend to emulsify, posing a difficult separation problem.
In the case of air cooling, any air that leaks into the process stream must
be removed by means of a vacuum pump which discharges at atmospheric pressure
or higher. This waste gas may contain oil, sulfur, odors, etc., such that it
should not be discharged directly to the environment.
A suitable way to dispose of the waste gases is by incineration,
for example in the sulfur plant or in one of the plant furnaces. Even with-
out considering exchanger leaks as a source of permanent gases that have to
be rejected by the vacuum pump, there will be other sources of gases such
that a typical design of any vacuum tower includes a vacuum pump downstream
of the overhead condenser.
One type of vacuum pump that may be used is the ordinary mechanical
design. An alternative type that is often more economical uses a steam jet
ejector rather than the mechanical design. With the ejector, steam is
injected at high velocity through a venturi throat which develops a low
pressure zone to inspirate waste gases from the system. This is followed
by &® ssrodynamic pressure recovery zone where the mixture of gases and
steam is returned to atmospheric pressure for disposal. The steam can
easily be condensed, but due to the direct contact with waste gases may be
contaminated with oil, sulfur compounds, etc. This sour condensate can be
included with the sour water going to waste water treating. As mentioned,
the non-condensible gases can be disposed of by incineration.
4.5 Hydrogen Manufacture
Synthesis gas for use in making hydrogen is generated in a slag-
ging gasifier where slurry bottoms from the vacuum tower plus supplemental
coal are reacted with steam and oxygen. The system operates at high pres-
sure but is entirely closed so that nonaally there will not be emissions
to the environment. The raw gas is cooled in a waste heat boiler to make
steam, followed by a water scrubbing tower to remove particulates such as
-------
- 27 -
ash and soot. The water will be severely contaminated with a mixture of
ammonia, phenols, sulfur compounds, etc. Up to this point in the hydrogen
manufacture section, the major effluent is sour water containing residual
ash and soot. In handling and disposing of these materials, emissions to
the atmosphere should be avoided. The residual ash and soot might be
separated from the sour water slurry by means of a settling pond or filter,
to give wet ash that may be disposed of as landfill or to a mine. If
allowed to dry out, ash dusting could be a problem, for example as a result
of leaks or spills in the ash handling system.
Odor control may be needed on the ash and sour water streams;
consequently, background information on it should also be collected during
pilot unit operations. Ammonia, sulfur compounds, and phenols may all be
troublesome. Facilities in a large scale plant may have to be enclosed or
covered to control odors, particularly in the case of sour water. Collected
vent gas can then go to suitable disposal, such as the sulfur plant or an
incinerator.
In the shift converter carbon monoxide in the scrubbed gas reacts
with steam to make hydrogen, plus carbon dioxide which must be removed
subsequently. A fixed bed of catalyst is used and the operation is relatively
clean, although the catalyst must eventually be replaced and preferably is
returned to a manufacturer for reworking or refining.
After shifting, carbon dioxide is removed from the hydrogen
stream using hot carbonate scrubbing for example. The C02 vent stream is
very large, 13 257 tons/day, or roughly half as much as the total weight
of coal fed to the plant. By careful design it should be possible to assure
that this C02 stream will be essentially free of objectionable contaminants
such as H2S and COS, or combustibles. The sulfur removal system ahead of
shifting should be able to give efficient sulfur cleanup, together with
protection furnished by the iron based shift catalyst. Combustibles in
the raw /gas should be minor due to the high gasification temperature com-
pared to some plants for making synthetic natural gas where contaminants in
the C02 vent stream present a serious problem.
A discussion of various approaches to gas cleanup after gasification
is Riven in reference 5, including comments on proposals for techniques to
remove sulfur at high temperature so as to avoid cooling the gas more than once.
In general, scrubbing systems used to remove sulfur compounds or
CO? will require a certain amount of chemicals makeup due to unavoidable
losses, or due to side reactions that consume chemicals and require purging
to maintain capacity and selectivity of the scrubbing solution (22). This
results in a net effluent of chemicals from the system, .and generally to
the environment, which requires plans for their proper disposal. In ^ the
case of araine purge, incineration may be acceptable in that the chemical
is combustible. In the case of carbonate scrubbers, the potassium carbonate
cannot be destroyed by burning so some other disposal must be defined.
Being water soluble, burial on land may be questionable. Ocean disposal
is a possibility. Additives such as metallic complexes or inorganic salts
(arsenic, vanadium, etc.) are sometimes used in scrubbing systems for acid
gas removal, requiring special consideration of techniques for acceptable
disposal of any chemical purges.
-------
- 28 -
4.6 Auxiliary Facilities
In order to have a comprehensive and meaningful evaluation of
environmental aspects of a coal conversion process, it is essential to
base it on a complete plant including all related and associated facilities
needed for the operation. Process fuel and utilities such as electric power
should be integrated into the study, allowing for the associated increase
in coal raw material consumption. The same applies to the oxygen plant,
sulfur plant, and water treating facilities.
On the oxygen plant the major effluent is waste nitrogen. It
should be a clean stream and can be vented to the air in a safe manner
well away from structures that might be used by workers.
The sulfur plant is a potential source of considerable obnoxious
emissions. An effective and reliable tail gas cleanup system is needed on
the Glaus plant to assure acceptably low sulfur emission. A number of
processes are offered for this service and extensive commercial experience
is available to draw on (23). In some of these the tail gas is first
treated to reduce all sulfur compounds to H2S which is then scrubbed out
with conventional systems such as amine. In others, the sulfur compounds
are first oxidized to SC>2 which is then removed by one of the techniques
used for stack gas cleanup. This type of tail gas cleanup is used in the
present study. Either type of process can be used to remove total sulfur
in the tail gas down to a level of 250-500 ppm, corresponding to an overall
sulfur separation exceeding 99% for the sulfur plant. The recovered H2S or
S02 is then returned to the Glaus plant.
Effectiveness of a Glaus plant is very sensitive to feed gas
composition, especially the % H2S in the feed (11) .. Processes to separate
H2S generally also separate out C02 at the same time, diluting the H2S
stream going to the sulfur plant. The dilution can greatly increase the
volume of tail gas, requiring a correspondingly lower concentration of
sulfur in the tail gas to hold a given tons/day of sulfur emissions. For
example, with 25 vol. % t^S in the gas fed to a Glaus plant, tail gas volume
is two times that for the same amount of H2S at 100% concentration. At 15%
H2S the ratio is three times. The latter is more representative of a Glaus
plant feed stream in gasification designs using partial oxidation to make
synthetic natural gas, where C02 in the raw gas is high relative to the
H2S content. In the present H-Coal study„ feed to the Glaus plant contains
35.6 vol. % H2S with the remainder being C02- This favorable concentration
is obtained because over 80% of the l^S comes from gas cleanup in the
liquefaction section where the H2S is not diluted, since there is no
substantial amount of C02 present in the gas being processed for sulfur
removal.
Chemicals are used for scrubbing in the tail gas cleanup operation,
leading to a chemical emission or effluent that must be recognized and
evaluated for any specific case. Consumption of chemicals may either reflect
physical losses such as amine vapors in the final tail gas, or the chemicals
consumption may be caused by side reactions that require a purge stream in
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order to maintain activity and capacity of the scrubbing solution. Thus,
when scrubbing out S02 with sodium sulfite, some oxidation to sodium sulfate
occurs. Buildup of the latter may be controlled by simply purging part of
the solution, although disposal of such chemicals presents problems.
Satisfactory methods need to be defined for taking care of all such chemical
wastes.
The utilities section includes a boiler to provide steam and
electric power. It has a large gas effluent, so that emissions of dust,
sulfur, NOX and CO must be controlled. The large fuel consumption of the
boiler (3020 tons/day of coal) has a correspondingly large effect on thermal
efficiency of the overall plant.
High sulfur coal is fired to the boiler equivalent to 7.6 Ib
S02/MM Btu versus the present Federal standard of 1.2 for large stationary
boilers, requiring a sulfur removal of at least 84% on the stack gas. In
addition fly ash will have to be removed to control dust emission, and 99%
removal is needed to meet the present Federal standard of 0.1 Ib particulates
per MM Btu. Release of flue gases from the utility boiler is the largest
gas stream that is processed and released to the atmosphere from the plant;
therefore, it is particularly important to assure that emissions are controlled
adequately, including transients such as at startup, etc.
Dust emission from furnaces can be controlled with demonstrated
conventional equipment such as cyclones, electrostatic precipitators, or
scrubbers. Sulfur can be removed as required, by one of the many processes
offered for this use (24,25,26). Processes are available from the following:
Wellman-Lord
Chemico
Combustion Engineering
Universal Oil Products
Research Cottrell
Chiyoda
Showa Denko
Babcock & Wilcox
Lurgi
Enviro Chem. Systems
FMC Corp.
Mitsui S.P. Inc.
Davy Power Gas
Stauffer Chemical Co.
Some of these are commercially demonstrated and others are undergoing large
scale tests.
Emission of NOX must also be defined and controlled in any specific
application of the process. The actual NOX formation will depend on the
particular furnace design as well as the nitrogen content of the fuel fired
(19,32). In general, NOX formation can be decreased by designing for a low
flame temperature and low excess air, staged combustion, and by using a fuel
of low nitrogen content (19).
Although NOX may be decreased by the above, It may still be
difficult in some cases to meet the target emissions set for large stationary
boilers. Considerable work is under way on methods to remove NOx from the
flue gas. While N02 is relatively easy to scrub out, it is found that most
of the NOX is in the form of NO which is very difficult to remove due to its
low solubility in water. One answer is to convert NO to N02 which can then
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be scrubbed out, but a simple efficient way to accomplish this is not yet
available. Other approaches are to effect chemical reactions with NOX
to decompose it to free nitrogen gas. The problem is receiving intensive
effort and it is expected that at least one demonstrated process will be
available in the near future for use on utility boilers.
The largest volume of gas discharge to the atmosphere from the
utility area is on the cooling tower. Air flow through it is about 69,000
MM cfdj and the cooling tower is therefore critical from the standpoint
of pollutants. It might be expected that the recirculated cooling water
would be perfectly clean and free of contaminants, however, experience shows
that there will be appreciable leakage in exchangers and occasionally tube
failures, especially with high pressure operations. In the present design
cooling water is exchanged with oil, sour water, raw gas, amines, etc.;
therefore, contaminants may get into the circulating cooling water and then
be transferred to the air in the cooling tower, which necessarily provides
effective contacting and stripping.
In oil refining and petrochemical operations, the cooling tower
is often a major source of emissions from the plant, and techniques have
been developed for making quantitative estimates of the loss (20). Control
measures are also described, with emphasis on good maintenance on valves,
pump seals, etc., plus floating roof tanks or vapor recovery as needed on
oil and chemical storage tanks. In critical cases monitoring instruments
can be provided to detect leaks.
Cooling towers also have a potential problem due to drift loss,
that is mist or spray which is carried out with the air leaving the tower.
Since this mist contains dissolved solids it can result in deposits when
the mist settles and evaporates. Drift loss due to mist carried out with
the air amounts to an estimated 1200 tons/day. New designs are being
offered to reduce drift loss from cooling towers (27).
Careful consideration should also be given to the potential
plume or fog problem associated with cooling towers that results from
condensation under unfavorable atmospheric conditions. Condensation can
occur whenever moist air leaving the cooling tower mixes with ambient air
to give a mix temperature which is below that corresponding to saturation.
The resulting plume can be a problem, for example, if it affects public
roads. Icing of roads in the winter should also be considered. One way
to prevent the plume is to provide reheat on the air leaving the cooling
tower, but this results in a very large heat load and may not normally be
warranted unless it can be accomplished using low level waste heat. It
may be that the problems can be taken care of by proper design of the
cooling tower, and by locating it in the plot plan so as to minimize
Impact on roads or public areas.
Waste water treating is an important area for air pollution
control. Many of the contaminants in the streams to waste water treating
have very strong odors so effective control measures need to be incorporated
into the plant. Sour water stripping and phenol extraction are carried
out in enclosed systems and should not normally have emissions. However,
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it is common to use open tanks for oil separation, biological oxidation, and
settling ponds which can give undesirable odors or evaporation. Careful
consideration of the problem is needed and covered systems provided where
appropriate.
One final consideration is the storage of oil, chemicals, sulfur,
and other materials. Vapor losses can be quite significant, especially
with volatile materials, due to filling and emptying tanks, or breathing
due to temperature changes. Control procedures have been developed in
related industries (20) and should be applied in coal conversion operations.
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5. EFFLUENTS - LIQUIDS AND SOLIDS
In this part of the discussion, attention will be focused on
environmental concerns related to liquid or solid streams in the plant.
As in the preceding section on gas emissions, these streams are identified
in Figure 2 and defined in Table 3. The order of discussion follows the
processing sequence used previously.
5.1 Coal Preparation and feeding
As mentioned earlier, the present study is based on receiving
cleaned coal; consequently, the problems associated with disposing of a
large amount of refuse from coal cleaning apply to some other location,
together with the need for cleaning up water for reuse. Careful attention
should be given to environmental aspects of coal storage and handling.
Rain runoff from this area is of particular concern. Of the rain that
falls onto the storage pile, some of it will run off quickly and carry
suspended solids, while the remainder will soak into the pile where it
will have a long contact time and can extract acids, metals, organics, etc.
One approach is to collect run off water from this area in a separate
sewer system and storm pond. After suitable treatment it can then provide
a valuable supplement to plant makeup water.
Solids recovered in the dust collection facilities on the coal
dryer can be included in feed to liquefaction or in the coal fired to the
utility furnace,, If coal fuel were used on the dryer instead of gas, it
would contribute a residue of ash which would have to be taken into con-
sideration in disposing of the recovered dust.
In slurry preparation the coal feed is mixed with hot recycle oil
at about atmospheric pressure and perhaps 200-400°F, possibly causing some
oil or moisture to flash overhead. Provision for condensing such vapors
can be included9 and the condensed liquid sent to the hydroliquefaction
reactor or to water cleanup as appropriate.
5.2 Liquefaction Section
After pumping to high pressure, the slurry of coal feed is pre-
heated in a furnace and fed to the hydrogenation reactor. There are no
intentional effluents of liquids or solids from this section, although
leaks and spills can be expected. Provision for containing these and
cleaning^ them should be part of the planning for pollution control and
housekeeping on the plant.
Maintenance and cleaning of the reactor section will require
specific procedures and facilities. The reactor will contain several tons
of oil slurry9 which must be removed when the plant is shut down.
Suspended solids will be present, as well as catalyst particles. One
possibility is to store the materials removed from the reactor in suitable
tanks for reuse or proper ultimate disposal. The oil is probably similar
to other coal tar materials which are known to be carcinogenic, so this
aspect should be evaluated and precautions taken as needed. It may be
desirable to flush out the system with a neutral wash oil before opening
up equipment for maintenance, although this would add to complexity.
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During hydroliquefaction, some of the minor or trace elements in
the coal deposit on the catalyst. Eventually, the catalyst must be
regenerated or reworked. Contents of some elements in spent catalysts are
summarized below (12):
Carbon wt. % 16.4 Ti02 wt. % 3.0
Sulfur wt. % 4.5 Boron wt. % 0.8
Vanadium wt. % 0.1 Calcium wt. % 0.5
Nickel wt. % 0.1 Iron wt. % 0.5
The above values were reported for Illinois coal and may be different for
other coals. Although the high levels of titanium and boron in the spent
catalyst may be surprising, these elements are often present in the coal
feed in relatively high concentration and could be deposited on the catalyst.
By way of illustration, if the catalyst replacement rate corresponds to
1 pound of catalyst per 1000 pounds of coal feed and 10 ppm of a trace
element is transferred from the coal to the catalyst, then the amount
deposited will give 1.0 wt. % on spent catalyst. For this illustration,
catalyst makeup rate would be 25 tons/day in the plant size of Figure 1.
It is clear that specific plans are needed to handle and dispose
of spent catalyst. One possibility is to return it to a manufacturer for
reworking and metals recovery. If it is to be stored or buried, the extent
of leaching should be defined and adequately controlled.
Obviously all materials that enter the plant, including trace
elements in the coal feed must leave at some point and be disposed of in a
satisfactory manner. The subject is discussed further in Section 8 on
trace elements. Since much of the product oil is recycled, any trace elements
collected in it will tend to build up and accumulate In this stream and may
cause problems, as discussed in reference 6.
5.3 Gas Separation and Cleanup
Oil is first condensed from the gas and vapor stream leaving the
reactor, at a temperature above the water dew point so as to avoid possible
emulsions. This oil may contain some suspended solids or certain trace
elements so pertinent information should be obtained during pilot plant
operations. Environmental aspects of oil products will be discussed In
Section 5.4 of this report.
After removing oil, moisture is condensed by further cooling,the
gas, giving a sour water stream which is sent to waste water treating. It
will contain H2S, ammonia, phenols, etc. absorbed from the gas phase.
Sour water is the major liquid stream from gas separation and
cleanup. It is sent to waste water treating where contaminants are removed
so that it can be reused as makeup to the cooling water circuit. The sour
water will contain a wide range of contaminants including compounds of
sulfur, nitrogen, or oxygen, as well as some oil and possibly solids. In
addition there may be certain trace elements that could be partially
vaporized in the liquefaction reactor and carried out with the gas. It can
be expected that HC1 and HF will tend to form from chlorides and fluorides
in the coal feed when they are expooed to the high hydrogen presQUSQ in
the reactor, although there can also be reactions with ssss^oni&9 etc-
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Cleanup of the sour water may require solvent extraction to remove
phenols if these are present in large amounts. The phenols may then be
withdrawn as a byproduct if an outlet is available, or possibly they could
be recycled through hydrogenation to destroy them. Sour water stripping
will remove most of the ammonia and H2S. Ammonia may be recovered separately
as a byproducts while the H2S should be sent to the sulfur plant.
The final step in gas cleanup is sulfur removal. This provides
a clean stream of product gas that is low enough in sulfur so that it can
be burned without requiring control of sulfur emission. The main effluent
is a sulfur containing gas 'stream that is sent to a Glaus plant for sulfur
recovery. Concentration of H2S separated in acid gas removal. In general,
scrubbing for acid gas removal will require some makeup of chemicals which
must showup as a corresponding effluent. Typically, this is a chemical
purge stream, which in the case of amine scrubbing might be disposed of by
incineration. An alternative to consider might be to send it to waste water
treating.
The tendency of high pressure liquid streams to release gas on
depressuring has been mentioned. All such flash gases should be collected
and returned to some point in the process, or cleaned up before discharging.
5.4 Liquid Product Recovery
Syncrude product from the process comes from two process streams.
A light portion of liquid product is recovered from the gas stream leaving
the hydroliquefaction reactor, while a heavy portion is the overhead from
vacuum distillation of the liquid sidestream leaving the reactor. The
combined oil is syncrude product which can be further processed as desired,
for example, to make motor gasoline. Based on information from other
processes it appears quite likely that syncrude from the H-Coal process
may contain very significant amounts of some trace elements. Thus, heavy
product from the SRC coal liquefaction process has shown over 200 ppm of
titanium (11), while some by-product oils from Lurgi type gasifiers are
reported to contain 30-50 ppm of arsenic or lead. To the extent that such
metals are contained in the H-Coal product, they may have to be recovered
and disposed of in subsequent use of the product. If catalytic processing.
is used, the metals' may deposit on the catalyst and may deactivate it.
Further information on metals content of the H-Coal product is needed to
clarify the situation. Solids content of the oil product is presumably very
low, but should be measured.
A distinctive characteristic of oil from coal is its high nitrogen
content compared to petroleum oils. Such nitrogen is known to increase NOX
formation on those fractions of the oil which find their way into fuel uses.
If the oil goes to further processing, there may also be an adverse effect
in that nitrogen compounds are known poisons for many catalysts. It might
be thought that adsorption could be used to separate the oil molecules con-
taining nitrogen so that they could be rejected. However, a large fraction
of the oil would then be rejected. In general the nitrogen is mainly in
molecules of over 300 molecular weight. If each molecule contains one
nitrogen atom, its total weight will be about 20 times its nitrogen content,
and there is 0.68 wt. % nitrogen in the syncrude product.
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- 35 -
In looking at other aspects of liquid product recovery, bottoms
from the vacuum tower are fed to gasification and should not contribute
any new effluents in normal operation. Plant shutdown and upsets need to
be considered, and it may be necessary to provide oil tanks for storing
the inventory during shutdown, and for emergency use.
All storage tanks should be adequately protected to control emis-
sions, such as vapor loss during filling, or breathing losses due to tem-
perature changes. For oil storage, consideration can be given to floating
roof tanks or completely enclosed tanks with a vapor collection system.
5.5 Hydrogen Manufacture
In hydrogen manufacture bottoms from the vacuum tower plus sup-
plemental coal are gasified with steam and oxygen as described earlier.
Raw gas is cooled and scrubbed, giving a sour water effluent which is sent
to waste water treating. It contains compounds of sulfur, nitrogen, and
oxygen which must be removed so that the water can be reused. Treatment of
waste water will be discussed further in Section 5.6 on auxiliary facilities.
Ash remaining after gasification is collected with the sour water
and has to be separated out so that it can be disposed of by burying or
returning it to the mine, for example. Potential dusting and odor problems
have been mentioned, but there is also a possibility of leaching contaminants
from the ash by rain or ground water. Pertinent leaching information should
be obtained regarding sulfur, calcium, and magnesium compounds, as well as
on trace elements.
Experience shows that soot is formed in this type of gasification
(17), resulting in complications in the cleanup and disposal operations.
Soot production, which may be several percent on feed, is normally separated
out from the water slurry and recycled to gasification but the presence of
coal ash may interfere with this operation. Recycling to the gasifier is
an effective way to dispose of soot, while improving thermal efficiency.
Moreover, it may avoid potential disposal problems that could arise if the
ash were contaminated with soot. This is an area for further study and
evaluation in the various related experimental programs to define satisfactory
handling and disposal methods.
It is known that many trace elements present in the coal feed are
partially volatile at operating conditions used in the gasifier (28), and that
considerable amounts can accumulate in the gas cleanup system - particularly
in the sour water stream (29). These include many toxic elements such as
arsenic, lead, cadmium, selenium, fluorine, etc. Their presence will com-
plicate the cleanup and disposal of the sour water stream. The subject of
trace elements involves special environmental problems, and is discussed in
greater depth in Section 8 of this report.
After scrubbing to remove particulates, sulfur compounds are
removed from the gas to prepare a clean gas for subsequent shifting. The
concentrated sulfur stream goes to sulfur recovery. No major liquid or
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effluents leave this unit; however, a chemical such as amine is used to
scrub out sulfur compounds and normally requires a purge of chemical solution
to maintain the desired capacity or activity. Provision must be made to
dispose of such chemicals, possibly by incineration as mentioned in Section
5.3.
Shift conversion is the next operation, using a fixed bed of
catalyst that may be of the iron type. Eventually the catalyst will need
to be replaced. The spent catalyst could be returned to a manufacturer
for recovery, but if it is disposed of by burying then information should
be obtained to assure that secondary pollution will not be excessive due to
leaching, etc.
The final cleanup of product hydrogen is by cooling to condense
unconverted steam, followed by scrubbing with alkali carbonate to remove
C02- The condensed water is relatively clean and can be used for boiler
feed water makeup. As in other chemical scrubbing systems, a purge of
the scrubbing solution is usually needed to prevent excessive buildup of
inert or undesirable compounds resulting from side reactions or contaminants.
While it might be included in the water sent to waste water treating, it
would then contribute dissolved solids to the system and actually cause an
increase in water consumption. A better alternative may be to return it to
a chemical processer for reworking or use, possibly after evaporation to a
concentrated paste. ,
5.6 Auxiliary Facilities ,
On the oxygen plant the only liquid effluent is a small amount of
clean water condensed from the air, which can be used as boiler feed water
makeup. On the sulfur plant the main output is byproduct sulfur which is
suitable for sale. Fixed beds of catalyst are used in the Claus plant,
and when replaced, can be returned to a manufacturer for disposal. Tail
gas cleanup again involves scrubbing with chemicals resulting in a purge
stream of chemicals that requires specific plans for disposal depending
upon its exact nature.
The utility boiler burns high sulfur coal, with stack gas cleanup
to control sulfur and dust emissions. Various processes are available and
the form and amount of recovered sulfur compound or waste to dispose of
will vary depending upon which process is selected (30,31,32,33). In one
process, S02 in the flue gas is catalytically oxidized to S03 which is then
absorbed in sulfuric acid and recovered as a byproduct from flue gas cleanup.
Another process reacts S02 with oxygen in an aqueous solution of iron sulfate
to form sulfuric acid, which is then neutralized with lime to form gypsum for
recovery as a valuable byproduct.
For the purpose of the present study stbichiometric limestone is
included for stack gas scrubbing, and could be used in a "throwaway" system,
for a lime scrubber, or in a system making gypsum byproduct. The amount of
limestone is 473 tpd on the above basis and introduces a considerable
handling and disposal problem. Obviously it may be more desirable in many
situations to have a process available that would make only pure sulfur as
a byproduct.
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In addition to used limestone from stack gas scrubbing there is a
waste solid stream consisting of 299 tons/day of ash residue from the coal
burned in the utility boiler. Consideration should be given to control
of dusting, leaching, and odors in handling and disposing of all solids
or waste streams.
On the cooling water system, some water must be purged in order
to limit the buildup of dissolved solids. Such solids may enter in the
makeup water, be introduced as chemical additives to control corrosion or
algae, etc., or be formed in the process. An example of the latter would
be ammonium chloride that may be formed from chlorides and nitrogen compounds
present in the coal feed. A large part of-the nitrogen is often.converted
to ammonia in hydroliquefaction or gasification, and coals often contain
considerable chloride, much of which may also be released. This-cooling
tower blowdown represents the net water discharge from the plant.
For a typical situation the water purged from the cooling water
circuit may be one-fifth of the amount evaporated in the cooling tower.
Thus, the nominal concentration of dissolved solids in the purge water could
then be six times that in the fresh makeup water, and may be for example
over 2000 ppm such that it could be considered as brackish water and
unsuitable for drinking, or even for irrigation. There are techniques for
recovering clean water from such streams by evaporation, electrodialysis,
etc., although there still remains the problem of how to dispose of the
soluble salts or concentrated brine residue. Ocean disposal, storage,
or sale are possibilities.
To inhibit corrosion chromates are often added to cooling water
at concentrations of 1-10 ppm, as well as algacides such as chlorine.
These interfere seriously with biological action in natural systems or in
biological oxidation to remove ammonia, phenols, etc. Therefore they may
have to be removed, e.g., by precipitating chromium in a pretreatment step.
There is also water blowdown from boilers but this can be used
as cooling tower makeup, together with sour water which is cleaned up for
reuse. Ion exchange resins are often used in demineralization to prepare
boiler feedwater. Such resins are regenerated by backwashing with sulfuric
acid or caustic which can then be combined, neutralized, and disposed of
as discussed for cooling tower blowdown.
Waste water treating is expected to clean up the sour water so
that it can be used as cooling tower makeup. The H2S stream removed by
sour water stripping together with small amounts of ammonia, hydrocarbons,
etc. can be sent to the sulfur plant for incineration and disposal. In
some cases byproducts such as ammonia and phenol may be recovered and sold.
The fluoride content of the treated waste water is of concern and should be
determined in the pilot plant development. Excessively high fluoride is
indicated for some large scale gasification operations, so it may be that
precipitation with lime should be provided. Trace elements in addition
to fluoride, such as arsenic, are expected to be present in the sour water
since some are partially volatile at gasification conditions and may also
be solubized in hydroliquefaction. This aspect is discussed more fully
in Section 8 on trace elements.
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Biological oxidation is used to clean up sour water, generating
a cellular sludge which must also be disposed of. It might be suitable
as a soil conditioner if satisfactory with regard to odor, trace elements,
etc., or it might be disposed of by incineration. Where activated carbon
is used for final water cleanup, the offgases from regeneration should be
incinerated or properly disposed of. Aspects of sour water treating and
cleanup are discussed more fully in reference 11.
Finally, there is treatment of makeup water which produces liquid
and solid effluents. Regeneration of resins used for demineralization has
already been mentioned. In addition, zeolites may be used for water
softening, generating another waste stream containing dissolved solids when
the zeolite is regenerated. Lime softening may be used, in which case an
innocuous sludge is formed and can be disposed of along with ash residues.
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6. SULFUR BALANCE
Details on sulfur balance for this study case on H-Coal lique-
faction are given in Table 4. Of the total sulfur entering with the coal
feed 87.2% is recovered as byproduct sulfur from the sulfur plant. Another
8 5%'is removed by stack gas cleanup on the utility boiler, resulting in
a'large amount of spent limestone to dispose of. Emissions to the
atmosphere total 2.5% of the total sulfur, or 36 tons/day, from the boiler
after stack gas cleanup plus effluent from tail gas cleanup on the sulfur
plant. While the sour water contains H2S, it will be removed by waste
water treatment so that water discharged from the plant should not contain
excessive amounts of objectionable sulfur compounds.
A large stream of C02 is vented to the atmosphere from hydrogen
manufacture. It is essential that it be satisfactorily low in sulfur, which
may present problems in that some of the sulfur in the raw gas from gasifica-
tion is in the form of carbonyl sulfide, perhaps 10% of the total sulfur,
and conventional acid gas removal systems are not very effective for
removing it. One approach is to hydrolyze carbonyl sulfide and other sulfur
compounds in the raw gas to H2S, which could then be removed completely
by amine scrubbing and sent to the sulfur plant. This approach has been
included in the present study. After shifting, the C02 can then be removed
using a hot carbonate type of process to give a clean C02 waste stream that
can be vented directly to the atmosphere.
The syncrude product is low in sulfur (0.19 wt. %) and is intended
for further refining and upgrading, rather than fuel uses. The process
also makes byproduct fuel gas, part of which is used as plant fuel in
critical services while the rest is available for sale as a clean fuel.
Hydroliquefaction is expected to give only H2S, so that complication in
gas cleanup due to carbonyl sulfide should not occur in this part of the
plant.
A Glaus plant is used for sulfur recovery, together with tail gas
cleanup to avoid excessive sulfur emissions. Sulfur compounds recovered
by tail gas cleanup are returned to the Glaus plant for conversion to
byproduct sulfur. Overall recovery is 99% on the sulfur plant.
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Table 4
Sulfur Balance H-Coal Plant
tpd
Sulfur
Sulfur Input
Coal to H-Coal sys tern
Coal to Gasifier to make H2
Coal to utility boiler
•Sulfur Output
Synthetic crude 27 1.8
Byproduct fuel gas, nil
Treated waste water nil
C02 vent gas nil
Byproduct sulfur from Claus plant 1,295 87.2
Tail gas from sulfur plant 13 0.9
Recovered from utility furnace flue gas 127 8.5
Left in utility furnace flue gas 23 1.6
1.485 100.0
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7. THERMAL EFFICIENCY
Thermal efficiency is one way to measure the effectiveness of
process for making clean products from coal. It also gives a measure
thermal pollution effects in that essentially all of the loss in thermal
ficiency must be dissipated to the environment. Thermal efficiency for
a process is defined as the heating value of all clean products divided
bv the heating value of all raw materials consumed including coal for
conversion as well as coal or gas for utilities production and for plant
fuel The numbers are based on a complete and self-sufficient plant
including all utilities etc., with no purchase of electricity, for example,
which would make the result less meaningful.
For the H-Coal design used in this study, thermal efficiency is
75 2% Clean products include synthetic crude and net byproduct gas as
shown'in Table 5, while coal is consumed in liquefaction, gasification for
hydrogen manufacture, and in the utility boiler. About half of the total
clean gas available is used as plant fuel on the coal dryer, reactor pre-
heat furnace, and tail gas incinerator on the Claus plant.
As an alternative, the net byproduct gas could all be consumed
within the plant by substituting it for coal used in the gasifier and/or
utility boiler. Coal consumption for the overall plant would then decrease
but thermal efficiency would fall to 73.2%, crediting only the synthetic
crude as clean product. This number would increase somewhat if the clean
gas could be used first in a combined cycle turbine for power generation,
and then used in furnaces.
Some increase in efficiency might result if all hydrogen is made
by conventional reforming of clean product gas, rather than from tar slurry
plus coal. The oxygen plant, which is a major consumer of utilities, would
then not be needed, and gas cleanup would be simplified due to the absence
of sulfur and particulates. An alternative disposition of the tar slurry
would be required and it might be used as fuel. One possibility is fluid
bed combustion in a bed of limestone - a process that is being tested on a
large pilot plant scale. Combustion with the usual stack gas cleanup might
also be used, perhaps combined with a precoking step to recover oil.
Other approaches to Improve thermal efficiency include possible use
of heat pumps on sour water strippers or in acid gas removal. Energy savings
may also be achieved by maximizing heat exchange and recovery, by more effective
insulation, and by operating furnaces with lower excess air and lower stack
temperatures. Suggestions for consideration are given in reference 11.
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Table 5
Thermal Efficiency H-Coal Plant
Tons/Day 109 %
(Dry Basis) Btu/Day of Btu
Input
Coal to H-Coal reactor 25,000 649.2 83.4
Coal to gasifier to make H2 1,940 50.4 6.5
Coal to utility boiler 3,020 78.4 10.1
29,960 778.0 100.0
Output
Synthetic crude 14,416 527.0 67.7
Net byproduct clean gas (1) 1,210 58.0 7.5
585.0 75.2
;Overall thermal efficiency: fff^ = 75.2%
(1) After providing plant fuel gas to coal dryer, reactor preheat
furnace, and tail gas incinerator on sulfur plant. Sulfur
byproduct has a heating value equivalent to 1.3% thermal
efficiency, while byproduct ammonia is equivalent to 0.5%
thermal efficiency.
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- 43 -
8. TRACE ELEMENTS
Coal contains many trace elements present in less than 1%
concentration that need to be carefully considered from the standpoint
of potential impact on the environment. It is obvious that essentially all
materials entering the plant must also leave via the effluent or product
streams. Many of the trace elements volatilize to a small or large extent
during processing, and many of the volatile components can be highly toxic.
This is especially truce for mercury, selenium, arsenic, molybdenum, lead,
cadmium, beryUium and fluorine. The fate of trace elements in coal con-
version operations such as liquefaction or gasification can be very dif-
ferent than experienced in conventional coal fired furnaces. One reason
is that the conversion operations take place in a reducing atmosphere,
whereas in combustion the conditions are always oxidizing. This maintains
the trace elements in an oxidized condition such that they may have more
tendency to combine or dissolve in the major ash components such as silica
and alumina. On the other hand, the reducing atmosphere present in 'coal
conversion may form compounds such as hydrides, carbonyls or sulfides which
may be more volatile. Studies on coal fired furnaces have indicated that
smaller particles in fly ash contain a higher concentration of trace
elements, presumably due to volatilization of these elements in the com-
bustion zone and their subsequent condensation and collection on the fly
ash particles (34,35). Other studies on coal fired furnaces are pertinent
(36,37,38) and some of these report mass balances on trace elements around
the furnaces (39).
Considerable information is available on the analyses of coal,
including trace constituents, and these data have been assembled and
evaluated (40,41,42). Very limited information is available on the fate of
trace elements in the various liquefaction processes (11). A few studies
have been made to determine what happens to various trace elements during
gasification (2,28). As expected these show a very appreciable amount
of volatilization on certain elements. As an order of magnitude, for the
29,960 tons/day of dry coal consumed by the overall H-Coal plant, each
10 ppm of trace element present in the coal contributes an input of 600
Ib/day which must then leave the plant at some point. The coal is fed to
liquefaction, gasification, and to the utility boiler, all of which may
contribute to emission of trace elements.
Trace elements may be partially volatile in the liquefaction
reactor, for example as arsine, or solubilized such that they appear in the
oil or sour water. Most of the trace elements probably remain with the ash
and unconverted residue and are then fed to the slagging gasifier where
they are exposed to high temperature in the presence of a large volume of
gas. Although only a portion of trace elements may be volatile in the
gasifier, there is a very real problem to consider and evaluate since the
combined amounts vaporized should be removed in the downstream gas cleaning
operation and disposed of in an acceptable manner.
-------
In order to make the picture on trace metals more meaningful,
the approximate degree of volatilization during gasification shown for
various elements has been combined with their corresponding concentration
in a hypothetical coal (as typical), giving an estimate of the pounds per
day of each element that might be carried out with hot gases. Results are
shown in Table 6 in the order of decreasing volatility. Looking at the
estimated amounts that may be carried overhead, it becomes immediately
apparent that careful consideration of the problem is required. For each
element the net amount carried overhead should be collected, removed from
the systems and disposed of in an acceptable manner. In the case of zinc,
boron and fluorine the degree of volatilization has not yet been determined,
but they would be expected to be rather volatile. Even if only 10% of the
total amount is volatile, there will be large quantities to remove in the
gas cleaning operation and to dispose of.
The preceding discussion has been directed primarily at trace
elements that are partially volatilized during gasification or combustion
.and that therefore must be recovered and disposed of in the gas cleaning
systems. Consideration must also be given to trace metals that are not
volatilized and leave in the solid effluents from the plant, one of which
is the slag or ash from the coal fired furnace and from gasification.
Undesirable elements might be leached out of this slag since it is handled
as a water slurry or will ultimately be exposed to leaching by ground water
when it is disposed of as land fill or to the mine. Sufficient information
is not now available to evaluate the potential problems and the suituation
on gasifiers may be quite different from the slag rejected from coal fired
furnaces since it is produced in a reducing atmosphere rather than an
oxidizing one. Background information on slag from blast furnaces used in
the steel industry may be pertinent from this standpoint, since the blast
furnace operates with a reducing atmosphere. However, a large amount of
limestone is also added to the blast furnace, consequently the nature of
the slag will be different.
Other possible sources of trace element emissions from the
plant need to be evaluated. Thus, additives such as chromates may be used
in the cooling water circuit and appear in the blowdown stream. Depending
upon the amount present and the particular plant location, it may be
desirable to provide for chromium removal, for example using lime pre-
cipitation. Similarly, trace elements may be present in chemical purge
stream such as from acid gas removal systems where arsenates etc. may be
used as additives, or from absorption/oxidation sulfur plants using
.catalysts such as vanadates. Vanadium may be an essential element in some
biological systems, especially marine ones; consequently, the specific local
situation will have a major effect on whether the effluent represents a
problem, and on the choice of disposal method.
It is obvious that all trace elements in the coal feed must leave
the plant either in the products, or in other gas, liquid, or solid effluents.
It is not yet possible to make complete balances due to the early stage of
process development but all data necessary for accurate and complete balances
on toxic or potentially toxic elements should be obtained in the pilot plant
program. Emission limitations have been specified by EPA for a number of
toxic trace elements, and specifications for other elements are under
consideration.
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- 45 -
Table 6
Example of Trace Elements That May
Aooear in Gas Cleaning Systems
Element
Cl
Hg
Se
As
Pb
Cd
Sb
V
Ni
Be
Zn
B
F
Ti
Cr
Possible
ppm in Coal (a)
1500
0.2
2.2
31
7.7
0.14
0.15
35
14
2
44
165
85
340
22
% Volatile
for Example (b)
• >90+
90+
74
65
63
62
33
30
24
18
(10)
(10)
(10)
(10)
nil
Combined
Ib/day (c)
80,900
12
97
1200
290
5
3
629
200
22
265
989
509
2037
nil
o£
(a) Mainly based on Pittsburgh Seaa Coal (2), but
Xllinois coal used in this study based on ext
f laments in a specific coal sample can vary
depends upon^ource, particle size, extent of cleaning, etc., as
discussed in reference 42.
(b) Mainly based on a lower temperature gasifier (28) and indicated
at 10% for Zn, B, and Fs in absence of data,
(c) For 29,960 tons/day of coal feed total to plant including
gasifier and utility boiler.
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- 46 -
Many effluents from the plant are from conventional operations,
such as process furnaces, utility boilers, waste water treating, and ash
disposal. These are common, or at least similar, to other coal conversion
operations or coal fired boilers, and the pollution aspects and controls
have been discussed in previous reports in this series (1,2,3,4) or in
other references (19,20,29,43,44,45,46).
Although elements are lost, information is needed as to where
they will appear, and in what form (also vapor pressure, water solubility
etc.). Such results will be needed for critical elements on all coal
conversion processes used commercially, to define what recovery or separation
may be required and to allow designing effective pollution control and dis-
posal facilities. It is possible that part of the volatilized elements
will enter into side reactions In the presence of sulfur, phenols, and
ammonia, ash, etc., and may be soluble in water or oil, but this will not
be known until further information is available.
An additional source of possible contamination from trace elements
is associated with the disposal of refuse from coal cleaning. Although
the cleaning operation has not been included in this specific study case,
it will normally have to be provided, possibly at the mine, or in some cases
at the conversion plant. It is known that sulfur compounds contained in
coal refuse will oxidize upon exposure to the air and form an acid solution
in the presence of water. It is quite likely that a number of trace elements
can be extracted from the refuse by this acid solution. For example,
similar systems have been proposed and studied for recovering copper, nickel,
iron, etc. from low grade ores. It might be thought that this situation
is no worse than that existing for natural mineral deposits; however, the
conditions are quite different. First, the mineral has been crushed and
reduced in size so that vastly more surface is exposed and available for
extraction. In addition, the mineral is exposed to a large amount of oxygen,
which together with the large surface area can cause considerable oxidation
of sulfur compounds, organic materials, and minerals in the refuse, whereas
natural mineral deposits may not be subject to such conditions. Some studies
have been made in this general area (45,46) but much more work is needed.
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- 47 -
9. TECHNOLOGY NEEDS
From this review and examination of environmental aspects of the
H Coal process, a number of areas have been defined where further information
is needed in order to evaluate the situation, or where additional studies
or Experimental work could lead to a significant improvement from the stand-
no int of environmental controls, energy consumption, or thermal efficiency
of the process. Items of this nature will be discussed in.this section of
the report, and a summary is shown in Table 7.
Any coal conversion operation has solid refuse to be disposed of.
While coal cleaning is not specifically included in this study design, it
will usually have to be provided at some location and necessarily generates
laree amounts of solid refuse to dispose of and wash water to be cleaned up
for reuse. For example, there may be over 800 acre feet per year of refuse.
In addition, the production of slag from gasification is 2667 tons per day
or another 400 acre ft/yr. More work is needed in order to define methods
of disposal that do not create problems due to leaching of acids, organic,
metals, or sulfur which could contaminate natural water. In addition,
adequate controls are needed with regard to the potential dust nuisance
and washing away of particulates. In many cases the material may be suitable
for land fill with revegetation. Although there is already a lot of back-
ground on this subject, specific information is needed on each coal and for
each specific location in order to allow thorough planning to be sure that
the disposal will be environmentally sound.
Coal drying is used on most coal conversion processes; consequently,
considerable effort is warranted to optimize the operation from the stand-
points of fuel consumption, dust recovery, and volume of vent gas to be
handled (4). It will often be attractive to burn high sulfur coal rather than
clean gas fuel, and to include facilities for cleaning up the vent gases.
In the liquefaction operation it will be important to determine
more about what happens to various constituents in the coal feed, such as
sulfur, oxygen, and nitrogen compounds and other minor or trace elements.
These may be converted to materials that are soluble in the oil or water,
or remain with the gas, or deposit on the catalyst. The possible formation
of arsine, HF, and similar compounds should be evaluated. It is expected
that much of the coal nitrogen will appear as ammonia which can be removed
by scrubbing with water, but amines may also form and appear in the water
layer to complicate the cleanup of waste water. Phenolic and other oxygenated
compounds will probably be present. Phenol itself is very soluble in water,
but higher phenols may be mainly in the oil phase. In order to clarify
environmental aspects on the liquefaction operation, considerable additional
information will be needed on the formation of critical minor and trace
compounds. The identity and amount for each of these should be determined
since it can have a major effect on the selection of cleanup and disposal
methods on the oil, water, and gas streams, as well as the spent catalyst
and solid wastes.
-------
Table 7
Technology Needs
• Environmentally sound disposal of large amounts of solid refuse from
coal cleaning, gasification and utility furnace, with regard to dust,
leaching and sediment, trace elements, land use, etc.
• An optimized design for coal drying to use low excess air and give
maximum allowable coal preheat, with good dust recovery.
• A simpler and more efficient process for acid gas removal which would
provide an I^S stream of high concentration (e.g., 50 vol. %) to the
sulfur plant, while giving a separate clean stream of C02 that can be
vented to the air. Desirable features to include:
- good sulfur clean up, to a few ppm
- a clean C02 vent stream that does not require incineration
- low utilities consumption
- little or no chemical purges to dispose of
• Ways to handle COS, CS2» thlophene, etc., that are usually present in
the raw gas to hydrogen manufacture and may not be removed by many acid
gas removal processes. Hydrolysis to l^S is probably one good approach.
• Sour water cleanup to make it suitable for reuse. Some purge will
probably be needed to remove trace elements and perhaps ammonia and
phenols. There is a great need for a practical system to evaporate
sour water to make steam for use in the process, and a fluid bed system
appears promising.
• Water recovery from the net water discharge leaving the plant, together
with disposal of the salt concentrate.
• Information on trace elements and techniques for their disposal for
liquefaction, gasification, utility furnace, and coal cleaning.
- Extent of volatility for specific process and coal.
- Where they appear in clean up system, and in what form. They may
collect in the oil and build up by recycling. Others may appear on
the hydroliquefaction or shift catalyst and in sour water or acid gas
removal.
- Many may be toxic and require separation and decontamination treatment
before disposal.
- Leaching may occur oh solid wastes such as the slag or on refuse from
coal cleaning. Information is needed to define the potential problem
and to devise environmentally sound disposal techniques.
- Other important discharges of trace elements must be identified for
evaluation, such as chromates in cooling tower blowdown, volatile
fluorides that may collect in sour water, and chemical purges from
acid gas removal etc. that .may contain arsenic, vanadium, etc.
-------
In the area of acid gas removal, systems based on amine or hot
ate are not completely satisfactory and leave room for improvement.
ine Drubbing is not effective on carbonyl sulfide, while contaminants
sSch as cyanide interfere with regeneration of the scrubbing liquid. Hot
carbonate systems do remove carbonyl sulfide, but it is often difficult
to provide a highly concentrated stream of H2S to send to the sulfur plant.
In addition the COo stream vented to the atmosphere may contain too much
sulfur Adsorption/oxidation systems are often not effectiv^n carbonyl
sulfide and in any event do not remove C02 as required, and therefore
a^itional processing is needed. The available systems, for acid gas removal
have very high utility requirements, causing a significant loss^in thermal
efficiency for conversion of coal to clean fuel products. In addition^there
is often a waste stream of chemical scrubbing medium which may be difficult
and expensive to dispose of. Systems based on physical solvents such as methanol
appear to give a C02 vent stream that is excessively high in combustibles
such as hydrocarbons and CO.
Desirable objectives for an acid gas removal process can be
summarized as follows: (a) good clean up of all forms of sulfur to give
a stream high in sulfur concentration for processing in a Glaus sulfur
plant (b) effective C02 removal while producing a vent stream satisfactorily
low in sulfur and pollutants, (c) low utility and energy consumption,
(d) no waste streams that present a disposal problem.
The need for a simple, effective method to clean up sour water
for reuse is another item that is common to most fossil fuel conversion
operations. Sour water generally contains sulfur compounds, ammonia, H2S,
phenol, thiocyanates, cyanides, traces of oil, etc. These are generally
present in too high a concentration to allow going directly to biological
oxidation, but their concentration is often too low to make recovery
attractive. Particulates, if present, further complicate the processing
of sour water. Usual techniques for clean up include sour water stripping
to remove H2S and ammonia, and in addition, extraction may be required to
remove phenols and similar compounds (11). Such operations are large consumers
of utilities and have a large effect on overall thermal efficiency.
In most cases the net amount of sour water produced is less than
the amount of steam consumed by reaction in gasification plus shift con-
version, which suggests a way to dispose of sour water. One approach is
to vaporize the sour water to make steam which can be used in the gasifier.
In this case, compounds such as phenol should be destroyed and reach
equilibrium concentration in the circulating sour water. It may not be
practical to vaporize sour water in conventional equipment such as exchangers,
due to severe fouling and corrosion problems. Therefore, new techniques
may be required, and one possibility would be to vaporize the sour water
by injecting it into a hot bed of fluidized solids as discussed in reference 5.
On trace elements, information is needed on the amount vaporized
in the gasifier and what happens to them, where they separate out and in
what form, so that techniques can be worked out for recovering or disposing
of the materials. Again specific Information is needed for each coal and
-------
- 50 -
for each coal conversion process since operating conditions differ, partic-
ularly between liquefaction and gasification. In many cases, the trace ele-
ments may tend to recycle within the system and build up in concentration (6,29).
This offers an interesting opportunity to perhaps recover some of them as
useful by-products. The toxic nature of many of the volatile elements
should be given careful consideration from the standpoint of emissions to
the environment, as well as protection of personnel during operation and
maintenance of the plant. Carcinogenicity of coal tar and other compounds
present in trace amounts or formed during startup or upsets should also
be evaluated. As discussed in Section 8 on Trace Elements, clarification
is needed regarding potential problems associated with trace elements in
various plant effluents such as spent catalyst from liquefaction and shifting
or chemical purge streams from acid gas removal, tail gas cleanup, and
stack gas scrubbing.
Protection of personnel, especially during maintenance operations
should be given careful attention, which will require that additional
information be obtained. Thus, toxic elements that vaporize in the gasifier
may condense in equipment such as piping and exchangers where they could
create hazards during cleaning operations.
Waste water is discharged as cooling tower blowdown, constituting
the net water effluent from the plant. Detailed study of the requirements
for cleaning up this water will be needed. In any event, the water make-up
that is brought to the plant will contain dissolved solids including sodium
and calcium salts. Calcium salts may be precipitated during the water
treating operation to form a sludge which can be disposed of with the other
waste solids, but the fate of the sodium salts in the make-up water calls
for further study. These will leave with the blowdown from the cooling
tower. If the concentration of dissolved solids is too high in this blow-
down water to allow discharging it to the river, then some suitable method
of disposal will have to be worked out. On one proposed commercial plant,
this has been handled by using an evaporation pond where the water is
evaporated to dryness. The salts accumulate and will ultimately have to
be disposed of. If they cannot be used or sold then it would seem logical
to dispose of them in the ocean. Other possibilities are electrodialysis,
or evaporators to concentrate the salts to a paste, while recovering usable
water from the waste stream.
In general it appears that there will be significant variations
in emissions and effluents from different conversion operations, in
addition to varying criticality of environmental factors depending upon
the local situation, plant location, coal feed, etc., such that each
specific plant may require its own evaluation of environmental effects
and control measures.
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- 51 -
10. PROCESS DETAILS
Additional details for the H-Coal plant including utility
requirements are given in Tables 8-13.
-------
- 52 -
Table 8
Steam Balance H-Coal Plant
Ib/hr
1000 psig Steam
Generated; Utility boiler
Consumed; Electrical generation (1)
Oxygen plant (1)
Oxygen plant (2)
Oxygen plant (3)
Hydrogen compressor (3)
600 psig Steam
Generated:
Consumed:
Gasifier reactor
Shift area
H-Coal system
Bleeder turbine
Gasifier
Shift reactor
Acid gas removal
2,178,000
750,000
303,000
570,000
302,000
253,000
2,178,000
275,000
233,000
550,000
570,000
1,628,000
178,000
1,020,000
430,000
1,628,000
70 psig Steam
Generated:
Electrical generation
Oxygen plant
Consumed; Sour water stripper
Acid gas removal
750,000
303,000
1,053,000
220,000
833,000
1,053,000
Notes; (1) Bleeder turbine discharging to 70 psig steam
(2) Bleeder turbine discharging to 600 psig steam
(3) Condensing turbine drive.
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- 53 -
Table 9
Electric Power Required in H-Coal Plant
kW
Coal Preparation 12,800
Scrubber 600
Acid Gas Removal 400
Gasification 400
Sulfur Plant 4,000
Slurry feed pumps 14,000
Cooling Water pumps 6,600
Cooling tower fans 3,200
Air cooler fans 4,000
Misc. 4,000
50,000
Table 10
Water Balance for H-Coal Plant
tons/day
To Waste Water Treating 8820
Cooling water circuit (200,000 gpm circulation):
Losses Makeup
Evaporation 259400 Treated wastewater 8,820
Drift loss 1,200 From boiler blowdown 2,160
Slowdown 5,100 Fresh water 20,720
31,700 31,700
Makeup Water
To cooling tower 20,720
To boiler feedwater 16,960
37,680 (6300 gpm)
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- 54 -
Table 11
Make Up Chemicals and Catalyst Requirements
Chemicals
Acid Gas Removal;
- scrubbing solution
- additives
Sulfur Plant tail gas cleanup
Limestone for stack gas cleanup
Cooling Tower Additives
Anticorrosion, e.g., chromate
Antifouling, e.g., chlorine
Water Treating
Lime
Alum
Caustic
Sulfuric acid
Catalysts» etc.
Liquefaction catalyst
Shift catalyst
Glaus plant catalyst
Ion exchange resin for water treating
-------
- 55 -
Table 12
Potential Odor Emissions
Coal storage and handling.
Coal preparation, washing, settling pond.
Coal drying - vent gas.
Vent gas from vacuum distillation.
Ash handling and disposal.
Sour water stripping and handling.
C02 vent stream from hydrogen manufacture.
Sulfur plant and tail gas.
Flue gas from utility boiler.
Cooling tower and air coolers.
Flash gases from depressuring liquid streams,
Biox pond and other ponds.
Leaks: ammonia, H2S, phenols, oil, etc.
Table 13
Potential Noise Problems
Coal handling and conveyors.
Coal crushing, drying and grinding.
Oxygen plant air and oxygen compressors.
Burners and furnaces.
Stacks emitting flue gases.
Turbo-generator etc., in utilities area.
Depressuring of gases and liquids.
-------
-se-
ll. QUALIFICATIONS
As pointed out, this study does not consider cost or economics.
Also, areas such as coal mining, coal cleaning, and general offsites are
excluded. These will be similar and common to all conversion operations.
The study is based on a specific process design and coal type,
with modifications as discussed. Plant location is an important item of
the basis and is not always specified in detail. It will affect items
such as the air and water conditions available, and the type of pollution
control needed. For example, this study is based on high sulfur Illinois
No. 6 coal, although it could be used on low sulfur western coal. Because
of variations in such basis items, great caution is needed in making com-
parisons between coal conversion processes since they are not on a com-
pletely comparable basis.
Some other conversion processes are intended to make a clean heavy
fuel, SNG, or low-Btu gas fuel, and may make appreciable amounts of
by-products. Such variability further increases the difficulty of making
meaningful comparisons between processes.
-------
- 57 -
12. BIBLIOGRAPHY
1. Magee, E. M., Jahnig, C. E., and Shaw, H., "Evaluation of Pollution
Control in Fossil Fuel Conversion Processes, Gasification; Section .1:
Koppers-Totzek Process," Report No. EPA-650/2-74-009a, January 1974.
(PB 231 675, NTIS, Springfield, VA 22151).
2. Kalfadelis, C. D,f and Magee, E. M., "Evaluation of Pollution Control
in Fossil Fuel Conversion Processes, Gasification; Section 2:
Synthane Process," Report No. EPA-650/2-74-009b, June 1974.
(PB 237 113, NTIS, Springfield, VA 22151).
3. Shaw, H., and Magee, E. M., "Evaluation of Pollution Control in Fossil
Fuel Conversion Processes, Gasification; Section 3; Lurgi Process,"
Report No. EPA-650/2-74-009c, July 1974. (PB 237 694, NTIS,
Springfield, VA 22151).
4. Jahnig, C. E., and Magee, E. M., "Evaluation of Pollution Control in
Fossil Fuel Conversion Processes, Gasification; Section 4: CC>2
Acceptor Process," Report No. EPA-650/2-74-009d, December 1974.
(PB 241 141, NTIS, Springfield, VA 22151).
5. Jahnig * C. E-., "Evaluation of Pollution Control in Fossil Fuel
Conversion Processes, Gasification; Section 5: Bi-Gas Process,
Report No. EPA-650/2-74-009g, May 1975. (PB 243 694, NTIS,
Springfield, VA 22151).
6. Jahnig, C. E., "Evaluation of Pollution Control in,Fossil Fuel
Conversion Processes, Gasification; Section 6: Hy-Gas Process,"
Report No. EPA-650/2-74-009h, August 1975.
7. Jahnig, C. E., "Evaluation of Pollution Control in Fossil Fuel
Conversion Processes, Gasification; Section 7: U-Gas Process,"
Report No. EPA-650/2-74-009i, September 1975.
8. Jahnig, C. E., "Evaluation of Pollution Control in Fossil Fuel
Conversion Process, Gasification; Section 8s Winkler Process,"
Report No. EPA-650/2-74-009J, September 1975.
9. Magee, E: M., "Evaluation of Pollution Control in Fossil Fuel
Conversion Process, Coal Cleaning; Section 1: Meyers Process,"
Report No. EPA-650/2-74-009k, September 1975.
10. Kalfadelis, C, D.9 "Evaluation of Pollution Control in Fossil Fuel
Conversion Process, Liquefactions Section Is COED Process,"
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Springfield, VA 22151).
11. Jahnig, C. E., "Evaluation of Pollution Control in Fossil Fuel
Converoion Processes, Liquefaction; Section 2s Seispeafc Safincd Coal
Process," Report No. EPA-650/2-74=009f, torch 1975. (PB 241 792,
NTIS, Springfield, VA 22151).
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- 58 -
12. Johnson, C. A., Chervenak, M. C., Johanson, E. S., and Wolk, R. H.,
"Scale-Up Factors In H-Coal Process," American Institute of Chemical
Engineers Meeting, New York, N.Y., November 26-30, 1972.
13. Johnson, C. A., Volk, W., and Winter, 0., "HRI Coal Gasification,"
Fifth AGA/OCR Synthetic Pipeline Gas Symposium, October 29-30, 1973,
Chicago, 111.
14. Johnson, C. A., Statler, H. H., and Winter, 0., "H-Coal Prototype
Plant Program," American Institute of Chemical Engineers, November
11-15, 1973, Philadelphia, Pa.
15. Johnson, C. A., Chervenak, M. C., Johanson, E. S., Statler, H. H.,
Winter, 0., and Wolk, R. H., "Present Status of the H-Coal Process,"
Clean Fuels from Coal Symposium, Institute of Gas Technology,
September 10-14, 1973, Chicago, 111.
16. HRI Inc., "Liquefaction of Kaiparowits Coal," For Electric Power
Research Institute, Report No. EPRI 132-2, October 1974.
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Processing, December 1974: 79-87.
18. Colgate, J. L., Akers, D. J., and From, R. W., "Gob Pile Stabilization,
Reclaimation, and Utilization," OCR R&D Report No. 75, 1973.
19. Bartok, W., Crawford, A. R., and Piegari, G. J., "Systematic Field
Study of NOx Emissions Control Method for Utility Boilers," P.B. 210739,
December 1971.
20. Atmospheric Emissions from Petroleum Refineries, U.S. Dept. of Health,
Educ. and Welfare, Public. No. 783, 1960.
21. Groaman, A. P., "Find Heat Exchanger Leakage Accurately," Hydrocarbon
Processing, January 1975: 58-59.
22. Heialer, L., and Weiss, L., "Experience with an Austrian Gas Plant,"
Hydrocarbon Processing, May 19/5: 157-161.
23. Goar, B. G., "Claus Tail Gas Cleanup," Parts 1&2. Oil Gas Journal,
August 18, 1975: 109-112 and August 25, 1975: 96-103.
24. National Public Hearings on Power Plant Compliance with Sulfur Oxide
Air Pollution Regulations, EPA, January 1974.
25. Environmental Engineering Handbook Issue. Chemical Engineering
Magazine, October 21, 1974: 79-85.
26. Status of Flue Gas Desulfurization Technology, F. T. Princiotta,
Efa. Symposium on Environmental Aspects of Fuel Conversion Technology.
St. Louis, Missouri, May 13-16, 1974, EPA 650/2-74-118.
27. Furlong, E., "Cooling Tower Operations," Environmental Science and
Technology, 8_, No. 8: 712.
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28 Attari A., "The Fate of Trace Constituents of Coal During Gasification,
EPA Report 650/2-73-004, August 1973 (Part I) Also, Part II presented
at American Chemical Society Meeting Division of Fuel Chemistry
April 6-11, 1975, Philadelphia, Pa.
29. Jahnig, C. E., and Bertrand, R. R., "Environmental Aspects of Coal
Gasification," American Institute of Chemical Engineers Meeting,
September 8-10, 1975, Boston, Mass.
30. Flue Gas Desulfurization - Installations and Operations, U.S.
Environmental Protection Agency Report, September 1974.
31. Proceedings: Symposium on Flue Gas Desulfurization --Atlanta,
November 1974, Vols. I & II., Report No. EPA 650/2-74-126 a/b
December 1974.
32. Lisaukas, R. A., and Johnson, S. A., "NOx Formation During the
Combustion of Low and Intermediate Btu Gas from Coal, American
Institute of Chemical Engineers Meeting September 8-10, 1975,
Boston, Mass.
33. Processes for S02 Removal, Chemical Engineering Progress 71. No. 5:
55-76.
34. Lee, R. E., and Lehmden, D. J., "Trace Metal Pollution in the
Environment," Journal of Air Pollution Control Association 23, 10
853-857.
35. Kaakien, J. W., Jorden, R. M., Lawasani, M. H., and West, R. E.,
"Trace Element Behavior in Coal-Fired Power Plant," Environmental
Science and Technology, ^, No. 9: 862-869.
36. Andren, A. W., and Klein, D. H., "Selenium in Coal-Fired Steam Plant
Emission," Environmental Science and Technology, 9., No. 9: 856-858.
37. Billings, C. E., Sacco, A. M., Matson, W. R., Griffin, R. M.,
Coniglio, W. R., and Barley, R. A., "Mercury Balance on a Large
Pulverized Coal-Fired Furnace," J. Air Poll. Control Association,
23, No. 9: 773.
38. Schultz, Hyman et al., "The Fate of Some Trace Elements During Coal
Pre-treatment and Combustion," ACS Div. of Fuel Chemistry, ji, No. 4:
108.
39. Bolton, N. E., et al, "Trace Element Mass Balance Around a Coal-Fired
Steam Plant," ACS Div. of Fuel Chemistry 18, No. 4: 114.
40. Magee, E. M., Hall, H. J., and Varga, G. M., Jr., "Potential Pollutants
in Fossil Fuels," EPA-R2-73-249, June 1973.
41. Hall, H. J., "Trace Elements and Potential Toxic Effects in Fossil
Fuels," EPA Symposium "Environmental Aspects of Fuel Conversion
Technology," St. Louis, Mo., May 1974.
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42. Ruch, R. R., Gluskoter, H. J., and Shimp, N. F., "Occurence and
Distribution of Potentially Volatile Trace Elements in Coal,"
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Science and Technology, 7_, No. 2: 110-119.
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TECHNICAL REPORT DATA
(Please read Imtructiom on the reverse before completing)
1. REPORT NO.
EPA-650/2-74-009-m
2.
3. RECIPIENT'S ACCESSI ON>NO.
4. TITLE AND SUBTITLE
Evaluation of Pollution Control in Fossil Fuel Conver-
sion Processes
Liquefaction: Section 3. H-Coal Process
5. REPORT DATE
October 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
C.E. Jahnig
8. PERFORMING ORGANIZATION REPORT NO
Exxon/GRU.15DJ.75
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Exxon Research and Engineering Company
P. O. Box 8
Linden, New Jersey 07036
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADD-023
11. CONTRACT/GRANT NO.
68-02-0629
12. SPONSORING AGENCV NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT.
The report gives results of a review of the H-Coal Process of Hydrocarbon
Research, Inc. , from the standpoint of its effect on the environment. Quantities of
solid, liquid, and gaseous effluents are specified, where possible, as well as the
thermal efficiency of the process. Techniques for controlling pollution are outlined
and discussed. For the purpose of reducing environmental impact, a number of
possible modifications or alternatives are presented for consideration. In some
areas existing information or control systems are inadequate; therefore, technology
needs are pointed out covering such areas, together with approaches to improve
efficiency and conservation of energy or water.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Coal
Liquefaction
Fossil Fuels
Thermal Efficiency
Air Pollution Control
Stationary Sources
H-Coal Process
Clean Fuels
Research Needs
13B
21D
07D
20M
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
67
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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