EPA-650/2-74-009-H
August 1975
Environmental Protection Technology Serie:
EVALUATION OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION
PROCESSES
GASIFICATION: SECTION 6. HYGAS PROCESS
+*& sr^
•tf
111
o
U.S. Environmental Protection Agency
Office of Research and Development
Washington, D. C. 20460
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EPA-650/2-74-009-H
EVALUATION OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION
PROCESSES
GASIFICATION: SECTION 6. HYGAS 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
August 1975
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EPA RKVIKW NOTICE
This rc'port has been reviewed by the National Environmental Research
Center - Research Triangle Park, Office of Research and Development.
EPA, and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial
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-h
11
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TABLE OF CONTENTS
Page
1. SUMMARY 1
2. INTRODUCTION 2
3. SELECTION OF BASIS 4
4. PROCESS DESCRIPTION 6
4.1 Coal Preparation 6
4.2 Gasification 8
4.3 Quench and Dust Removal 8
4.4 Shift Conversion and Cooling 10
4.5 Acid Gas Treatment 10
4.6 Methanation and Drying 11
4.7 Auxiliary Facilities 11
5. EFFLUENTS TO ATMOSPHERE 14
5.1 Coal Preparation 14
5.2 Gasification 22
5.3 Quench and Dust Removal 23
5.4 Shift Conversion and Cooling 23
5.5 Acid Gas Treatment 24
5.6 Methanation and Drying 25
5.7 Auxiliary Facilities 25
6. EFFLUENTS - LIQUIDS AND SOLIDS 28
6.1 Coal Preparation 28
6.2 Gasification 29
6.3 Quench and Dust Removal 29
6.4 Shift Conversion and Cooling 30
6.5 Acid Gas Treatment 30
6.6 Methanation and Drying 31
6.7 Auxiliary Facilities 31
7. SULFUR BALANCE 34
iii
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TABLE OF CONTENTS (Cont'd)
Page
8. THERMAL EFFICIENCY 36
9. TRACE ELEMENTS 38
10. TECHNOLOGY NEEDS 41
11. PROCESS DETAILS 45
12. QUALIFICATIONS 50
13. BIBLIOGRAPHY 51
IV
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LIST OF TABLES
No. Page
1 EFFLUENTS AND STREAMS FOR HYGAS PROCESS 16
2 THERMAL EFFICIENCY HYGAS PROCESS 37
3 TRACE ELEMENTS - ESTIMATED VOLATILITY 39
4 TECHNOLOGY NEEDS 42
5 COAL FEED AND PRODUCTS - HYGAS PLANT 46
6 STEAM BALANCE HYGAS PROCESS 47
7 ELECTRIC POWER CONSUMPTION HYGAS PROCESS 48
8 WATER BALANCE HYGAS PROCESS 49
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LIST OF FIGURES
No. Page
1 FLOW PLAN FOR HYGAS PROCESS 7
2 HYGAS REACTOR 9
3 EFFLUENTS AND STREAMS FOR HYGAS PROCESS 15
4 SULFUR BALANCE - HYGAS PROCESS 35
vx
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1. SUMMARY
The HYGAS process being developed by the Institute of Gas Technology
has been reviewed from the standpoint of its potential for affecting the
environment. The quantities of solid, liquid and gaseous effluents have
been estimated where possible, as well as the thermal efficiency of the
process. For the purpose of reduced environmental impact, a number of
possible process modifications or alternatives which could facilitate
pollution control or increase thermal efficiency have been proposed, and
new technology needs have been pointed out.
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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 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 commercially
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 gasification 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 the
various 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 &
Engineering Company under Contract No. EPA-68-02-0629, using all available
non-proprietary information.
The present study under the contract involves preliminary design
work to assure that conversion 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 non-polluting.
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 of a given quantity of clean fuel. Alternatively,
it is a way of estimating the amount of raw fuel resources that are consumed
in making the relatively pollution-free fuel. At this time of energy shortage
this is an important consideration. 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 with some of the developers were made, when it appeared
warranted, to develop and up-date published information. Not included in
this study are such areas as cost, economics, operability, etc. Coal mining
and general offsite facilities are not within the scope of this study.
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Other 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, CC>2 Acceptor and BIGAS
processes (1,2,3,4,5).
In the area of coal liquefaction, reports have been issued on
the COED process of FMC (6) 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 (7).
The present report covers our environmental evaluation of
the HYGAS process to gasify coal and make synthetic pipeline gas, based
to a large extent on information in reference 8, as part of a study made
for EPA. This reference gives flow rates and compositions for oxygen-
steam gasification, as well as total utilities for a complete plant. A
breakdown of utilities requirements was not given and had to be estimated,
as was the case with certain flow rates and compositions.
Our calculations included weight balances on individual elements,
heat balances, and thermodynamic considerations. Some additional informa-
tion on the process is given in other publications (9-18) and an engineering
analysis for a commercial HYGAS plant has been projected (18), although
these do not use the present route of gasifying with oxygen and steam.
Information on the U-Gas System is also given in references 8, 13, 16 and 17.
The U-Gas process is incorporated into the overall plant design in the
present HYGAS study, but a separate report will be issued to cover it in
more detail.
This particular design omits pretreating of coal to destroy
caking properties, and has been used for the present study as suggested
by the Institute of Gas Technology. Although pretreating is not required
if the process is used on a non-caking coal, it should be emphasized that
with caking coals pretreating may be necessary, in which case extensive
additional facilities would have to be added beyond those considered in
our present study. Also, pretreating generates a very large volume of
raw gas that must be cleaned up and used, produces by-product tar liquids,
and releases a large amount of heat (14).
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3. SELECTION OF BASIS
In the HYGAS development, various alternatives have been con-
sidered for generating hydrogen or synthesis gas to use in the gasifier
(9,11,15). One method is electrothermal, in which spent char is supplied
by electrodes whereby an electric current flows through the fluidized bed
of char. An alternative source of hydrogen is based on the steam-iron
process, in which steam reacts with iron to form hydrogen and iron oxide.
The latter is circulated to a separate vessel where it is regenerated using
low Btu gas formed by reacting air with char. These are not the routes
selected for the latest pilot plant design; however, the steam-iron route
may be of interest in the longer range picture.
Attention is now focused on steam-oxygen gasification for the
HYGAS process, together with methanation. The gasifier operates at 1,200
psig and the coal feed is pressurized by pumping it as an oil slurry,
rather than using lock hoppers.
Coal-oil slurry at 1,200 psig or higher is dried by evaporation
in a fluidized bed at 600°F and the coal then flows to a 1250°F bed,
followed by one at 1750°F, and is finally gasified at 1900°F with steam
oxygen. The feed coal passes through coking zones of increasing severity,
consequently appreciable by-product liquids are formed. Most of the tar
present in the raw gas is condensed in the 600°F drying zone and returned
along with the coal feed back to the 1250°F zone, where the tar can be
cracked to lighter liquid.
Except when a non-caking coal feed was used, pretreating of the
coal feed to eliminate caking tendency was included in previous publica-
tions on the HYGAS process (9,11). Since caking coal would agglomerate
in the fluid beds and cause plugging, pretreatment was considered to be
necessary. The method of pretreating is to blow air through a fluid bed
of coal particles at about 750-800°F, whereby much of the volatile
matter is removed and some by-product tar is recovered (14) . Oxidation
destroys caking properties. It also releases a very large amount of
heat which is recovered and used to make steam.
Pretreated coal must then be cooled in order to form a slurry
for pumping at 400°F or less. The cooling step might be avoided if pre-
treating were carried out at gasifier pressure, but then the air for
pretreating would have to be compressed, and a very large volume of air
is required. Pretreating uses about 375 MM SCFD of air for a plant making
250 MM SCFD of synthetic natural gas (SNG). Off-gas from pretreating
has a heating value of only 39 Btu per cubic foot but can be used as
fuel, after clean-up (12). Tar yield from pretreating, if it were used,
is estimated to be 630 tpd.
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Looking into the future, it is the hope of IGT that modifica-
tions to the process can be made so that pretreating will no longer be
necessary. Therefore, they recommended that pretreating be omitted from
our study case and on this basis we have used a HYGAS design without
coal pretreatment. It should be pointed out that if pretreatment is
required, then the plant will look considerably different and will in-
clude large complex pretreatment facilities generating a large amount
of heat, as well as a large volume of low Btu gas (e.g., 39 Btu per cf)
which would have to be processed to remove tar, sulfur, and dust and
consumed within the process.
To make the plant complete and self-sufficient, the necessary
auxiliaries have been included, such as a sulfur plant, an oxygen plant,
and all utilities. Clean low Btu fuel gas for the boiler furnace and
for coal drying is manufactured using the IGT U-Gas process, based on
steam-air gasification of coal. Since information on this system was
incomplete, some of the flow rates and balances were calculated or esti-
mated, in order to allow defining environmental controls and effects for
the U-Gas operation.
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4. PROCESS DESCRIPTION
The process makes 260 MM SCFD of pipeline gas (SNG) from
Illinois No. 6 coal by gasifying it with medium Btu gas (mainly CO plus
H2 and steam) in a series of countercurrent fluidized zones. Residual
char is then gasified with oxygen and steam in a bottom zone to provide
gas for gasification in the upper zones. Carbon content of the rejected
char may be 10-30 wt. %.
Raw gas is cleaned-up, shifted, and methanated. Operating
pressure is sufficiently high so that compression of the product gas is
avoided. The method of pressurizing coal feed involves slurrying it
with light oil by-product, pumping to high pressure, and evaporating
the slurry to dryness by direct contact with hot raw gas in a fluidized
bed.
A block flow diagram of the processing steps is shown in
Figure 1, together with major flow rates and operating conditions. The
process can conveniently be sub-divided into a sequence of operations,
each of which will be described in the following sub-sections of the
report: (1) Coal Preparation, (2) Gasification, (3) Quench and Dust
Removal, (4) Shift Conversion and Cooling, (5) Acid Gas Removal,
(6) Methanation and (7) Auxiliary Facilities.
4.1 Coal Preparation
These facilities include storage and handling, crushing, and
drying. It is assumed that cleaned coal is delivered, the separation
of refuse and washing having been done at the mine or elsewhere with
suitable disposal of waste and environmental controls. Coal feed,
amounting to 17,517 tons/day (6.48% moisture), is received and 30 days
storage is provided. Information on the coal feed is given in Table 1.
Since the storage pile is very large, roughly 15 acres at 25 ft high,
protection will be needed to control dust nuisance due to wind, while
rain run off should be collected and cleaned up to supply makeup water
for the plant.
Crushing is the next step in coal preparation, to reduce the
coal feed to minus 8 mesh. Crushed coal is then dried to negligible
moisture content in a fluid bed drier fired with part of the low Btu gas
produced by the U-Gas system. The latter also supplies clean gas fuel
for generating utilities, and consumes 22.5% of the total coal used by
the plant.
Dried coal going to gasification is pressurized by mixing with
oil to form a slurry which is pumped to about 1200 psia. Theoretical
power for pumping is about 4500 horsepower. Oil is vaporized and re-
covered when the slurry is subsequently dried in an upper zone of the
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FIGURE 1
FT.OH PLAN FOR HYCAS PROCFSS
Atmosphere
30.726
Benzene 133
Water
iH20 51.3
T02 0-6
K 39-6
1 7^J517 -^^ '
(6.57. Preparation (
moisture)
Air |
38. MM SCFD
Chi
L
oal
12,695_
nil Molltui^e)
r \
Fuel Gas
33 MM SCFD
CO 17.0 v 7.
CO2 8.8
H2 11.6
H-fl 12.6
CH4 4.1
N2 45.9
\r
450
To Sulfur f
recovery from
regeneration 17-Ca
797
21 v 7. S02 T "
79 v 7. N, 1
2 Coal
3686
Air
1173'
100.0
»
in
2560
)
r-U rX rX X-E,
Sulfur
Coal Raw Cooled Shifted Clean Free
Sl"rry Slurry r.ast f ica t fo i Oas _ oil ,f:»s-fc, shift ™» Scrub f-as A,c'd ras
Preparation ' ' -^ 600°F^ ijucncli Td6*F -^ ',*,,,,. ^
-ojsia 29.082 £& ,;»/, Treat JOOJr
T f f c t f r . f I
^^ Steam 1 Recycle Oil 1 Oil 3368 1 ¥
S°-raS U'78° ' "-640 ' W«er To Sulfur
' Oxygen Steam Recovery
3686 3244 /.955 282'' 2225
(41 MM SCKD)
(29.8 v X H2S)
Tail cas
Sulfur 7 { — *" Watcr to l)cusc
C02 H.70 41W
Flue 0aS •>-, 963
905 N« SCFD ,,20 „, ,-V Water
nil Sulfur » 2 — ^ Kfflucint
C02 14.7 v 7. Oxyf.en Nttro.on Air 73.600 MM SCFD 5'.26
. H20 15.9 3244 ' .5.,- Sulfur Wotci; Kvap. 27,120 tpd /— *-Al»ionIa 120
T °2 K1 f t f666 tfiSOOrgm) | ,. .
.V2 68.3 P^n ^1'l.enol
1 inn n 11 .1 1 | | I 16
Cool f nf.
Watcr
Utility Oxygen Sulfur Cooliny, Rccirt. •j"'1^
furnace plant Hecovory Tower 200,000 Kpn "''T
Treatinjt
(I A A From A A 4 From Acid A (_ J A
1 I U-Cas | | Removal [
_ .. ' ' 797 1 ???r> ' ii u, n.. ,
'3'u 260 MM SCFD
T "58 Btu/CK
Pi pel inc
5167
Composition vol 7
CM/, 93.0
M2 6.6
CO? 0. 1
CO' O.I
.V? 0.2
100.0
'reated water
A2.428
1
MA k cup
Water
Treat inj;
t
Frora u-(;as A ^ ct Alr 2.81 W! tpd 9715 Makeup x'ater
^7^ .....;
Ho-;c: Numbers .irp tons/Hnv
cxcoot «a noted
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HYGAS reactor. Sufficient oil is thereby recycled to give a slurry
containing 35% coal/65% oil, and cooling is provided so that tempera-
ture of the recycle oil is 400°F.
It should be emphasized again that this specific study case
does not include pretreating to destroy caking properties of the coal
feed.
4.2 Gasification
The HYGAS reactor has four zones, down through which the coal
passes in series countercurrent to rising gas. These include an initial
drying zone, followed by gasification zones at increasing temperature
and severity. Figure 2 shows this arrangement (18). Slurry feed is
dried in the upper bed at 600°F using heat in the raw gas. Vaporized
oil is condensed and most of it is recycled to slurry preparation, but
part of it is withdrawn as net product.
Dry coal then flows to the next bed at 1250°F where partial
gasification occurs. Volatiles will be released from the coal at this
temperature, including gas, oil, and tar. The oil can leave as vapor
from the upper bed and be condensed for use in slurry preparation. How-
ever, heavy tar will condense in the upper bed and remain on the coal
which is fed to the 1250°F bed. It will, therefore, tend to recycle
between these two beds and build up until it is destroyed by cracking
and coking in the 1250°F zone.
Char pases next to a bed at 17500F, and then to the bottom
zone where steam and oxygen are added for final gasification. Residual
char rejected from this lower zone may contain 10-30% carbon, correspond-
ing to 2-7% of the original carbon contained in the coal feed. The char
is slurried in water, depressured, and discharged through lock hoppers.
The countercurrent contacting between gas and char provided by
this multibed arrangement results in a considerable saving in oxygen. Of
the total methane in the product, 58% is formed in the gasifier by the
favorable effects of high pressure, temperature gradient, and the contri-
bution from volatile matter in the coal feed.
4.3 Quench and Dust Removal
Raw gas leaving the upper drying bed of the gasifier at 600°F,
is cooled to 400°F by contact with a recirculating oil stream, whereby
most of the oil is condensed out and returned to slurry preparation.
Temperature is maintained high enough to avoid condensing water which
could cause emulsion problems; moreover, the steam is needed for the
subsequent shift reaction. Heat removed in this cooling operation can
be used to generate low pressure steam by recirculating the 400°F oil
through waste heat boilers.
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FIGURE 2
HYGAS REACTOR
(From Reference 18)
COAL
SLURRY
STEAIV
OXYGEN
I>
GASIFIER
600 F
1250 F
1750°F
1200PSIG
1900°F
I
DRYING ZONE
LOW TEMPERATURE
REACTION ZONE
HIGH TEMPERATURE
REACTION ZONE
SYNTHESIS GAS
GENERATION
ZONE
WATER
'QUENCH
RAW GAS TO
PURIFICATION
AND
METHA NATION
•^•CHAR REMOVAL
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When the oil is condensed upon cooling, most of the dust in
the raw gas leaving the drying bed will also be removed. Since the
condensed oil is recycled and used for slurrying coal feed, the fines
will also be recycled and buildup in concentration, unless some provi-
sion is made to purge them from the system.
4.4 Shift Conversion and Cooling
The next step in gas handling is shift conversion, to react
part of the CO with steam and thereby increase the H2/CO ratio to 3/1
as needed for methanation. A sulfur resistant shift catalyst such as
cobalt-molybdenum is used, and one-third of the raw gas bypasses the
catalytic reactor. The catalyst is also exposed to oil vapors contained
in the gas, and operates at about 700°F.
After shift conversion, the gas is cooled to condense most of
the moisture, and at the same time remove ammonia, phenols, cyanides,
and light oils, etc. This sour water is cleaned up for reuse by extrac-
tion and stripping, which operations will be described in Section 4.7
Auxiliary Facilities. The light oil condensed at this point is sep-
arated from the sour water and removed as a by-product, or it may be
recycled to slurry preparation.
4.5 Acid Gas Treatment
At this point, the gas still contains various contaminants
that must be removed, such as: H2S, COS, C02, and condensable hydro-
carbons. The required cleanup is accomplished by scrubbing with
refrigerated methanol, using the Rectisol process. Gases containing
the sulfur compounds removed in the Rectisol unit are sent to a Glaus
plant for sulfur recovery. The Claus plant also provides incineration
of COS and combustibles on this stream.
Most of the C02 is removed as a separate stream in the Rectisol
regeneration, and indicated to be discharged to the atmosphere. However,
this vent stream is shown as containing over 2.0 vol. % of combustibles,
most of which is ethane; consequently, it will require further cleanup
or incineration. While sulfur content is indicated to be low, nil t^S
and 300 ppm COS, other detailed evaluations of similar Rectisol applica-
tions show that additional controls will be needed—as a minimum,' '
incineration, and possibly a modified processing scheme using a different
type of sulfur plant (3,19,20,21).
It is not clear that any one simple process for acid gas treatment
available today can simultaneously meet the targets of a highly concentrated
stream to the sulfur plant, together with a C02 waste stream that is clean
enough to discharge directly to the atmosphere, without further treatment
such as sulfur cleanup or incineration. Therefore it appears that addi-
tional facilities will be needed, such as adsorption by molecular sieves
or activated carbon to clean up the C02 vent stream.
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A guard bed, for example of zinc oxide, is used to remove re-
maining traces of sulfur in the clean gas, so as to protect the methana-
tion catalyst, which is extremely sensitive to sulfur poisoning. Reheat-
ing is needed since the guard bed operates at about 600°F, and can be
provided by heat exchange with gas leaving the methanator. Such preheat
is also needed to initiate the methanation reaction when this is carried
out in a fixed bed of catalyst.
4.6 Methanation and Drying
Fixed bed catalytic reactors with conventional nickel base
catalyst are used to react CO and H2 to form methane and water. Operat-
ing temperature is 550-900°F. Outlet gas at 900°F is recycled to the
inlet through waste heat boilers which generate steam, thereby recover-
ing the large exothermic heat of reaction. Heat release amounts to
954 MM Btu/hr, which can generate about 1 million Ib/hr of high pressure
steam.
Water formed by the methanation reaction is condensed and re-
covered when the product gas is cooled, providing 200,000 Ib/hr of clean
condensate suitable for boiler feed water makeup. Final drying of the
gas is effected by scrubbing with glycol, to meet pipeline specifications
of 7 Ib/MM SCF. The product specification of 0.10 vol. % CO maximum is
met by providing effective control of methanation and excess hydrogen,
leaving 6.5 vol. % hydrogen in the product gas. High heating value
is then 960 Btu/CF.
4.7 Auxiliary Facilities
To make the plant complete and self-sufficient, various
utilities and auxiliary facilities are needed in addition to the main
gasification process. A Glaus plant is used for sulfur recovery on a
concentrated stream from acid gas removal, with tail gas cleanup by
incineration followed by scrubbing with sulfite to remove S02, using
the Wellman-Lord process (8). The Rectisol design basis provided shows
29.8 vol. % H£S in the feed to the Glaus plant, while at the same time
the C02 vent gas contains no t^S and 300 ppm of carbonyl sulfide. This
would represent a very desirable high concentration of feed to the sul-
fur plant together with complete removal of ^S from the COo vent gas,
although the latter contains an excessive amount of COS plus 2 vol. %
combustibles, so it would require incineration.
Oxygen for gasification is supplied by a conventional air separa-
tion plant. While it does not generate contaminated waste streams, it is
a large consumer of utilities, with a correspondingly large impact on thermal
efficiency for the overall process.
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- 12 -
Large amounts of steam and power are needed in the process.
These are supplied by a utilities system fired with clean gas fuel manu-
factured by the U-Gas process being developed by The Institute of Gas
Technology. This U-Gas process has been described in the literature
(13,16,17).
In the U-Gas process, coal feed goes first to a pretreating
reactor to destroy caking properties (14). Here it is contacted with
air at 750-800°F in a fluid bed to give partial oxidation, accompanied
by a decrease in volatiles. A very large amount of heat is released,
which is used to generate steam. Hot char then goes to a second reactor
where it is gasified with steam and air at 1800°F and 300 psia in a
fluid bed. Off gas from pretreating, with a high heating value of only
39 Btu/CF, contains tar and sulfur, so it is mixed with hot gases from
the gasifier in order to destroy the tar.
Sulfur removal is provided at high temperature by contacting
the gas with a "molten metal", which is regenerated in a separate
zone by reacting with air to form a concentrated S02 stream that is
sent to the sulfur plant.
After further clean up by cooling to condense water and by
scrubbing, the gas is used as clean fuel for coal drying, furnaces, and
gas turbines.
A combined cycle system is used to maximize efficiency by first
burning the high pressure fuel gas from the U-Gas unit for use in a gas
turbine, and then discharging the hot exhaust to a boiler furnace which
supplies process steam. Combined cycle systems may be a very effective way
to supply by-product power for the oxygen plant compressors and for
generating electricity.
Water treatment is an important part of the process. As in the
Lurgi and Synthane gasification processes, considerable oil, phenols, etc.,
leave the HYGAS reactor and must be removed and disposed of in the gas
cleanup section. A similar arrangement is used for this purpose, consisting
primarily of a Rectisol unit for gas cleanup, and a Phenosolvan unit to
remove phenols from the sour water. The latter effectively removes low
molecular weight phenols as a by-product, but may be less satisfactory on
higher molecular weight phenols. Treated water from Phenosolvan then passes
to a sour water stripper which removes ammonia as a by-product, and H2S
which is sent to the sulfur plant. On the HYGAS process, details are not
available for utilities used by the Rectisol and Phenosolvan units.
Therefore, these were estimated by using information from the Lurgi plant
design prepared for the El Paso project, which includes similar operations
and processing units.
Other auxiliary facilities include treatment of makeup water,
boiler feed water preparation, storage of by-product oil, phenol, ammonia,
and sulfur, as well as ash disposal, and a cooling water circuit with
cooling tower. While the original design showed no net water effluent
-------
- 13 -
from the plant, this would lead to unacceptable buildup of dissolved
solids, etc., in the cooling water circuit, since salts in the makeup
water build up due to evaporation in the cooling tower and there is no
way for them to leave the system. Therefore, we have added a nominal
amount of discharge, and have increased the makeup water requirement
accordingly.
Information is not available on sour water composition in the HYGAS
process, but pilot plant data have been reported (22) for the Synthane pro-
cess which may be comparable. Some results have also been reported for a
commercial Koppers-Totzek plant (23). In the original HYGAS design, gas
liquor form the Phenosolvan unit was processed for ammonia recovery and then
sent directly to the cooling tower. However, it is estimated that this water
may contain 100 ppm or more each of residual ammonia, phenols, and fatty
acids, together with some H2S left after sour water stripping. A similar
situation in the design for the El Paso gasification project shows 100 ppm
of free ammonia and 500 ppm of phenols in the treated water (3). These
material might be stripped out in the cooling tower, causing undesirable
odors and contamination of the large volume of air flowing through.
Experience shows that part of the contaminants in the water can be
removed by biological action in the cooling water circuit. This necessarily
results in generation of cellular material, sludge, and algae, which foul,
the cooling tower and exchangers; consequently, additives are usually
introduced to inhibit biological action. In order to avoid such complica-
tions, the design was modified to process the water in a biox unit before
sending it to the cooling tower.
-------
- 14 -
5. EFFLUENTS TO ATMOSPHERE
Environmental aspects of the process will now be discussed,
together with possible control techniques in order to assure adequate
pollution control. The various streams will be considered as shown in
Figure 3, in the order of processing steps used in the section on
Process Description. Table 1 shows the amounts and characteristics of
all effluents from the process and auxiliary facilities.
5.1 Coal Preparation
A first consideration is the handling and storage of large amounts
of coal feed. Delivered coal must be loaded on conveyors, with transfer
to and from storage piles. Such operations necessarily tend to create
problems due to noise, dust nusiance, and spills. These facilities should
be enclosed as much as possible, with plans and equipment provided for
cleanup. A dust collection system is desirable, operating at below atmos-
pheric pressure to collect vent gas and pass it through bag filters. Storage
piles are an additional concern since wind can disperse the fine particles.
In some cases consideration has been given to covering the coal pile, or
coating it with for example heavy tar. The pile is very large, over 500,000
tons for 30 days storage, requiring an area of about 10 acres. Coal piles
are also liable to spontaneous combustion, calling for special attention
and plans for control, together with provision for extinguishing fires if
they occur (24). The obnoxious fumes, sulfur, and odor from this type of
fire is well known. Previous reports in this series include further dis-
cussion of the general subject (e.g. 5) but for any specific project, a
very careful and thorough evaluation and definition of facilities is needed.
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 from the standpoint of
personnel inside the building.
It should be noted that the present design is based on receiving
cleaned coal, so that environmental considerations for the cleaning opera-
tion will be transferred to a different location. Coal cleaning and washing
results in rejection of a large amount of refuse and fines, often 25%
of the mined coal, with major environmental impacts as discussed in previous
reports in this series.
Coal is crushed through 8 mesh and fed to a fluid bed dryer
where essentially all moisture is removed. Since the fluid bed provides
good contacting and temperature control, the heating gas can be introduced
at a relatively high temperature without overheating coal particles and
releasing volatiles. To maximize fuel efficiency, combustion should be
with minimum excess air (e.g. 10%) and dryer offgas can be recycled to
temper the hot gas to about 1000°F before it enters the fluid bed. Low
excess air also decreases the volume of vent gas compared to some other
drying systems that may use as much as 100% excess air in order to facilitate
-------
FTGURE 3
EFFLUENTS AND STREAMS FOR HYCA.S PROCESS
Coal Feed__
>>
2345
* H f
III
Jill
Coal
Prcparatlor
ttff
21 22 23 24
Dry Coal __
>
2
^
f
5
6
1
Slurry
Preparation
Coal
Slurry
1
7
4
r:aslfi-
cat ton
t I 1
2? ?i 24
Raw
Cas
8 9 10 11 12 13 14 1516 17 18 19
44* A* 4 M f 4 * 4
I ! ! II 1 ! : 1 ! 1 !
Oil
Quench
Cooled
Cas
Shift
Shifted
Cas
Scrub
1 1
3(5 3!
Clean
fas
Acid
Gas
Treat
Free
Cos
I I
32 33
PI pel ine
SNC 20
34 35 36 37
ttit
U-Gas
?
Utility
Furnace
39 40
t t
Oxygen
Plant
41 42 43
4 * *
• i i
Sulfur
Recovery
66 65 66
4 f 4
! 1 .'
Cool Ing
Tower
67 68 6Q
tit
50 51 52 53
4444
i « i •
Waste
Water
Treat inj;
y y J6 y
i I I 1
58 5" 60
f * *
1 i :
Makeup
Water
Treating
61
67
f Tm TIT TT
69 ^0 ^1 72 h 74 75 76 ?l? ?lg ^
go g,
Note: Effluents released to the environment are ihown bv heavy dashed line:
other streams are returned to the nrocess. See Tab'e ' for details.
-------
- 16 -
TABLE 1
EFFLUENTS AND STREAMS FOR HYGAS PROCESS
Stream Identification
1 Coal Feed
*2 Wind
*3 Rain
*4 Flue Gas
5 Coal Fines
6 Flash Gas
*7 Char Slurry
Flow Rate Tons/Day
17,517
e.g. 6" in 24 hrs.
114 MM SCFD
e.g. 175
Comments
1667 Char
8 Quench Oil
*9 By-Product Oil
*10 Fine Solids
11 Light Oil
12 Sour Water
13 Sulfurous Gases
23,640
338
3368
9678
2225
Total coal to plant - 6.5% moisture
Wind can pick up and disperse fines
from coal storage and handling.
Rain will wash fines from coal
preparation area and should be collected
and sent to separate storm storage pond.
Vent gas from coal dryer. Clean gas
fuel is fired, but dust must be
recovered, e.g., by bag filters,
scrubbing, etc.
Fines recovered from dryer gas may be
returned to U-Gas agglomerating reactor.
Gas and vapors released when hot recycle
oil is depressured and mixed with coal
feed, must be recovered and returned to
system.
Due to low density and open structure
of char, as much as 16,000 tons/day of
water may be needed to form a fluid
slurry. Part of this water may be
recovered by draining for reuse, but
much of it may be retained in the char
structure.
Light oil recycled to slurry preparation.
Net light oil by-product.
Purge of ash, coal fines, volatile trace
elements, etc. that accumulate in oil
quench recycle system and must be purged
to prevent undue buildup.
Oil vapors are condensed in scrubber,
separated from water layer, and returned
to quench system.
Scrubber water containing compounds of
sulfur, nitrogen, and oxygen. Processed
in waste water cleanup section for reuse.
From acid gas treatment - sent to sulfur
plant. Based on 30% H2S content.
-------
- 17 -
TABLE 1 (Cont'd)
EFFLUENTS AND STREAMS FOR HYGAS PROCESS
Stream
Identification
*14 C02 Vent Gas
*15 By-Product Oil
16 Waste Water
*17 Chemical Purge
18 Condensate
*19 Water Purge
20 Pipeline Gas
21 Wind
Flow Rate Tons/Day
13,726
Comments
22
23
24
25
26
27
28
29
30
Rain
Gas Fuel
Air
Coal
Oil
Steam
Oxygen
Water
Steam
140
37
2520
5167
e.g. 6" in 24 hrs.
33 MM SCFD
38 MM SCFD
3686
23,640
11,780
3244
e.g. 16,000
4955
Must be discharged to the atmosphere but
requires cleanup to remove combustibles
by incineration or adsorption, etc.-
could be treated by passing through
utility furnace.
Mainly benzene. Separated in Rectisol
unit and removed as by-product.
Separated from gas in Rectisol operation
and sent to waste water treating.
Methanol consumption in Rectisol unit
is estimated at 13 tons/day and
definition is needed as to where it
leaves.
Clean water produced by methanation
reaction - used for boiler feed water.
Removed in glycol dryer to meet SNG
requirement.
Product SNG, 960 Btu/CF HHV.
(260 MM SCFD).
Wind action on coal storage and
handling area.
Rain onto storage pile can pick up
acids, organics, fines, etc.
Clean low Btu gas fired on coal dryer
(from U-Gas).
Combustion air to coal dryer.
Dry coal to U-Gas unit.
Quench oil recycled to slurry
preparation.
High pressure steam to HYGAS reactor.
Oxygen to HYGAS reactor.
Water used to quench and slurry spent
char for depressuring and disposal.
(See item 7).
Added to shift reactor to convert
CO to C02 + H2-
-------
- 18 -
TABLE 1 (Cont'd)
EFFLUENTS AND STREAM FOR HYGAS PROCESS
Stream
Identification
31 Water
32 Chemicals
33 Glycol
34 Fuel Gas
*35 Char Slurry
*36 Dust
37 S02 Stream
*38 Flue Gas
39 Oxygen
*40 Nitrogen
*41 Tail Gas
*42 Sulfur
*43 Chemical Purge
Flow Rate Tons/Day
2824
13
482 MM SCFD
450 Char
Comments
797
905 MM SCFD
3244
10678
2931
666
Recirculated water added to scrubber for
dilution.
Methyl alcohol makeup added to Rectisol
unit.
Small amount of makeup to glycol dryer
on product gas.
Clean gas to supply plant fuel require-
ments. Made in U-Gas process by coal
gasification with steam and air.
Spent char from U-Gas unit is quenched
and slurried in water for disposal.
See item 7.
Recovered from product gas on U-Gas
unit, as required to meet gas turbine
requirements and emission standards.
May be returned to system. May contain
some metal or chemical used to
desulfurize raw gas.
From regeneration of sulfur acceptor
on U-Gas unit. 21 vol. % S02 and
79 vol. % N2.
Flue gas from utility furnace after
combined cycle turbines. Should be low
in sulfur and dust, but NOX should be
controlled.
From oxygen plant - used in gasifier.
Waste nitrogen to atmosphere. Should be
clean.
Waste gas from sulfur plant after tail
gas cleanup by Wellman-Lord process.
By-product sulfur from sulfur plant.
Chemicals are used in sulfur plant.
Sulfite scrubbing for tail gas cleanup
requires purge containing sodium sulfate
etc. May go to waste water treating.
-------
- 19 -
TABLE 1 (Cont'd)
EFFLUENTS AND STREAMS FOR HYGAS PROCESS
Stream Identification
*44 Air
45 Cooling Water
*46 Chemical
47 Treated Water
*48 Net Water Discharge
49 HS Stream
Flow Rate Tons/Day
73,600 MM SCFD
200,000 gpm
Comments
4155
5424
*50
*51
*52
*53
By-Proi
Phenol
Oil
Sludge
120
16
20-60
*54 Chemicals
*55 Trace Elements
*56 Water Evaporation
*57 Spent Char
See Text
Section 9
See item 7
2117 dry
Air from cooling tower containing
evaporated water (27,120 tons/day).
Will also carry mist of water drops
which may amount to 1200 tons/day.
Water from cooling tower recirculated
to process heat exchangers.
Chemicals are used in cooling water
circuit to control corrosion, algae,
etc. and must appear in the effluent.
Water for reuse after treatment.
Water effluent from plant to reject
soluble salts. Disposal of this stream
may present problems and more definitive
information on composition is needed.
Gases from sour water stripper sent to
sulfur plant for incineration and
recovery.
Recovered from sour water using Phosam
process.
By-product recovered from sour water
using Phenosolvan process.
Recovered in oil separator on waste
water treating system.
Cellular material from biox reactions.
Should be incinerated to avoid odor
problems.
Used in Phosam process. Purge streams
must be defined so that disposal can
be specified.
Volatile trace element will accumulate
in cleanup system and must be
deactivated and disposed of.
Evaporation from pond where char slurry
is sent for draining and drying. May
be odor problem.
Combined drained char from HYGAS and
U-Gas units. Will also contain moisture.
-------
- 20 -
TABLE 1 (Cont'd)
EFFLUENTS AND STREAMS FOR HYGAS PROCESS
Stream
Identification
58 Treated Water
*59 Sludge
*60 Chemical Wastes
61 Coal
62 Air
63 Steam
64 Air
65 Quench Water
66 Sulfur Acceptor
67 Fuel Gas
68 Air
69 Air
70 H2S Stream
71 S02 Stream
72 Air
73 Chemicals
74 Air
75 Water
76 Chemicals
Flow Rate Tons/Day
42,428
e.g. 10-20
Comments
3286
11,739
2560
651
ca. 4000
444 MM SCFD
533 MM SCFD
13,922
2,225
797
575
73,600 MM SCFD
(2.8 MM Tons/Day)
200,000 gpm
Make up water to plant.
From water treating using lime, alum,
etc.
From water treating, including acid
and caustic use in boiler feed water
demineralization.
Feed to U-Gas unit.
Air for gasification in U-Gas unit.
To U-Gas unit.
Used to regenerate sulfur acceptor
that removes sulfur from raw gas on
U-Gas unit. (Gas is sent to Glaus
unit for sulfur recovery.)
Used to quench and slurry spent char
for transport to settling pond.
See item 7.
Makeup metal or chemical used to
remove sulfur from raw gas.
Clean fuel gas to utility boiler.
Combustion air to utility boiler.
Air used to make oxygen.
From Rectisol unit for acid gas
treatment of raw gas.
From air-regeneration of sulfur
acceptor in U-Gas unit.
Supplemental air needed to complete
Glaus reaction.
Sodium sulfite tec. used in Wellraan-
Lord unit for fuel gas cleanup.
Air to cooling tower.
Cooling water circulated through
cooling tower.
Treating agents used in cooling water
circuit, e.g. chlorine to control
algae and chroraate to control corrosion.
-------
- 21 -
TABLE 1 (Cont'd)
EFFLUENTS AND STREAMS FOR HYGAS PROCESS
Stream
Identification
77 Waste Water
78 Chemical
79 Chemical
80 Water
81 Chemicals
Flow Rate Tons/Day
9715
Comments
42,428
Sour water from gas cleanup system to be
processed for reuse.
Makeup to phenol extraction system
(Phenosolvan). May be isobutyl ether.
Makeup to ammonia recovery unit
(Phosam) e.g., phosphate.
Makeup water to plant.
Used for treating makeup water.
Includes lime, alum, ion exchange
resin, sulfuric acid, and caustic.
These streams are emitted to the environment, others are returned to the process.
-------
- 22 -
drying. Low excess air results in higher moisture content of the gas,
but this disadvantage is more than offset by decreases in fuel consump-
tion and volume of vent gas to be cleaned up. Volume of dryer vent gas is
114. MM SCFD, or about half as much as the SNG product. Moisture content
is 51 vol. %. Although the drying system is not described in the references,
the fluid bed can be operated with a coal temperature of 250-300°F to give
adequate drying, but maximum allowable coal preheat is limited by the need
for forming a slurry at 400°F for pumping.
About 77% of the dried coal goes to gasification, while the
remainder is used to supply plant fuel requirement after being processed
in a U-Gas unit which converts the coal to clean low Btu gas fuel. Part of
this gas is used as fuel for coal drying, consequently the dryer vent gas
does not require sulfur removal, although dust cleanup is needed and can be
provided by bag filters, scrubbing, or electrostatic precipitators. Odor
of the dryer vent gas may be a problem, particularly if the operation is
on lignite or a reactive coal. This question needs to be answered in the
pilot plant program.
The next step in this section of the process is to mix recycle
oil with the coal feed for pumping into the high pressure gasifier. Any
flash gas released during slurry formation must be recovered and used, or
incinerated. Slurry concentration is about 35 wt.% coal/65 wt.% oil,
and reciprocating pumps are indicated to raise the pressure to 1200 psia.
5.2 Gasification
A series of complex operations are involved in gasification,
including handling of slurry and hot fluidized solids at very high tempera-
tures. Careful consideration should be given to potential problems due to
leaks, spills, upsets, etc., as well as scheduled shutdown and maintenance.
The major effluent from gasification during normal operation is the
residual char, containing ash that comes in with the coal feed.
This char, containing 10-30% carbon, is quenched with water,
depressured by lock hoppers, and sent to an ash settling pond. Steam formed
by this quenching operation may contain particulates and other contaminants,
consequently it should be returned to the process or collected for disposal.
The amount: of steam is approximately 50,000 Ib/hr. In the operation as
intended, there should be no serious emissions to the atmosphere; however,
the system may be difficult to operate and maintain due to plugging or
erosion of valves, and any failures or upsets could cause serious environ-
mental emissions.
Ash in the water slurry is recovered in a settling pond, which
is drained so that semi-dry ash can be removed for burial. Although wet ash
is not dusty, parts of the settling basin or spills on the ground can dry
out and become a dust nusiance, as has happened in the past.
The nature of this ash or char warrants further discussion. If
the original coal particles maintain their size during gasification, then
their density will decrease as the carbonaceous content falls to the indi-
cated 10.3% carbon. On this basis, a char density of only 11.24 Ib/cu. ft.
-------
- 23 -
is calculated for a coal feed of'1.40 specific gravity and 11.54 wt.% ash.
Obviously, the particles will not only be light, but friable as well.
Therefore, additional information should be obtained on the depressuring,
handling, and disposal operations in order to assure that problems are
satisfactorily resolved.
If the char particles break up, then very fine dust -may result,
with complications in the ash handling and disposal. Alternative approaches
to this problem have used sintering of fly ash or an agglomerating fluid
bed system (25,26), or a slagging gasifier (1,5).
Attrition of particles in the HYGAS reactor will generate fines
that are carried up with the gas stream. These fines will probably be
removed rather completely by the oil quench system, thus tending to build
up in concentration in the recycle oil unless they are removed by agglomer-
ation, filtration, or other means. Similarly, volatile trace elements
such as arsenic, lead, and cadmium will accumulate in the recycle oil,
requiring separation as will be discussed in the section on trace elements.
5.3 Quench and Dust Removal
Gas from the gasifier, together with slurry oil evaporated in
the drying zone is quenched to 400°F by direct contact with recirculated
oil, the heat being used to generate steam in waste heat boilers. Most
of the oil vapor in the entering gas is condensed and recycled to slurry
preparation, while at the same time particulates and condensibles such
as certain trace elements will be removed from the gas and accumulate in
the oil. While most of the oil is recycled, part of it must be withdrawn
as product and can be expected to contain toxic elements such as arsenic,
lead, and cadmium, as well as particulates, phenols, sulfur and nitrogen
compounds, etc. Therefore properties of this oil and its projected use
need further evaluation to define what treatment may be required to make
it suitable for use as fuel, or as a raw material for refining.
Due to safety considerations and the possibility of emulsions,
quench temperature is maintained above the water dew point. Steam will
not condense unless a high concentration of steam inadvertently occurs,
as for example during startup or upsets.
5.4 Shift Conversion and Cooling
The next step in the gas processing sequence is to shift the CO
by reaction with steam to make hydrogen. This catalytic operation may also
give some hydrogenation to help remove olefins, cyanides, and oil vapor.
It may also be possible to modify the shift reactor so as to hydrolyze
carbonyl sulfide and other compounds to form I^S which is removed more
easily in acid gas treatment. Some deposition of trace elements and coke
is expected on the shift catalyst, consequently it should be reprocessed
periodically or properly disposed of.
In the scrubbing operation to remove dust, the gas is cooled to
125°F, condensing out most of the water vapor remaining in the shifted
gas. Ammonia, cyanides, phenols, oil, etc., will be present in the sour
water, similar to the cases of Lurgi (3) and Synthane (2), in fact the
-------
- 24 -
processing sequence is quite similar to proposed plants using Lurgi
technology (3,19,20). The major effluent from this area is the gas liquor,
handling of which will be discussed in Section 6.4, but it should be noted
that when this water is depressured, gases are released that must be recovered
or incinerated. In addition, sour water stripping produces by-product
ammonia, and H2S which can be sent to sulfur recovery.
5.5 Acid Gas Treatment
In this section of the process, the bulk of contaminants remain-
ing in the gas are removed. Major constituents are acid gases, H2S (1.44
vol. %) and C02 (30.85 vol. %), while minor contaminants include HCN,
ammonia, light hydrocarbons, naphtha, etc. Ideally, acid gas treatment
should remove all contaminants to a low level, while giving both a concen-
trated sulfur containing stream to the sulfur plant together with a C02
waste stream that is sufficiently pure so that it can be vented directly
to the atmosphere without further treatment.
The IGT design uses a Lurgi Rectisol system for acid gas treat-
ment, based on scrubbing with refrigerated methanol. The design shows
30 vol. % concentration of sulfur compounds in the gas fed to the Glaus
Plant, which represents a desirably high concentration to allow efficient
sulfur recovery. Other Rectisol designs for commercial projects (19) show
much lower concentrations, less than 2 vol. %. These designs remove H2S
and C02 together, resulting in a dilute H2S stream that is not suitable for
a conventional Glaus plant. It is understood that the Rectisol process can
be designed to remove the H.2S as a separate stream at high concentration,
although the utilities consumption may be increased. In any detailed
specific evaluation, special attention must be given to design basis to
assure that the process efficiency used is consistent with costs and
economics, utilities consumption, and environmental effects.
The C02 rejected to the atmosphere is a very large stream, the
tons/day exceeding total coal used by the plant. Therefore, it must be
particularly free of undesirable contaminants. Unfortunately, methanol
scrubbing is indicated to give about 2% combustibles in this C02 waste
stream, including 1.46% ethane, and 300 ppm carbon monoxide, and 300 ppm
COS. Other related information (3, 19, 20) confirms that the C02 waste
will require further cleanup, possibly with incineration. Sulfur content
at 300 ppm is moderate, amounting to less than 1% of Sulfur in the coal to
gasification, and would appear acceptable in some cases depending on standards
that apply for a specific location, at least if it is in a less objectionable
form such as S02.
Combustible content is more of a problem. Heating value in the
C02 vent gas is about 270 MM Btu/hr., or 2% of the heating value in the coal
to gasification, so it should not be wasted. On the other had, extraneous
fuel, or effective preheat, would be needed to maintain a minimum incinera-
tion temperature of say 1500°F, which corresponds to a heat load of 440 MM
Btu/hr.
Other methods of acid gas removal, such as scrubbing with amine
or hot carbonate, also have difficulty in providing a C02 purge stream that
is clean enough to vent directly to the atmosphere. Further work on this
problem would be very desirable, for example to develop a simple inexpensive
way to clean up the C02 vent stream. Contaminants to remove include com-
bustibles, carbon monoxide, plus carbonyl sulfide and other sulfur compounds.
-------
- 25 -
One possible approach is to pass the CC^ stream through the combus-
tion zone of a furnace, such as the utility boiler. This would provide
incineration of combustibles with recovery of useful heat. If the boiler
already had stack gas cleanup, sulfur emissions would also then be
controlled, so that requirements in acid gas treatment would be less strin-
gent. A further advantage is that combustion temperature would be decreased
by the added CC>2 stream, thereby decreasing NOX formation. A disadvantage
however is that the C02 stream is large, increasing the total volume of flue
gas by about one-third. Assurance is needed that the C02 vent stream will
be clean, so further study and evaluation of alternatives is called for.
While the major gas emissions have been discussed, it should be
recognized that there can be other effects associated with depressuring or
handling other streams in acid gas treatment, such as separated water, oil,
etc. , or waste chemicals that may be discharged. Also, utilities consumption
for acid gas treatment is large; it is often the largest single consumer
in the plant.
5. 6 Methanation and Drying
As covered by the process description in Section 4.6, methanation
and drying is carried out in a closed system, with no streams normally
emitted to the atmosphere. The large heat release is used to make steam,
generally by recirculating reactor outlet gas through waste heat boilers.
Careful attention is required in design and operation to control leaks
from this system. In addition, gas released when depressuring water
produced, or when depressuring equipment for maintenance should be collected
and recovered or incinerated.
5. 7 Auxiliary Facilities
The complete plant includes auxiliary facilities one of which is
a sulfur plant to make by-product sulfur from sulfur compounds removed in
various cleanup operations. A Glaus plant is used for this purpose, with
tail gas cleanup by sulfite scrubbing using the Wellman-Lord process.
Feed to the Claus plant is mainly an K^S stream from acid gas
treatment, plus an S02 stream from the U-Gas unit producing clean plant
fuel. .The former contains 30 vol. % sulfur compounds (nearly all H2S) ,
while the latter has 21% S02 plus 79% N2 from regenerating the molten metal
used to desulfurize the fuel gas. Some additional SC^ comes from the tail
gas cleanup system.
These feed streams are combined and reacted with additional air
to form sulfur which is recovered. Tail gas cleanup is specified to give
a total sulfur of 250 ppm as S02 in the gas released to the atmosphere,
which should be satisfactory for most plant locations. There are no other
primary emissions from the sulfur plant, but special precautions should be
taken to control leaks, vents from sulfur storage, etc. , and to avoid
offensive odors. I^S is appreciably soluble in molten sulfur, but there
are well established techniques for control.
-------
- 26 -
Oxygen production is not expected to cause undesirable emissions
to the air, the main effluent being waste nitrogen. However, being a large
energy consumer, it affects the size of the utilities system and the amount
of waste heat to be dissipated to the environment.
A major concern on emissions to the air is from the system used
to provide plant utilities. The utility boiler is an important factor,
discharging a volume of flue gas 3.5 times the volume of SNG product.
In this case it is expected to be free of particulates and very low in
sulfur, since clean gas fuel is supplied from the U-Gas system. There is
still the question of NQx formation, although this will tend to be lowered
by the fact that low Btu fuel is used (151 Btu/scf), thereby giving a
relatively low flame temperature. The exact amount will depend on the
furnace design, use of staged combustion, etc., and should be defined for
specific process applications to be sure that applicable standards are met.
A large part of the fuel gas will be used first to drive gas
turbines as part of the "combined cycle" operation. Since this improves
efficiency, it should tend to reduce plant emissions.
Clean low Btu gas for plant fuel is provided by the U-Gas unit
which gasifies high sulfur coal using air and steam. Required cleanup
facilities are included in this section to remove sulfur, tar, dust, and
other pollutants. The large size of this operation makes it especially impor-
tant in evaluating environmental impacts. The primary gas product is
contained and treated within the system, without specific emissions to the
atmosphere. However, contaminants are withdrawn as a liquid effluent con-
taining water, sulfur, nitrogen, and oxygen compounds, as well as oil, tar,
and particulates. This stream must be contained and handled in a way to
avoid undesirable emissions or odors. In addition, spent char which is
withdrawn from the U-Gas unit could cause a dust nusiance unless proper
precautions are taken in handling and disposal. It is presumably similar
to char from the main gasifier, so a common disposal system might be used.
In addition, there is a drift loss due to mist carried out by the
air. A typical estimate of this would be about 200,000 Ib/hr, although it
could be reduced considerably by using some of the new techniques that are
being developed to control drift loss from cooling towers (27). Drift
can cause deposits in the nearby area due to dissolved solids in the cooling
water. Careful consideration should also be given to the potential fog pro-
blem or plume associated with cooling towers due to condensation under
unfavorable atmospheric conditions. One way to avoid the plume is to provide
reheat on the air leaving the cooling tower, but this will not normally be
warranted. It may be that these problems can be taken care of by proper
design and placement of the cooling tower.
Normally, there will not be contaminants introduced into the
cooling water circuit that might be stripped out by the air flowing through
the cooling tower. However, experience has shown that leaks can be expected
-------
- 27 -
in exchangers used in cooling water service, especially at high pressures
such as the 1000 psig in this process. Leaks, for example, in exchangers
on sour water service could introduce sulfur, cyanide, and ammonia into
the cooling water, which would then be stripped out into the air. Special
precautions and possibly monitoring equipment may be needed from this
standpoint.
In the areas related to use of water, by far the largest effluent
to the atmosphere is from the cooling tower. Flow of air through the cooling
tower is 74,000 MM SCFD, or nearly 300 times the volume of product SNG.
The volume of air passing through the cooling tower is so large that every
precaution should be taken to see that it does not inadvertently become
contaminated.
-------
- 28 -
6. EFFLUENTS - LIQUIDS AND SOLIDS
As in the preceeding section, effluents will be discussed in
the order in which they appear on the Figure 1 flowplan. Individual
streams are all identified on Figure 3 and described in Table 1.
6.1 Coal Preparation
This particular design assumes that the coal has been cleaned
before delivery, consequently the rejection of rock, gangue, or tailings
does not appear on the flowsheet. In applications where coal cleaning
must be provided at the plant, a considerable amount of refuse will have
to be disposed of. Similar designs for other processes (5) show for
example 20% refuse on delivered run of mine coal, equivalent to over
800 acre-ft/yr to dispose of. Moreover, coal washing requires a large
volume of water which must be sent to a tailing pond, cleaned up, and
reused. Leaching from solids, for example, by rain and seepage from ponds
are potential problem areas.
A further consideration on the coal preparation area is with
regard to the coal storage pile. The design includes storage for 30 days
minimum, or about 500,000 tons; so the coal storage pile will cover a very
large area. Rain run off can lead to undesirable effluents. A large part
of the rain can run off quickly and carry suspended particles, while the
remainder will have a long contact time with the coal and can pick up metals,
acids, and organics. Therefore, rain run off from the storage area should
be collected in storm sewers and sent to a separate storm pond. With a
certain amount of treatment, this water can then be used as make-up for
the process. Control of seepage may be desirable on the pond, and particu-
larly on the coal storage area, using for example a layer of concrete,
plastic or clay.
Coal drying can also contribute effluents. The drying gas will
pick up coal fines, which should be recovered by filtering, scrubbing, or
electrostatic precipitation for reuse in the process. Fines are undesirable
in the coal feed to HYGAS in that they readily blow out of the initial
drying bed and accumulate in the oil recycled to slurry preparation. One
possible use for the coal fines is as fuel in the coal dryer, to the extent
permitted by sulfur emission. Using some fines as fuel in the utility furnace
might be satisfactory, although fly ash recovery may have to be added. Perhaps
a better use for the fines is to gasify them in the U-Gas system so that all
fine ash is recovered. Adding the fines as a separate stream to the oxygen
gasifier at the bottom of the HYGAS reactor would also consume them, while
assuring that all ash is recovered.
In slurry preparation, coal from drying is mixed with hot recycle
oil. The latter must be depressured from over 1000 psig, which will no
doubt release vapors. These should be condensed and returned to the system.
Similarly, any residual moisture in the coal that flashes during slurry
preparation should be collected and returned to the process.
-------
- 29 -
6.2 Gasification
The major effluent from this area of the plant is spent char,
which serves to reject ash brought in with the coal feed. Some unreacted
carbon is also rejected in the char. Hot char from the gasifier is handled
by quenching in water, forming steam which is presumably returned to the
gasifier, and a water slurry (25% solids) which is depressured across an
oil field type choke (28). The slurry goes to a settling pond from which
water is recycled to the quench system. At intervals, the pond is drained
so that wet ash can be reclaimed for ultimate disposal offsite. There is
no water effluent from the ash system other than that retained by the ash,
but this may contain soluble salts or trace elements so further information
should be obtained on leachables from the wet ash. Exposure to air may be
a factor, and tests are needed to define to what extent leaching by rain
or ground water may be a problem when the char is disposed of by burial
or as fill. Potential leaching of calcium chloride, magnesium sulfate,
compounds of iron, manganese, fluorine, etc., are of concern.
It has been indicated that the char resembles activated carbon in
that it has adsorptive properties, and will remove phenol from waste water.
If used in this manner, the char could be regenerated, for example, by
returning it to the gasifier. In some cases it may be preferable to
discard without regenerating spent char used in waste water treating, in
which case additional assurance is needed that adsorbed materials will not
find their way into natural waters and cause problems.
Char from the gasifier is expected to have a low density and to be
friable. Severe turbulence associated with depressuring the slurry may
create very fine particles. Therefore, careful consideration is needed
of potential problems due to particulates in drainage water, in addition to
the potential leaching problem mentioned earlier. When the wet ash dries
out, dusting could also be a nuisance and requires evaluation, since this
has sometimes been a problem.
6.3 Quench and Dust Removal
In this section of the process, raw gas is cooled by direct contact
with product oil which is recirculated and cooled. At the same time, parti-
culates in the raw gas will be removed. While most of the oil is used to
slurry the coal feed, a stream of by-product oil is also withdrawn corre-
sponding to the net yield of oil from the coal gasification reaction. This
by-product oil, amounting to 338 tons/day is the only major effluent from
this section of the process. One possibility is to use it for fuel, but
considerably more information would be needed to determine whether it can be
burned directly, or whether it will first need further treatments to remove
contaminants.
As discussed in Section 4.3, the oil will pick up fines from the
gas, and if ash in the oil is over 0.2%, then it would exceed the 0.1 Ib.
of particulates per MM Btu specified for large stationery boilers. Ash
content may well be excessive since this is the only purge of fines that are
carried out in the raw gas leaving the drying bed of the gasifier. An ash
-------
- 30 -
content of 0.2% in the by-product oil would correspond to only .05 wt. %
of the ash in the coal fed to gasification, so to the extent that net
entrainment of coal fines exceeds this value, ash removal from the by-
product oil would be needed.
A further concern is the amount of other contaminants picked
up in the quench oil. It is known that many trace elements such as Hg,
As, Cd, Sb, etc., are partially volatile at gasification conditions. When
the gas is cooled, some of them may drop out, and accumulate in the gas
handling system, for example, in the quench oil. Some plant data on coal
gasification has shwon as much as 30-50 ppm each of arsenic and lead in
oil or tar by-products, raising major questions regarding subsequent use
and disposal of such materials. The subject is discussed further in
Section 9 dealing with trace elements.
6.4 Shift Conversion and Cooling
Shift conversion does not involve primary emissions or effluents,
although some trace elements and tarry materials may accumulate on the fixed
bed of catalyst used in this operation. However, subsequent cooling and
scrubbing of the gas condenses a large amount of sour water which must be
cleaned up and reused or disposed of. Some oil is also condensed and it is
returned to the oil quench system, after separation from the water layer.
If there is residual dust in the gas leaving the oil quench system, it will
also be removed in the scrubber.
As in other gasification processes previously evaluated for
environmental aspects, cleanup of the water layer, commonly called gas liquor,
is a formidable challenge. At this point in time, not enough information
is available on the HYGAS process to define the kinds or amounts of conta-
minants in the condensate from scrubbing. It is known that various sulfur
compounds including H2S will be present, as well as nitrogen compounds such
as ammonia, cyanides, etc., oxygen compounds such as phenols and fatty acids,
together with thiocyanates, chlorides, and other products of interaction.
In addition some of the volatile trace elements will also appear in the sour
water, particularly chlorine and fluorine, although their chemical form is
uncertain.
It is apparent that a great deal of additional information needs
to be obtained in pilot plant operations to define the problem adequately
so that effective measures for environmental controls can be specified. Phenols
can be largely separated by extraction (e.g. Phenosolvan process), while sour
water stripping will remove NH^ and HoS for recovery. Biological oxidation
(biox) may then be used for further cleanup of waste water, followed by
filtration, activated carbon, etc., as required.
6. 5 Acid Gas Treatment
The primary liquid effluent from acid gas treatment is naphtha
and oil which is recovered from the gas by scrubbing with refrigerated
methanol. This oil is returned to the oil quench system, and eventually
withdrawn as a by-product. As a result of the high cracking severity that
it has been exposed to in the gasification reactor, it will consist mainly of
aromatics such as benzene and should be useful as a raw material for making
chemicals or motor gasoline. Benzene is toxic, so proper precautions are
needed in its handling and storage.
-------
- 31 -
There is also a small amount of water rejected from acid gas treat-
ment, which can be combined with sour water from scrubbing for treatment.
Methanol makeup is needed on the Rectisol unit, a typical figure being
.03 Ib/MSCF feed gas, which corresponds to 13 tons/day of methanol. It is
not specified as to where this leaves the system, but it probably is mostly
in the rejected water, and can be consumed in the biox operation. There
should be no significant solid effluents from acid gas treatment, since
char and ash particles will be removed efficiently in the scrubber. The
large effluents of gases were covered in Section 5.5.
6. 6 Methanation and Drying
The methanation reaction also produces a large amount of water,
which is condensed and used for makeup to steam boilers. The amount, 2520
tons/day, is large relative to the net waste water effluent of 5424 tons/day
and thus makes an important contribution in the overall water balance. It
is very clean condensate, free of sulfur and dissolved solids, so little or
no treating is required on it. When it is condensed at high pressure, some
methane will be dissolved in it and may have to be removed. If the water is
depressured, most of the methane will be released and should be recovered
and returned to the system, or incinerated.
6.7 Auxiliary Facilities
One of the auxiliary facilities is a Glaus plant for sulfur recovery.
The sulfur by-product may be handled as either a solid or a liquid, and
methods are well established for handling it in a clean safe manner, for
example with regard to odors, dust, H2S release from molten sulfur, etc.
No other solid or liquid effluents are expected from the Glaus plant itself,
except for catalyst which is replaced periodically. There is also a separate
system for tail gas cleanup using the Wellman-Lord process based on scrubbing
with a sodium sulfite solution. Since some of the sulfite is oxidized to
sulfate, a purge stream of the solution is withdrawn and must be disposed of.
If 10% of the sulfur in the Glaus plant feed were to leave as sodium sulfate,
the latter would amount to 300 tons/day of salt. In addition, there may be
sodium sulfite present, particularly if purge represents part of the circu-
lating solution. If only sodium sulfate is purged, it might be sold, other-
wise there can be a sizeable disposal problem.
On the oxygen plant there are no major liquid or solid effluents,
although a small amount of water may be condensed from the entering air and
recovered for use as boiler feed water.
The utility furnace burns clean gas fuel and the major effluents
are gases, with no ash or slag. There will be water blowdown from the
boilers, but this can be added to the cooling water to provide makeup. It
is assumed that char from the HYGAS and U-Gas reactors will be low enough
in carbon content so that it can be discarded. If it were necessary to burn
it to recover heating value, then recovery of particulates would be needed
on that operation. The indicated carbon content of 10.3% on char corresponds
to about 1.5% of the heating value in the coal feed, while if the carbon
content were 30% it would then represent 5.7% of the heating value in the
coal feed and recovery of this would be desirable.
-------
- 32 -
Clean gas fuel for the utility boiler and the coal dryer is
supplied by a U-Gas unit, which includes scrubbing to remove particulates
and acid gas treatment to remove sulfur. A major liquid effluent from
U-Gas is sour water from scrubbing to remove particulates. It will be
similar to the sour water from HYGAS and contain a variety of sulfur,
nitrogen and oxygen compounds. Particulates could be removed by filtration
and settling, and the sour water might then be treated along with sour
water from gasification. There may also be tar and oil to remove in the
U-Gas cleanup system, since the operation uses pretreatment of the coal
feed to destroy caking properties. Pretreating generates considerable
tar, perhaps 4 wt. % on coal feed. Most of this will be destroyed in the
U-Gas design which provides for passing the pretreater off-gas through
the gasification reactor where it is held at about 1500°F for 10-15 seconds
to destroy tar (16). Even so, some oil or benzene may appear in the gas
cleanup system, especially during startup or upsets.
Another effluent from the U-Gas unit is spent char or ash. As
discussed earlier in this subsection, it is important that the carbon con-
tent be low enough so that it does not result in a significant loss of the
heating value in the coal feed. A carbon content of 10% or less would be
desirable from this viewpoint, but may cause operability problems due to
low particle density, or due to disintegration of the ash.
The cooling water circuit has a very important impact on the water
effluent from the plant. The large amount of evaporation serves to con-
centrate dissolved solids in the cooling water circuit. Moreover, chemicals
are added to the cooling water system, such as chromates to inhibit corrosion
of exchangers and equipment, chlorine to suppress algae growth, or other
additives. These chemicals appear in the water blow-down from the cooling
tower, and when they go the biox system can interfere with its operation.
Biological processes are often inhibited by less than 1 ppm of chromium or
copper, for example. In general, water blowdown will not be a direct
effluent to the environment, but rather will be processed first through
waste water treatment.
The major stream to waste water treating i§ gas liquor from
cooling and scrubbing the raw gas, after extraction of phenols and after
sour water stripping. Residual amounts of phenols, H2S, NH3 etc. are then
further decreased by biological oxidation.
Operability considerations make it necessary to have a net
discharge of waste water from the process in order to purge dissolved
solids. Some of these enter in the makeup water as sodium salts while
others may be formed during water treating or softening operations, or by
leaching from ash or refuse. Due to evaporation in the cooling tower,
dissolved solids can buildup in concentration to a level approaching
brackish water which would not be acceptable for discharge from the plant
at inland locations. For the basis shown on Figure 1, the amount of water
evaporated is 5 times the net effluent; consequently, dissolved solids
will increase by a factor of 6 at least over that in the makeup water.
One approach to this problem is to evaporate the water effluent to dryness
(e.g., in a pond) and store the salts or dispose of them in the ocean.
-------
- 33 -
Many trace elements are partially volatile in the gasifiers and
must be removed in the gas cleanup systems, thereby showing up in the net
effluents of liquids and solids from the plant. To a large extent, these
show up in the waste water (e.g., fluorine, arsenic, and chlorine). At
this time there is almost no information available to define the problem
or to outline treating methods that would recover or deactivate harmful
materials. It is unlikely that conventional waste water treating will be
satisfactory for this purpose. The subject will be discussed further in
Section 10 on trace elements.
A solid effluent from water treating is sludge from biox, which
may be several hundred tons/day of material having a high water content,
and difficult to filter. It might be disposed of as land fill if odor
problems can be controlled, or it could be incinerated although extraneous
fuel may be necessary.
The facilities for treating makeup water also generate sludge,
as well as various liquid effluents. In this case the sludge is inoccuous
and can be buried or disposed of with the char. Demineralization of boiler
feed water usually uses ion exchange resins which are back washed with acid
or alkali. These effluents can be combined and neutralized, but still
contribute to total dissolved solids in the waste water. In brief, all
chemicals used by the plant must also leave in some stream, and in many
cases they will leave in the waste water.
-------
- 34 -
7. SULFUR BALANCE
Of the sulfur entering in the coal feed, nearly all of it
appears in the raw gas leaving the gasifiers, from which it can be
separated and sent to the Glaus plant for sulfur recovery. The latter
gives 99% sulfur recovery with tail gas cleanup. The HYGAS design is
based on essentially complete recovery of all sulfur compounds by the
Rectisol unit, so that sulfur emission in the CC^ vent gas is very low-
much less than 1% of the sulfur entering with the coal. In addition,
the gas stream sent to the Glaus plant is very high in sulfur, equivalent
to 30 vol. % H2S, giving a high sulfur recovery. There is some question
as to whether this is completely consistent with'the utilities consumption
listed in Section 11. In the absence of detailed numbers, the latter were
taken from the design for the El Paso Lurgi Plant, which gave only 1% H2S
in the gas to sulfur recovery and may therefore have relatively lower con-
sumption of utilities.
Overall sulfur balance for the plant is summarized in the diagram
on Figure 4, including the U-Gas unit supplying clean fuel gas to coal
drying and the utilities area. Sulfur is removed in the U-Gas system using
a molten metal, which is regenerated by blowing with air to form S02 which
goes to the sulfur plant. This system is presumed to give about 96%
sulfur removal including compounds such as COS, etc.
While effective control of sulfur emissions and high sulfur
recovery are indicated by the numbers on Figure 4, supporting confirmation
of the design basis will be essential in any actual commercial application.
-------
FIGURE 4
SULFUR BALANCE - HYGAS PROCESS
(Numbers are Tons/Day Sulfur)
Dryer Vent Gas
Coal Feed
-—- - s^
533
Coal Feed
155
Coal
Prep.
U-Gas
532
"*1
HYGAS
Char f
153
526
»»-
Jother *
1 (As
(as S02) *"~
Sulfur
Removal
6
Acid Gas .
Treat .
523
i H2S)
i
Sulfur
Plant
Utility
Boiler
• 1
i^-
CO? _
... - ^_
Tail Gas
> • ^*
Sulfur
Flue Gas
Char
* Other: oil product, sour water, etc.
Tons/Day
1
7
663
0.2
0.3
1.0
96.4
0.9
1.0
0.2
OJ
Ul
688 100.0
-------
- 36 -
8. THERMAL EFFICIENCY
It is of interest to compare the heating value of pipeline gas
product versus that of total coal consumed by the plant including auxiliaries,
This represents the thermal efficiency for the process and relates to raw
materials consumed, as well as to the amount of waste heat that must be
rejected to the environment, or that appears in by-products such as oil.
In order to be meaningful the calculation must include all processing,
auxiliaries, environmental controls, utilities, etc., needed to make the
plant self-sufficient. In this HYGAS design thermal efficiency is 64.6%
for the complete plant, as shown in Table 2.
Oil by-product is included, and adds 4.3% to thermal efficiency.
It is also informative to look at where losses in efficiency occur, so that
their relative importance can be examined. The lower part of Table 2 shows
a breakdown of losses. Evaporation of water in the cooling tower is by
far the largest, followed by sensible heat transferred to the air as it
passes through the cooling tower.
The tabulated numbers assume that rejected char contains only
10.3% carbon. If this low level is difficult to achieve or results in
excessive attrition within the gasifier, then thermal efficiency might
decrease. Thus if the char contained 30% carbon, loss via this stream
would increase to 5.7% of the high heating value of total coal used.
In the energy balances used for this study, all electric power
needed for the plant is generated onsite, and no power is purchased.
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- 37 -
TABLE 2
In: Coal to Hygas
Coal to U-Gas
Out: Pipeline Gas
Oil By-Products
Losses:
Char (10.3% Carbon)
CO2 Vent Gas
Dryer Vent Gas
Cooling Tower Evap.
Cooling Tower Se
Furnace Flue Gas
By-Products:
Sulfur
Ammonia
Phenol
Other Losses
THERMAL EFFICIENCY
HYGAS PROCESS
Tons /Day
12,695
3,686
16,381
5,167
478
5,645
0 2,117
13,726
3,647
>. 27,120
;. Heat 2,800,000
34,280
666
135
16
—
109 Btu/Day
320
93
413
249
18
267
6.3
6.5
1.3
57.0
29.2
10.0
5.3
2.6
0.5
27.3
146
77.5
22.5
100.0
60.3
4.3
64.6
1.5
1.6
0.3
13.8
7.1
2.4
1.3
0.6
0.1
6.7
35.4
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- 38 -
9. TRACE ELEMENTS
Coal contains many trace elements present in less than 1% con-
centration that need to be carefully considered from the standpoint of
potential impact on the environment. Many of these may volatilize to a
small or large extent during processing, and many of the volatile components
can be highly toxic. This is especially true for mercury, selenium,
arsenic, molybdenum, lead, cadmium, beryllium and fluorine. The fate of
trace elements in coal conversion operations, such as gasification or
liquefaction, can be very different 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 con-
dition 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 voltaile. 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 combustion zone and their subsequent condensation
and collection on the fly ash particles (29). Other studies on coal fired
furnaces are pertinent (30,31,32) and some of these report mass balances
on trace elements around the furnaces (33).
Considerable information is available on the analyses of coal,
including trace constituents, and these data have been assembled and evaluated
(34,35). A few experimental studies have been made to determine what happens
to various trace elements during gasification (2,37,38). As expected, these
show a very appreciable amount of volatilization on certain elements. As
an order of magnitude, in this specific HYGAS design each 10 ppm of element
volatilized would amount to about 240 pounds per day.
Results on the fate of trace elements in commercial gasification
plants is rather limited, but an effort was made to assemble and evaluate
the available data. Some trace elements show up in unexpected
places, thus analyses of tar from gasification show up to 50 parts per
million of lead, while oil samples from gasification show 30 parts per
million of arsenic. This raises environmental and safety questions on sub-
sequent use of such materials. One further example is a report of about
200 parts per million of titanium in the heavy liquid or tar produced in a
coal liquefaction pilot plant (7). While titanium is not now considered
to be one of the more toxic elements, further consideration of the implica-
tions is called for.
In order to make the picture on trace metals more meaningful,
the approximate degree of volatilization 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 the hot gases leaving the gasifier. Results are
shown in Table 3 in the order of decreasing voltaility. Looking at the
-------
- 39 -
TABLE 3
Cl
Hg
Se
As
Fb
Cd
Sb
V
Ni
Be
Cr
Zn
B
F
Ti
* V
TRACE ELEMENTS -
Hypothetical
Coal ppm
1500
0.2
2.2
31
7.7
0.14
0.15
35
14
2
22
44
165
85
340
olatility based mair
ESTIMATED VOLATILITY
% Volatile*
90+
90+
74
65
63
62
33
30
24
18
nil
e.g. 10
e.g. 10
e.g. 10
e.g. 10
ily on easificatior
lb/day**
32,400
4
39
484
116
2
1
252
81
9
nil
106
396
204
816
i experimei
but chlorine is taken from combustion tests, while zinc,
boron, and fluorine were taken at 10% for illustration in
absence of data.
** Estimated volatility for 12,000 tons/day of coal to
gasification.
-------
- 40 -
estimated amounts that may be carried overhead, it becomes immediately
apparent that there can be a very real problem. For each element the net
amount carried out in the gas leaving the gasifier Should be collected,
removed from the system, and disposed of in an acceptable manner.
Environmental controls will be needed if the effluent contains excessive
amounts of undesirable components, particularly if these are toxic elements.
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.
A complication that has not generally been recognized, occurs in
the gas cleanup section due to the volatility of trace elements. These may
be carried out with the raw gas, and removed in the gas cleanup facilities
when the gas is cooled and scrubbed. In any event, they do not remain in
the pipeline gas, and it follows that they must leave the system at some
point. Compounds such as cyanides might be destroyed by recycling to the
process (e.g., the gasifier), but this can not be the case for elements
such as arsenic, lead, chlorine, etc. Neither will they disappear in the
biox unit. Therefore provision will be needed to separate and recover
them, or to deactivate them for disposal in a satisfactory manner. As can
be seen from Table 3, the combined amounts of all volatile portions of
potentially undesirable trace elements can present a formidable disposal
problem.
The preceeding discussion has been directed primarily at trace
elements that are partially volatilized during gasification and thereby
carried into the gas cleaning section. 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 char from gasification. Undesirable
elements might be leached out of this char since it is handled as a water
slurry, and the char 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 associated with
char disposal, and additional information and evaluation is needed. The
situation may be quite different from the ash rejected from coal fired
furnaces, since the char 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.
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- 41 -
10. TECHNOLOGY NEEDS
From this review and examination of environmental aspects of the
HYGAS process, a number of areas have been defined where further information
is needed in order to evaluate the stiuation or where additional studies
or experimental work could lead to a significant improvement from the stand-
point 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 4.
Any coal conversion operation has solid refuse to be disposed of.
Rejected char in the present design generates over 3,000 acre feet per year
of refuse. More work is needed in order to define methods of disposal that
do not create problems due to leaching of acids or sulfur which could con-
taminate natural water. In addition, adequate controls are needed with
regard to the potential dust nuisance and washing away of particulates, since
the char is expected to have a low density, and be quite friable. In many
cases the material may be suitable for land fill with revegetation.
Although there is already some general background on this subject, specific
information is needed on each coal for each process, and each specific
location in order to allow thorough planning to be sure that 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. It will often be attractive to burn high sulfur coal rather than
clean gas fuel and to include facilities to remove sulfur from the vent
gases, since this gas must be processed in any event for dust removal.
The need for a simple, efficient means of feeding coal to the high
pressure gasifier has been apparent and has received considerable study.
For pressure levels of 400-500 psig, lock hoppers have been used satis-
factorily, although they are expensive. For systems at 1,000 psig, it may
be attractive to pump an oil or water slurry of the coal in order to pres-
surize it. A water slurrry could be particularly attractive if it is
possible to then evaporate the water at high pressure and thereby supply
steam to the gasifier (5).
In the area of acid gas removal, scrubbing with refrigerated
methanol may give satisfactory cleanup of the gas but utilities consump-
tion is high, and the C02 vent stream requires further treatment to remove
combustibles, and possibly also COS. Systems based on amine or hot car-
bonate are not completely satisfactory and leave room for improvement.
Amine scrubbing is not effective on carbonyl sulfide, and it is often
difficult to provide a highly concentrated stream of ^S to send to the
sulfur plant. In addition the C02 stream vented to the atmosphere may
contain too much sulfur. Adsorption/oxidation systems are often not
effective on carbonyl sulfide and in any event do not remove C02 as
required; and therefore, additional processing is needed. The available
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TABLE 4
TECHNOLOGY NEEDS
• Environmentally sound disposal of large amounts of char from gasification,
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.
• An improved system to feed coal into high pressure zones, for example
using a piston feeder on oil or water slurry. If water is used, then it
might be evaporated in a heated fluid bed to make steam for gasifier,
and preheat the coal fed to gasification.
• A simpler and more efficient process for acid gas removal which would
provide an H2S stream of high concentration (e.g. 50 vol. %) to the
sulfur plant, while giving a separate clean stream of C02 that can be
vented directly to the air. Desirable features to include:
Good sulfur cleanup, to a few ppm
- A clean C02 vent stream that does not require incineration or cleanup
- Low utilities consumption
- Little or no chemical purges to dispose of
• An effective process to remove sulfur at high temperature could lead to
improvements such as reacting CO directly with steam to form methane,
and thereby avoid cooling and reheating the gas as in present designs.
• Ways to treat COS, CS2, thiophene, etc., that are usually present and
may not be handled effectively by many acid gas removal processes.
Hydrolysis to H2S is one approach, and would assure that COS, for example,
does not escape with the C02 vent stream.
• Sour water cleanup techniques need evaluation and demonstration. There is
a great need for a practical way to evaporate sour water to make steam for
use in the gasifier, and a fluid bed system appears promising.
• Information on trace elements and techniques for their disposal.
- Extent of volatility for specific process and coal.
- Where they appear in gas cleanup system, and in what form.
They may collect on the char or shift catalyst, in sour water
or acid gas removal, or in the by-product oil.
- Many trace elements may be toxic and require separation and
decontamination treatment before disposal.
Since trace elements contained in the coal feed must leave the
system at some point, specific means must be defined either to
recover them, or dispose of them in an environmentally acceptable
manner.
Leaching may occur on the rejected char. Information is needed to
define the potential problems and to devise environmentally sound
disposal techniques.
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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.
Desirable objectives for an acid gas removal process can be
summarized as follows: (a) good cleanup of all forms of sulfur to give
a stream high in sulfur concentration for processing in a Claus type sulfur
plant, (b) effective CC>2 removal while producing a vent stream satisfactorily
low in sulfur and pollutants, (c) low utility and energy consumption, and
(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. Such operations are large consumers
of utilities and have a large effect on overall thermal efficiency.
As in most gasification processes, the amount of sour water
produced is less than the amount of steam fed to gasification plus shift
conversion, 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 (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
for each coal conversion process since operating conditions differ. In
many cases, the trace elements may tend to recycle within the system and
build up in concentration. 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
start up or upsets should also be evaluated.
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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.
In an actual application, the net water effluent from the plant
will have to be cleaned up. 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 s'olids, 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 blowdown 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 store them, or
dispose of them in the ocean. It would be desirable to define alternative
technology for disposing of or using more effectively the final waste
water discharge from a plant.
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11. PROCESS DETAILS
Further information on the basis used in this evaluation is
given in Tables 5-8, which show coal feed and products for the plant,
as well as utilities consumption. The latter were not given for the
basic design, which was not specified in sufficient detail to allow
calculating them; however, the overall process is very similar to the
plant design of the El Paso Natural Gas project for New Mexico based on
Lurgi gaisifers (3), which therefore provides a sound basis for utilities
required on the HYGAS process. In fact, both designs are sized to make
the same amount of SNG. The gas cleanup systems are also quite similar
using the Rectisol process for acid gas treatment, and the Phenosolvan
process to extract phenols. Since the El Paso design gives only about
1% H2S in the stream to sulfur recovery compared to the 30% assumed for
HYGAS, the utilities consumption in acid gas treatment may be higher than
we have used.
Operating pressure is higher for HYGAS, 1200 psia versus about
500 psia for Lurgi, which increases the power required for oxygen compres-
sion and coal feeding. Also, the steam fed to the gasifier cannot be
used first in bleeder turbines to generate power as is done in the El Paso
design. Offsetting these factors is the saving gained by eliminating the
product SNG compressor, made possible by operating the HYGAS process at
higher than pipeline pressure.
In both cases, clean gas for plant fuel is made by air gasifica-
tion of coal, and this gas is used in a combined cycle to generate useful
power from gas turbines before it is used in furnaces. All electrical
power used by the plant is generated onsite and allowed for in the energy
balances. No power is purchased.
Rough estimates of differences between the two processes show
that utilities requirements will be about the same although some modifica-
tions to the El Paso utility consumptions were made where practical. There
will be some debit for the HYGAS process in that high level heat in the
raw gas from gasification is degraded in temperature level by the drying
bed and oil quench system, so that it cannot be used to make high pressure
steam.
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TABLE 5
COAL FEED AND PRODUCTS - HYGAS PLANT
tons/day
Coal Feed - Dry Basis to HYGAS 12,695
(Illinois No. 6) to U-Gas 3,686
16,381
Coal Analysis - Dry Basis Wt. %
Carbon 69.40
Hydrogen 4.80
Oxygen 8.71
Nitrogen 1.35
Sulfur 4.20
Ash 11.54
100.00
High Heating Value 12,600 Btu/lb
Pipeline Gas 250 MM SCFD @ 1000 psig
(H.H.V. 960 Btu/SCF)
Char
From HYGAS
From U-Gas
Tons /Day
1,667
450
2,117
(10.3% Carbon, 0.3% Sulfur, 89.4% Ash, H.H.V. 1500 Btu/lb)
Product Oil 478 Tons/Day (H.H.V. 18,800 Btu/lb)
By-Products
Sulfur 663 tons/day
Ammonia 120 tons/day
Phenol 16 tons/day
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TABLE 6
ESTIMATED STEAM BALANCE HYGAS PROCESS*
Source
Use
Power Boiler
Methanation and Superheater
Gasifier Jacket (02 Blown)
Pipeline and Methanation Compressors
Gasifier Jacket (Air Blown)
Power Generator
Waste Heat Boiler (02 Blown)
1500 Psia (955°F)
1489 M Lb/Hr
1100 Psia (930°F)
1354 M Lb/Hr
500 Psia (752°F)
171 M Lb/Hr
1738
54
842
112 Psia (336°F)
741 M Lb/Hr
Electrical Generator
Pipeline Compressor
Pipeline Compressor
Methanation Recycle Compressor
Gasifier -(02 Blown)
Gasifier (Air Blown)
02 Plant Turbine
Lock Gas Compressor (02 Blown)
Lock Gas Compressor (Air Blown)
Oxygen Compressor
Air Compressor (Air Blown)
Phenosolvan
Rectisol
Stretford Plant
Refrigeration Compressor
Condenser
1105 M Lb/Hr
384
571 M Lb/Hr
784
1762 M Lb/Hr
312
132
118
35
314
132
32 M Lb/Hr
20
21
435
234
* Note: This steam balance is from the Lurgi study using Lurgi gasifiers (3), in order to provide a
complete picture. Overall steam balance would be about the same for the HYGAS process, although
there would be some increases and decreases as discussed in the text. Steam production from
gasifier jacket assumed to be similar for HYGAS plus U-Gas combination.
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- 48 -
TABLE 7
ELECTRIC POWER CONSUMPTION
HYGAS PROCESS*
KW
Coal Preparation 6,000
Gas Purification 13,200
Sulfur Plant 4,200
Gas Liquor Treating 3,600
Cooling Water System 7,000
Power Plant 8,000
U-Gas e.g. 3,000
Other e.g. 12,000
57,000*
* All power consumed is supplied by onsite generation
using appropriate facilities, and necessary fuel
requirements, etc., are included in overall balances
for plant.
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- 49 -
TABLE 8
WATER BALANCE
HYGAS PROCESS
Consumed Tons/Day
Steam to Gasifier 11,780
Steam to Shift 4,955
Water to Scrubber 2,824
Steam to U-Gas 2,560
Evaporated in Cooling Tower 27,120
Net Discharge from Plant 5,424
54,663 9,110
Recovered
From Scrubber 9,678 1,613
From Methanation 2,520 420
From Acid Gas Treatment 37 6
12,235 2,039
Net Makeup Water Required 42,428 7,071
Note: Cooling water circulation rate will be
roughly 200,000 gpm.
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- 50 -
12. QUALIFICATIONS
A major qualification of this study is that it assumes that no
pretreat of the coal will be needed. The results therefore apply to those
applications which use a non-caking coal. It is the hope of the Institute
of Gas Technology that the process can eventually be used on caking coal
without pretreatment, but additional development and demonstration will be
needed to confirm this.
The basis used does not include coal cleaning, which is a very
important factor in environmental impact of coal conversion technology,
and has been included in some other studies in this series (7). Refuse
from coal cleaning may be 20-25% of the coal as mined, presenting a sizeable
disposal problem. Although it has not been included, suitable provision
will have to be defined and evaluated in order to have a viable and complete
gasification project.
As pointed out in connection with acid gas treatment, the very
desirable high concentration of 30% H2S shown as feed to the Glaus plant
is not confirmed by results from some operating plants and projected
plant designs; consequently, further consideration and evaluation of this
feature is needed.
An important basis item that can have a large effect on thermal
efficiency is the carbon content assumed for the char withdrawn from the
HYGAS and U-Gas reactors. Unused carbon in the rejected char is a direct
loss of heating value in the coal feed. A higher than minimum amount of
residual carbon may be set to control attrition and dusting in the fluidized
or suspended solids reaction system, as well as by the reaction kinetics and
extent of staging in gasification. A carbon content of 10.3% has been
assumed, but other publications show higher values, and at 30% carbon
content in char the number for thermal efficiency would be 4.2% lower.
Clean gas for plant fuel is provided by the U-Gas process, which
is also in the development stage. Full use is made of the combined cycle
operation using gas turbines to supply power, and thereby gain a significant
increase in efficiency for generating utilities. Combined cycles are being
explored intensively, although they are not used conventionally yet by
public utilities or industry.
In view of these and other factors used in setting a study basis,
great caution should be exercised in attempting to make comparisons between
processes, since they must be on a strictly comparable basis if the results
are to be meaningful. Variations that must be taken into account include
coal type and sulfur content, plant location, amount of emissions relative
to permissible, production and disposition of tar and other by-products,
utilities systems, use of air cooling, and scope of project.
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- 51 -
13. BIBLIOGRAPHY
1. Magee, E. M., et al., "Evaluation of Pollution Control in Fossil
Fuel Conversion Process, Gasification: Section 1: Koppers-Totzek
Process," EPA-650/2-74-009a, January 1974.
2. Kalfadelis, C. D., "Evaluation of Pollution Control in Fossil Fuel
Conversion Processes, Gasification: Section 2: Synthane Process,"
EPA-650/2-74-009b, June 1974.
3. Shaw, H., "Evaluation of Pollution Control in Fossil Fuel Conversion
Processes, Gasification: Section 3: Lurgi Process," EPA-650/2-74-
009c, July 1974.
4. Jahnig, C. E., "Evaluation of Pollution Control in Fossil Fuel
Conversion Processes, Gasification Section 4: C02 Acceptor Process,"
EPA-650/2-74-009d, December 1974.
5. Jahnig, C. E., "Evaluation of Pollution Control in Fossil Fuel
Conversion Processes," Gasification: Section 5: BI-GAS Process,"
EPA-650/2-74-009g, April 1975.
6. Kalfadelis, C. D., "Evaluation of Pollution Control in Fossil Fuel
Conversion Processes," Liquefaction: Section 1: COED Process,"
EPA-650/2-74-009e, January 1975.
7. Jahnig, C. E., "Evaluation of Pollution Control in Fossil Fuel
Conversion Processes, Liquefaction: Section 2: Solvent Refined
Coal Process," EPA-650/2-74-009f
8. Study Made for EPA by Booz Allen and Hamilton Co. on "Pollution Control
in Fossil Fuel Conversion Processes," Report EPA 9075-015, March 1974
Sections VII and XIV.
9. Schora, F. C., et al., "The HYGAS Process," IGT Clean Fuels Symposium,
Chicago, 111., Sept. 1973.
10. Schora, F. C., "Clean Energy from Coal," Intersociety Energy Conversion
Conference, San Francisco, Calif., August 26-30, 1974.
11. Lee, B. S., "Status of KYGAS Process," Fifth Synthetic Pipeline Gas
Symposium, Chicago, 111., October 29-31, 1973.
12. Schora, F. C., et al., "Analysis of a HYGAS Coal Gasification Plant
Design," AIChE 65th Annual Meeting, New York City, Nov. 27-30, 1972.
13. Bodle, W. W., et al., "Clean Fuels from Coal," The Oil Gas Journal
August 26, 1974, pg. 73-88.
14. Kavlic, V. J., et al., "Coal Pretreatment in Fluidized Bed," American
Chemical Society, Division of Fuel Chemistry, September 1966.
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- 52 -
15. Lee, B. S., "Status of HYGAS, Electrothermal Gasification, and Steam
Oxygen Gasification Programs," Fourth Synthetic Pipeline Gas Symposium
Chicago, 111., Oct. 30-31, 1972.
16. Loeding, J. W., et al., "The U-Gas Process," Chemical Engineering
Progress 7.1, (4) pg. 85, (April 1975).
17. Loeding, J. W., et al., "Clean Fuels from Coal Symposium," Institute
of Gas Technology, Chicago, Sept. 10-14, 1973.
18. Bolln, J. J., "Commercial Concept Designs," Fifth Synthetic Pipeline
Gas Symposium, Chicago, 111., Oct. 29-31, 1973.
19. Gibson, C. R., et al., "Environmental Aspects of El Paso's Burnham/
Coal Gasification Complex," EPA Symposium: Environmental Aspects of
Fuel Conversion Technology, St. Louis, Mo., May 1974, EPA-650/2-74-118.
20. Berty, T. E., et al., "Environmental Aspects of the WESCO Coal
Gasification Plant," EPA Symposium: Environmental Aspects of Fuel
Conversion Technology, St. Louis, Mo., May 1974, EPA-650/2-74-118.
21. El Paso New Mexico Coal Gasification Project Environmental Statement
1974.
22. Forney, A. J., et al., "Analyses of Tars, Chars, Gases, and Water
Found in Effluents from the Synthane Process," EPA-650/2-74-118.
23. Farnsworth, J. F., et al., "Clean Environment with Koppers-Totzek
Process," EPA-650/2-74-118.
24. Colgate, J. L., et al., "Gob Pile Stabilization, Reclamation, and
Utilization," Office of Coal Research R&D Report No. 75, 1973.
25. Goldberger, W. M., "The Union Carbide Coal Gasification Process,"
Fourth Synthetic Pipeline Gas Symposium, Chicago, 111., Oct. 30-31, 1972,
pg. 257.
26. Corder, W. C., "The Union Carbide/Battelle Coal Gasification Process,"
Fifth Synthetic Pipeline Gas Symposium, Chicago, 111. Oct. 29-31, 1973,
pg. 107.
27. Furlong, E., "Cooling Tower Operations," Environmental Science and
Technology 8., (8) pg. 712 (Aug. 1974).
28. Lee, B. S., "Slurry Feeding of Coal Gasifiers," Chemical Engineering
Progress 71, (4), pg. 81, (April 1975).
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- 53 -
29. Lee, R. E., et al., "Trace Metal Pollution in the Environment,"
Journal of Air Pollution Control, 23, (10), October 1973.
30. Schultz, H., Hattman, E. A., and Booker, W. B., ACS Div. of Fuel.
Chem., Vol. 8, No. 4, p. 108, August 1973.
31. Billings, C. E., Sacco, A. M., Matson, W. R., Griffin, R. M.,
Coniglio, W. R., and Harley, R. A., "Mercury Balance on a Large
Pulverized Coal-Fired Furnace," J. Air Poll. Control Association,
Vol. 23, No. 9, September 1973, p. 773.
32. Schultz, Hyman et al., "The Fate of Some Trace Elements During Coal
Pretreatment and Combustion," ACS Div. Fuel Chem. 8_, (4), p. 108,
August 1973.
33. Bolton, N. E., et al., "Trace Element Mass Balance Around a Coal-Fired
Stream Plant," NCS Div. Fuel Chem., 18, (4), p. 114, August 1973.
34. Magee, E. M., Hall, H. J., and Varga, G. M., Jr., "Potential Pollutants
in Fossil Fuels," EPA-R2-73-249, June 1973.
35. Trace Elements and Potential Toxic Effects in Fossil Fuels H. J. Hall,
EPA Symposium "Environmental Aspects of Fuel Conversion Technology,"
St. Louis, Mo., May 1974, EPA-650/2-74-118.
36. Ruch, R. R., et. al., "Occurence and Distribution of Potentially
Volatile Trace Elements in Coal," EPA-650/2-74-054, July 1974.
37. Attari, A., "The Fate of Trace Constituents of Coal During Gasification,"
EPA Report 650/2-73-004, August 1973.
38. Attari, A., et al., "Fate of Trace Constituents of Coal During
Gasification," (Part II), Presented at Amercian Chemical Society
Meeting, Div. of Fuel Chem., Phil., PA., April 6-11, 1975.
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- 54 -
TECHNICAL REPORT DATA
(I'll a.<< irail luilfiirHtiini on liic ici < rsi before e
NO.
EPA-650/2-74-009-h
3. RECIPIENT'S ACCfc SSIO?* NO.
<.T,TLEANDSUBT,TLE Evaluation of p0nution Control in
Fossil Fuel Conversion Processes; Gasification:
Section 6. HYGAS Process
5. REPORT DATE
August 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
C.E. Jahnig
8. PERFORMING ORGANIZATION REPORT NO
Exxon/GRU.llDJ.75
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Exxon Research and Engineering Company
P.O. Box 8
Linden, NJ 07036
10. PROGRAM ELEMENT NO.
1AB013: ROAP 21ADD-023
1 1. CON T~RACT/GRANT NO.
68-02-0629
12. SPONSORING AGENCY 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
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The report gives results of a review of the HYGAS process being developed by the
Institute of Gas Technology, from the standpoint of its potential for affecting the
environment. The quantities of solid, liquid, and gaseous effluents have been
estimated where possible, as well as the thermal efficiency of the process. For the
purpose of reduced environmental impact, a number of possible process modifications
or alternatives which could facilitate pollution control or increase thermal efficiency
have been proposed, and new technology needs have been pointed out.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Air Pollution
Coal Gasification
Fossil Fuels
Thermal Efficiency
Trace Elements
b.IDENTIFIERS/OPEN ENDED TERMS
Air Pollution Control
Stationary Sources
Clean Fuels
HYGAS Process
Fuel Gas
Research Needs
c. COSATI l-'icld/Cmup
13B
13H
21D
20M
3. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS {This Report/
Unclassified
21. NO. OF PAGES
60
20. SECURITY CLASS (This page/
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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