EPA-650/2-74-009-f
March 1975
Environmental Protection Technology Series
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EPA-650/2-74-009-f
EVALUATION OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION
PROCESSES
LIQUEFACTION: SECTION 2. SRC PROCESS
by
C.E.Jahnig
Exxon Project Director: E.M. Magee
Exxon Research and Enginering Company
P.O. Box 8
Linden, New Jersey 07036
Contract No. 68-02-0629
ROAP No. 21ADD-023
Program Element No. 1AB013
EPA Project Ol'lict.-)-: William J. Rhodes
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, N. C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH AND DEVELOPMENT
WASHINGTON, D.C. 20460
March 1975
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EPA REVIEW NOTICE
This report 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 tic-Ids. These series are:
I . ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOC1OECONOMIC 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-f
11
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TABLE OF CONTENTS
1. SUMMARY
2. INTRODUCTION 2
3. BASIS AND PROCESS DESCRIPTION 4
3.1 Basis 4
3.2 Process Description 5
4. EFFLUENTS TO AIR 12
4.1 Coal Preparation and Storage 12
4.2 Liquefaction and Filtration 22
4.3 Product Handling and Hydrotreating 23
4.4 Acid Gas Removal and Hydrogen Manufacture 24
4.5 Gasification and Slag Disposal 25
4.6 Auxiliary Facilities 26
5. EFFLUENTS - LIQUID AND SOLID 31
5.1 Coal Preparation 31
5.2 Liquefaction and Filtration 32
5.3 Product Handling and Hydrotreating 34
5.4 Acid Gas Removal and Hydrogen Manufacture 35
5.5 Gasification and Slag Disposal 36
5.6 Auxiliaries 37
6. WATER TREATING AND WATER MAKE-UP 39
6.1 General 39
6.2 Biological Clean-Up 40
6.3 Sludge Handling 42
6.4 Water Make-Up 43
7. THERMAL EFFICIENCY 44
8. SULFUR BALANCE 47
9. TRACE ELEMENTS 49
10. PROCESS ALTERNATIVES 54
11. GENERAL EFFICIENCY ITEMS 58
- iii -
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TABLE OF CONTENTS (Cont'd)
Page
12. POTENTIAL IMPROVEMENTS 60
13. PROCESS DETAILS 64
14. TECHNOLOGY NEEDS 70
15. QUALIFICATIONS 77
16. SRC REPORT REFERENCES 78
- iv -
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LIST OF TABLES
Table Page
1 Major Inputs to Plant , 9
2 Major Streams from Plant 10
3 Detailed Definition of Streams Including
All Effluents From Plant 14
4 Catalyst and Chemicals Consumption 20
5 Thermal Efficiency 45
6 Sulfur Balance 48
7 Analysis of Coal and Product
Samples - Trace Elements 50
8 Process Alternatives 55
9 Potential Improvements 61
10 Fuel Balance 65
11 Electric Power Balance 66
12 Cooling Water Required 67
13 Treated and Waste Water Balances 68
14 Steam Balance, Ib/hr 69
15 Technology Needs 71
- v -
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LIST OF FIGURES
Figure
1 SRC Process Flowplan.
2 SRC Coal Liquefaction Process -
Process Streams and Effluents 13
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1. SUMMARY
The Solvent Refined Coal (SRC) process of the Pittsburg &
Midway Coal Mining Company 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 -
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 correneri ca lly proven,
and several others are being developed in L-> rgi- pilot plants. 1'hcse j.i>>-
grams are extensive and will cost millions of Jollai-. t-u{ ( t> •. = \= v.-=>
ranted by the projected high cost, for cvrnmrrc i;» I ^.asil \>a( ion (-lam = an.'.
the wide application expected in order to meet national needs, C^al eon-
version is faced with potential pollution problems that are common to
coal-burning electric utility power plants in addition to pollution pro-
blems peculiar to the conversion process. It is thus important to examine
alternative conversion processes from the standpoint of pollution and
thermal efficiencies and these should be compared with direct coal utili-
zation when applicable. This type of examination is needed well before
plans are initiated for commercial applications. Therefore, the Environ-
mental Protection Agency arranged for such a study to be made by Exxon*
Research & Engineering Company under contract 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 ot
the processes and to point out areas where present technology and informa-
tion 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 Protection Agency objectives.
Thermal efficiency is also calculated, since it indicates the amount of
vaste 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
update 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.
Prior to June 1, 1974 Exxon Research and Engineering Company conducted
business under the name Esso Research and Engineering Company.
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- 3 -
Our 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, low Btu gas, and/or
liquid products. Reports have been issued on the Koppers, Synthane,
Lurgi, C02 Acceptor, and COED processes (1,2,3,4,5). The present report
extends these studies to include conversion of coal to clean boiler fuel
that is low in sulfur and ash, using the Solvent Refined Coal (SRC) process
being developed by the Pittsburg & Midway Coal Mining Company.
Some consideration has been given previously to environmental
aspects of the SRC liquefaction process in several papers presented at an
EPA symposium. One of these (34), "Environmental Factors in Coal
Liquefaction" presented a quantitative engineering analysis, including
performance of the biological oxidation system (biox). This was shown as
giving 94% removal of ammonia, 95% removal of phenols, and 99% removal of
phosphorous. However, the cooling tower and boiler blowdown streams, amounting
to over half of the total waste water, were indicated to contain up to
10 ppm chromate, which would be extremely toxic to the culture that is
depended upon to carry out biological oxidation. Pretreatment to thoroughly
remove chromium will be needed. Also, cyanides, and particularly thio-
cyanates have been shown to be inhibitors and to resist biodegradation (29).
While disposal of solid sludge from the biox system was not mentioned,
provision is needed (with odor control), for example by incineration. The
amount of such sludge would be sizeable, considering that the 600 gpm of
blowdown is indicated to contain up to 15 ppm phosphate, 99% of which is
removed by biox and thereby incorporated into cellular material.
We wish to acknowledge the information and assistance provided
by EPA and the Pittsburg & Midway Coal Mining Company. To a large extent,
the study has been based on an earlier, detailed engineering study prepared
by the Ralph M. Parsons Company (11) .
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- 4 -
3. BASIS AND PROCESS DESCRIPTION
3.1 Basis
An alternative to converting coal to clean gas fuel is to liquefy it,
and at the same time remove most of the sulfur and ash which pose major
environmental problems if the coal is burned directly without adequate contiols.
Several processes are under development for carrying out this liquefaction.
Some of these use a hydrogenation catalyst to speed up the reaction and
allow high conversion. Such processes are being developed by Hydrocarbon
Research Inc., the Bureau of Mines, and others. Another approach is to use a
hydrogen donor liquid. This consists of an aromatic traction of the pro-
duct which is hydrogenated to form naphthenes, and then recycled to the
coal liquefaction reactor where the hydrogen is transferred to the coal.
The advantage of this route is that hydrogenation is done under relatively
clean conditions, with the ash and metals in the coal excluded so that
they do not foul the hydrogenation catalyst. Still another approach is to
add hydrogen gas directly to the reactor without adding a catalyst, and
accept the low conversion that is obtained for such a non-catalytic
operation. The SRC process being developed by Pittsburg & Midway Coal
Mining Company is of this type (6,7,8). The product is reasonably low in
sulfur and quite low in ash so that it should be suitable as a clean
boiler fuel. It is solid at room temperature and might be handled in
this form, or it could be heated above the melting point an'l handled as
a liquid. The advantage of this non-catalytic route is that there is no
catalyst to foul, and hydrogen consumption is low compared to processes making
synthetic crude. Production of hydrogen is a very large item of cost
in coal liquefaction.
The product still is high in nitrogen (over 1%) and special
attention must be given to the nitrogen oxides problem on burning it.
Development work is under way on means to reduce NOX formation by con-
trolling the combustion conditions. Also, techniques are being developed
to remove NOX from flue gases by conversion to N©2 which is then scrubbed
out, or by reaction with ammonia to form nitrogen.
Early studies on the SRC liquefaction process were made by
Chem Systems and by Stearns Roger (9,10), but these included hydro-cracking
of the heavy product to make light liquids or synthetic crude. This
is not now considered to be the preferred application. A more recent
study by the Ralph M. Parsons Company (11) is based on making primarily
a heavy product and is therefore used as a guide in our environmental
evaluations. Their study did include some hydrotreating such that
1/3 of the heavy product has a sulfur content of 0.2%, versus 0.5% on
the heavier fraction. Current emission regulations for liquid fuels
correspond to about 0.6% sulfur content for fuels having the heating
value of the SRC product.
An interesting feature of the process described by Pittsburg
& Midway Coal Mining Company is that synthesis-gas can be used in the
reactor instead of pure hydrogen. It appears that the water-gas shift
reaction occurs at reaction conditions of about 850°F and 1000 psig.,
and perhaps the coal ash is catalytic for this reaction, and also for
liquefaction. Of course, sufficient water or steam must be added for the
shift conversion. Use of synthesis-gas is said to be practical on Western
coals which are more reactive, but it is not recommended on Eastern coals.
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- 5 -
Studies by The Ralph M. Parsons Company indicate that there is little
or no economic advantage to using synthesis-gas rather than pure hydrogen
since the CO must be shifted one place or another and the C02 removed by
scrubbing. The use of hydrogen has the advantage of much higher hydrogen
partial pressure in the reactor for a given total operating pressure. As
far as overall material and heat balances are concerned, it makes little
difference which path is used as the same amount of shifting and CC>2 scrubbing
is required for either case. Therefore, our environmental studies are based
on the Parsons numbers for synthesis-gas but it is expected that the overall
plant effluents and thermal efficiency will be about the same if pure hydrogen
is fed to the reactor. However, if the liquefaction process were used
only to convert coal to the heaviest liquid while still meeting sulfur
regulations, then the hydrogen consumption would be less than the three
weight percent on coal used by Parsons, and this could improve the thermal
efficiency provided that the balance is such that all of the char or
filter cake can be disposed of efficiently.
A number of conventional methods are available to make the
hydrogen required in the process from by-product fuel gas, or from liquid
products. Another method is to gasify the filter cake which consists of
the ash and char not converted in the liquefaction reactor, along with a
certain amount of liquid product which is not separated from it.
Additional liquid is needed to slurry the filter cake so that it can be
handled. The method used by Parsons is to gasify this ash slurry with
oxygen and steam in a high temperature slagging gasifier similar to that
being developed as part of the BI-GAS process (12). The gasifier
operates at about 3,000°F and 200 psig.
Gasification provides one way to dispose of the filter cake
and convert it to a clean high-value fuel gas, although there may be no
advantage to using this as the source of hydrogen for the liquefaction
process. It would seem preferable to burn this low BTU gas in a combined
cycle boiler. Then hydrogen for the process would be made by a simple
conventional reforming process, feeding the methane and lighter fraction
of the fuel gas. If this should contain too much nitrogen or is other-
wise difficult to clean up for reforming, then the hydrogen could be made
by reforming the light liquid fraction of the product, for example, the
C3 to C5 cut. There appears to be enough of either one of these streams
to provide the hydrogen needed.
3.2 Process Description
The SRC design is based on converting 10,000 tons/day of Illinois
type bituminous coal to net liquid products amounting to 25,000 barrels/day
of heavy clean liquid fuel, of which 2/3 has a sulfur content of 0.5%
while the remaining 1/3 contains about 0.270 sulfur. The plant facilities
can be conveniently grouped into several areas including coal preparation
and handling, coal liquefaction and filtration, gas cleaning and acid gas
removal, product handling and treating, char gasification, hydrogen
production, and finally auxiliary facilities such as utilities, oxygen
manufacture, water treating, and a sulfur plant.
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- 6 -
The process is described in the literature (5-11), and in
the block flow diagram Figure 1. 'It starts with run of mine coal, which
is delivered in rail cars, unloaded, and mechanically stacked in a storage
pile with 3 days capacity. Coal containing moisture is reclaimed from
storage and conveyed to a breaker. Refuse larger than 3 inches in size
from the breaker is returned to the mine for disposal. Coal smaller than
3 inches goes to a second storage pile with 8000 tons capacity, which feeds
the washing and cleaning operation. Here it is processed through a series
of jigs, screens, centrifuges and cyclones, followed by a roll crusher to
reduce it in size to 1-1/4 inch or smaller. Refuse from this cleaning
operation goes to a settling pond to clean-up the water for reuse.
The cleaned coal is dried, sent to a pulverizer, and ground
to pass through a 1/8 inch screen. This stream provides the 10,000
tons per day of coal for liquefaction and is transferred to the slurry
tank where it is mixed with 20,000 tons per day of recycled solvent. The
resulting slurry is recycled through a system supplying the high pressure
feed pumps which deliver slurry to the reactor section at 1,000 psig
pressure. The slurry of coal and recycled oil is mixed with makeup synthesis
gas and recycle gas containing steam formed by injecting and vaporizing
sour water recovered from the products leaving the reactor. This
mixture of gas and slurry goes through a pre-heat furnace and then to a
reactor which operates at about 840"F and 1,000 psig, with about one
hour holding time. Total gas flow to the reactor corresponds to about
45,000 cu. ft. per ton of coal processed. In this particular design,
synthesis-gas is used in the reactor rather than pure hydrogen. Carbon
monoxide in this gas is shifted to hydrogen in the reactor and, the water
needed for this is added in the feed. Conversion of coal is about 91%
on a moisture and ash-free basis.
The stream leaving the liquefaction reactor passes to a separator
at 840°F from which gas is removed overhead and recycled to the reactor
after passing through acid gas removal. Liquid from the bottom of the
separator is cooled and recycled in p*rt to the slurry mixing tank where
it is used to suspend the cofll feed so that it can be pumped to high
pressure. This recycle portion does not have to be filtered. The
remaining liquid from the separator after the reactor goes to a rotary
pre-coat filter where ash and solid particles are removed. Liquid pro-
duct from the filter contains about 0.5% sulfur and constitutes the main
clean liquid product from the process. About one third of it is further
processed by catalytic hydro-treating with pure hydrogen to reduce its sulfur
content to 0.2%,.
The catalytic hydro-treating is severe enough to remove oxygenated
compounds such as phenols, and nitrogen compounds. Use is made of this
feature in processing the waste water for cleanup. Phenols, etc. are formed
during coal liquefaction, and an appreciable part of these remain in the water
phase that is separated from the reaction products. These phenols are re-
moved from the waste water by extracting with a clean light oil, which is
then recycled through catalytic hydrogenation to destroy phenolic type com-
pounds .
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Tail
gas Sulfur
6831 317
12,500 tpd
oily
sour
water
]326
gas to plant fuel gas
Fuel Air
56 1453 782 "1 Sour Gas
dried and ground
coal
10,000 tpd
(2.7% moist.)
Fractlonation
and
Hydrodesulfurizer
slurry
of steam
filter 120 water water
cake 355 497
»/3638 make-up syngas
121
to plant fuel
Dust
Removal
and
Cooling
solids
and gas 920 sour
water
349
slag/water
slurry
1300
water
881
Block Flowplan Showing Flow races of Major Streams.
Numbers arc flow rates in tons/day.
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The process makes an appreciable amount of light gas which is
recovered and cleaned up for use as plant process fuel, for example, in
the reactor pre-heat furnace. A small amount of by-product naphtha is
also formed. Raw materials used are summarized in Table 1, and product
yields for the process are shown in Table 2.
Filter cake containing pre-coat is mixed with enough liquid
product to form a slurry so that it can be fed to the gpsification sys-Lc-n).
This stream contains nearlv all of the ash in the coal feed, as well as
some unconverted coal. The amount of liquid is set to give a slurry
containing 50% wt. solid and 50% liquid.
The gasification system is a modification of the slagging type
gasifier being developed with OCR/AGA funding (BI-GAS). For the modified
system a slurry of ash and char is fed to a 2-stage gasifier, where it
reacts with oxygen and steam at 1,700-3,000°F and 200 psig. The synthesis-
gas leaves the upper 1700°F zone and contains mostly CO and hydrogen, in
the ratio of 1.2 moles of CO per mole of H2« Molten slag is removed from
the lower 3000°F zone and is quenched in water for disposal.
Low BTU gas from the gasifier is cooled, scrubbed, and passed
through acid gas removal. Part of it then goes directly to the coal
liquefaction reactor and the remainder is shifted and scrubbed to produce
pure hydrogen which is used for hydro-treating part of the liquid product
to make the lower sulfur fuel oil.
In addition to the process facilities described there are auxiliary
facilities needed such as the oxygen plant for gasification and utilities
including steam, electric power, cooling water, and waste water treating.
Also, a sulfur plant is included to process gases from the acid gas removal
systems. This makes a high purity sulfur by-product, and has tail gas clean
up facilities to meet environmental requirements.
One aspect of coal liquefaction that raises important environmental
questions is that the product contains a large amount of oxygen and nitrogen
compounds. To the extent that these are in fuel products, the major effect
may only be on NOx production during combustion. However, the water layer
is separated after intimate contact with the oil, and will contain considerable
amounts of these compounds that must be either removed as by-products, or
destroyed.
One conventional approach is to extract chemicals, such as phenols,
from the water layer using a suitable solvent (3). The phenols might
then be sold, or burned. In the present design the method used for treating
waste water is to extract phenols, etc. by using a heavy oil stream consisting
of hydrotreated product. The extract is then recycled to hydrogenation
where phenols and other unwanted materials are destroyed.
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Table 1
SRC Process - Major Inputs to Plant
RAW MATERIALS USED
(1) Run of Mine Illinois No. 6 seam coal: To gasifier 10,000 tons/day
Fuel to dryer
Proximate analysis wt. % & util. 140 tons/day
10,140 tons/day
Moisture 2.70*
Ash 7.13
Volatile matter 38.47
Fixed carbon 51.70
Heating value HHV 12,821 Btu/lb
Ultimate analysis wt. %
Carbon 70.75
Hydrogen 4.69
Nitrogen 1.07
Sulfur 3.38
Oxygen 10.28
Ash 7.13
Mositure 2.70*
100.00
(2) Oxygen, 99.5%, 1964 tons/day
(3) River water, 3626 gpm
* After Drying.
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Table 2
SRC Process - Major Streams from Plant
NET PRODUCTS
1. 2915 tpd of heavy liquid, with a sulfur content of 0.5%.
Higher heating value 16,660 Btu/lb
API -9.7
2. 1442 tpd of hydrotreated liquid, with a sulfur content of 0.270.
Boiling range 400 to 870°F
Higher heating value 18,330 Btu/lb
Gravity 13.9° API
3. 272 tpd of hydrogenated light oils with the following approximate characteristics:
Boiling range C, - 400°F
Gravity 52° API
Nitrogen 5 ppm
Sulfur 1 ppm
4. Ash - 713 tpd from gasifier (plus 10 tpd from coal to furnaces)
5. Sulfur of 99.5% purity - 317 tpd
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- 11 -
Based on information from other processes, it appears likely that
some amines, pyridines, fatty acids etc. will be formed and have to be
removed in the clean-up operations. Insufficient data are available at
this time to define this situation clearly.
The raffinate, or water layer is stripped to remove light
gases, including ammonia and hydrogen sulfide, which are sent to the
sulfur plant. Contaminants remaining in the water layer are considered
to be low enough so that processing in a biological oxidation system
will give adequate clean-up to permit discharging the water effluent
to a river for example. A further discussion of considerations in cleaning-
up waste water is given in Section 6 of this report.
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4. EFFLUENTS TO AIR
4.1 Coal Preparation and Storage
All inputs and effluents are summarized in block flow diagram
Figure 2} and described in Tables 3 and 4 according to available data.
Environmental aspects are described and evaluated in the following discussion.
The first effluent to the air in the process flow is from
the coal storage and preparation area. Coal is received in rail cars
or trucks and dumped into a hopper. From there it is moved by conveyors
to a storage pile with 3 days capacity, or 37,500 tons. Coal is
reclaimed from storage by a bucket wheel and conveyors which move
it to the cleaning facilities. A dust nuisance could be generated from
the unloading and loading equipment and conveyors, therefore, these should
be covered as much as possible to minimize dusting and spills. Good
housekeeping is essential since trucks or the wind will pick-up and
disperse any dust in the area. Specific clean-up equipment should be
provided such as a vacuum system and clean-up trucks, plus water sprays
and hoses as needed to flush any dust into the storm sewer system for
recovery in the storm pond.
Large coal storage piles often contribute to a dust nuisance,
although it may be possible to control this by spraying the pile with liquefied
product or asphalt. Spontaneous combustion can occur in coal storage piles
and result in evolution of fumes and volatiles. As one control measure,
equipment for compacting the pile as it is formed has been indicated and
it will also be desirable to monitor the temperatures within it. In any
event, plans and facilities should be available for extinguishing fires
if they occur (13). For the specific design being considered, only 3 days
storage is provided, consequently it should be possible to avoid the problems
by simply using storage silos with nitrogen blanketing.
In the washing plant coal is screened, crushed, and a slurry
of fine refuse is sent to the tailing pond. The coal washing section
is relatively free of dust since it is a wet operation, but spills can
occur, and when they dry out can create a dust nuisance. This has been
a problem for example on some retention ponds used for disposal of
tailings (14).
Noise control should be carefully considered since it is often
a serious problem in solid handling and size reduction. If the grinding
equipment is within a building, the process area may thereby be shielded
from undue noise, but additional precautions are needed for personnel
inside the building.
The next process step is to dry the washed coal, using a flow
dryer to reduce the moisture content to 2.7%. In the design of Ralph M.
Parsons, part of the dried coal supplies the fuel required for drying.
However, the sulfur content of this coal is very high and flue gas clean-
up would be required to remove sulfur as well as particulates. An
-------
23456
A
i
Run of
Figure 2
SRC Coal Liquefaction Process
Showing all effluents from process units and auxiliaries.
8 9
t I
I L
10
t
69 72
i 70 711
ft
Note: Streams indicated by heavy dashed lines are all
emitted to environment, others are reused within
the plant or leave as products.
87 88
89 90
91 92 93
t t tf
94 95 96 97
-------
- 14 -
Table 3
Detailed
Stream No.
1
* 2
3
* 4
* 5
* 6
*'- "7
/
* 8
* 9
* 10
11
12
13
14
15
16
17
18
SRC
Definition of Streams
Process
Including All
Identification Amount Ib/hr
Coal feed 1,
gangue
wash water 1,
rain runoff eg
dryer vent gas
dust eg
chemical purge
sulfur
tail gas
chemical purge
gas produced
rain eg
wash water 1,
air
fuel to dryer
makeup chem
air
fuel gas
041,667
208,334
830,964
6" rain in
24 hours
244,311
10,417
-A")V
26,417
569,250
**
178,500
6" in 24 hr.
830,964
122,070
6,853
2,700
**
121,100
4,667
Effluents from Plant
Comments
ROM coal 12,500 tpd, 10% moist.
separated by screening
used for washing coal, recirculated
from coal storage and handling area
coal is dried to 2.7% moisture
from coal prep. & drying - collected
in bag filters
purge soln. from acid gas removal
by-product sulfur
treated tail gas from sulfur recovery
purge soln. from acid gas removal
C - product to plant fuel
4
rain onto coal stor. and process
area
used to wash coal - recirc., and
purge to pond
air for combustion to heat dryer
low sulfur gas fuel to dryer (from
plant fuel gas); high sulfur coal fines
to dryer as limited by sulfur emission
chemicals for acid gas removal (eg amine
air to burner and incin. in sulfur plant
C/ - fuel to S plant burner and tail
gas cleanup (from plant fuel gas)
* These streams are all emitted to the environment.
** See Table 4 for details.
-------
- 15 -
Table 3 (continued)
19
20
21
22
* 23
* 24
* 25
26
27
28
29
30
31
32
33
34
35
chemical makeup
coal to reactor
water vapor
oily sour water
flue gas
flue gas
**
833,333
23,333
110,500
873,180
135,156
air from airfins 6,289,000
sour water 41,417
naphtha product 22,667
light fuel oil 120,167
heavy fuel oil 242,917
heavy fuel oil to 10,083
plant fuel
syngas to reactor 303,167
(7.4 MMCFH)
fuel gas 61,650
air 811,350
sour water 65,583
ash slurry to gasif. 255,080
chem. makeup for acid gas removal
dried cleaned coal feed to process
(2.7% moist.)
moist, in coal (2.77o) released in
hot slurry
from product recovery
from furnace preheating slurry to
reactors
from prht,furn. on fractionation
to hydrotreating
airfin cooling alternative to save
cooling water
water from hydrotreating heavy prod.
C5 - 430°F naphtha, 52° API,
5 ppm N, 1 ppm S
400-870°F, 13.9°API, 0.27.S, HHV
18,330 Btu/lb
-9.7°API, 0.5%S, HHV 16.660 Btu/lb
-9.7°AP1, 0.5%S, HHV 16.660 Btu/lb
supplies hydrogen for coal conversion
Reactor preheater furnace 1039.5 MM
Btu/hr
Reactor preheater furnace 1039.5 MM
Btu/hr
Contains ammonia, H2S, phenols, etc.
and is recycled through furnace & reactor
Unreacted coal residue & equal wt. of
heavy prod.
* These streams are all emitted to the environment.
** See Table 4 for details.
-------
- 16 -
Table 3 (continued)
36
37
38
39
40
* 41
42
* 43
44
45
46
47
* 48
49
* 50
51
* 52
steam
water
fuel gas
air
air
slag
steam
flue gas
h.p. steam
dust
recycle slurry &
condensate
chemical purge
acid gas
flue gas
condensate
C09
10,000
29,583
9,543
125,663
6,289,000
108,333
10,500
35,440
321,000
76,667
gas 44,175
29,083
**
111,583
65,394
71,667
67,417
* 53
chemical purge
27,168
open steam to fractionator
water used to wash oil
furnaces on fractionation & hydrotreating
160.9 MM Btu/hr
furnaces on fractionation & hydrotreating
160.9 MM Btu/hr
airfin coolers to save cooling water
water slurry containing 59,400 Ib/hr ash
by product steam from waste heat
from preheat furnaces on gasifier
steam made in waste heat boiler
dry char recovered & recycled to
gasifier
sour water, slurry from scrubber con-
taining 18,900 Ib/hr solids is mixed
with 6,350 Ib/hr of scrubbed gas and
recycled to gasifier.
sour condensate, returned to liquif.
reactor.
chemical purge from acid gas removal
and caustic scrubbing on syngas
to sulfur plant from amine scrubbing
(11.5 vol. % H2S)
from preheat furnaces on shift converter
water condensed after shift
C02 rejected to air from Benfield unit
after shift
net discharge of waste water from
Benfield C02 removal unit, may contain
some carbonate
* These streams are all emitted to the environment.
** See Table 4 for details.
-------
- 17 -
Table 3 (continued)
54
55
56
57
58
59
60
61
62
63
64
65
66
* 67
68
* 69
70
71
* 72
73
condensate
steam
water
plant fuel gas
air
water
air and condensate
chemical makeup
plant fuel gas
air
boiler feed water
chem. makeup
Oxygen
Nitrogen
condensate
sludge
boiler feed water
cooling water
backwash
phenols, etc.
1,750
77,500
116,083
2,440
33,000
321,000
--
**
4,620
60,800
99,333
**
163,700
616,300
4,500
*v<
213,738
1,328,378
*x
--
74
H2S
water condensed after methanation
steam to gasifier
water added to quench slag
to preheat furnaces on gasifier
air to preheat furnaces on gasifier
boiler feed water to waste heat boiler,
to back flush filters on circulating
amine. Gas is vented to S plant and
liquid goes to waste water treating.
makeup to acid gas removal - amine,
additives, sodium hydroxide
to preheat furnace for shift converter
to preheat furnace for shift converter
to make steam fed to shift
converter
makeup chemicals to Benficld unit
oxygen to gasifier (99.5/1)
vented from oxygen plant
moisture from air, typical
from treating makeup water with lime,
alum
to steam generation
makeup to cooling tower
acid, caustic, used to regenerate
extracted & returned to hydro unit to
destroy it. But it could be recovered
& sold as a by-product
from final stripping, sent to
sulfur plant.
* These streams are all emitted to the environment.
** See Table 4 for details.
-------
- 18 -
Table 3 (continued)
•-'-- 75
76
77
water
ammonia
oil
532,193
est 4,000
— —
78
* 79
sludge
air
670,000,000
(31 MMM SCFD)
* 80
81
82
* 83
84
85
86
87
88
89
90
91
92
93
94
drift loss
blowdown
cooling water
flue gas
blowdown
steam
air
chemicals
water
additives
waste water
chemicals
air
water
plant fuel gas
est 100,000
301,555
60,634,000
1,246,560
61,123
242,331
780,000
**
1,813,208
"ff"ff
532,193
*•>•,-
670,000,000
(31 MMM SCFD)
60,634,000
78,000
treated waste water leaving plant
formed from nitrogen in coal
from API oil separator on waste
water treating, (add to oil product)
from biox unit on waste water - to be
dewatered & incinerated
air from cooling tower
water mist lost in air
water purge from cooling tower
recirculated cooling water
from utility boiler & turbine/gener.
water purge from steam gener.
generated in utility boiler
to supply oxygen plant
for water treating, lime,
alum, etc
raw makeup water
used to treat waste water, recover
phenol, oil, etc.
processed water from separators(includes
19,606 Ib/hr sour water which is part of
the waste water balance shown on p. 68).
additives to cooling water
air to cooling tower
water recirc. to cooling tower
fuel to steam & power gener.
* These streams are all emitted to the environment.
** See Table 4 for details.
-------
- 19 -
Table 3 (continued)
95 SRC heavy liq. 10,083 supplemental fuel for utility boiler
prod.
96 air 1,159,00 combustion air to boiler plus gas
turbine/generator.
97 boiler feed water 213,738 for steam generation - util. boiler
Footnote: ** For details on chemicals consumed, see Table 4.
-------
- 20 -
Table 4
SRC Process
Catalyst and Chemicals Consumption
(as indicated in report by Ralph M. Parsons)(11)
Catalyst or Chemical
Diatomaceous Earth Filter Precoat
Monoethanolamine (1)
Cellulose, Asbestos, and Diatomaceous Earth (1)
Corrosion Inhibitor (1)
Antifoam (1)
Hydrogenation Catalyst
Hydrogenation Catalyst
Monoethanolamine (2)
Cellulose, Asbestos, and Diatomaceous Earth (2)
Corrosion Inhibitor(2)
Antifoam (2)
Monoethanolamine (3)
Sodium Hydroxide* (3)
Active Carbon(3)
Corrosion Inhibitor (3)
Antifoam (3)
CO Shift Catalyst
Benfield Solution - K2C03
DEA
V2°5
Basis or Makeup
Requirement
20 tons/day
1750 to 7000 Ib/day
20 to 100 Ib/day
2 to 4 gal/day
5 to 10 gal/day
253,000 Ib (3-yr life)
2,700 Ib (3-yr life)
500 Ib/day
2 to 10 Ib/day
1/4 to 1/2 gal/day
1/2 to 1 gal/day
1500 to 5100 Ib/day
340 Ib/day"
50 to 100 Ib/day
1 to 2 gal/day
2 to 5 gal/day
2399 ft3 (1-yr life)
986 Ib/month
99 Ib/month
17 Ib/month
(1) Dissolver acid gas removal.
(2) Fuel gas sulfur removal.
(3) Gasifier and gas removal.
* Does not allow for significant consumption in sulfur cleanup from
gasification section, which could increase consumption by mora than
10 fold if all carbonyl sulfide is removed by reacting with sodium hydroxide.
-------
- 21 -
Table 4 (continued)
Basis or Makeup
Catalyst or Chemical Requirement
3
Methanator Catalyst 140 ft (3-yr life)
Zinc Oxide Pellets 71 ft (3-yr life)
BSRP CoMo Catalyst 750 ft3 (3-yr life)
Sulfur Recovery Catalyst 5200 ft3 (3-yr life)
Stretford Solution Chemical Makeup $386/day
Corrosion Inhibitor 319 Ib/day
Polymer Dispersant 319 Ib/day
Sulfuric Acid 3209 Ib/day
Chlorine 1766 Ib/day
Phosphate Polymer Antifoam 383 Ib/day
Hydrazine 2.7 Ib/day
Lime 2072 Ib/day
Aluminum Sulfate 1295 Ib/day
Caustic Soda 2135 Ib/day
-------
- 22 -
alternative is to burn part of the product gas as fuel in the dryer and
use bag filters or a water scrubber to control particulates. While
Parsons did not show the volume of flue gas leaving the dryer, their
fuel consumption is high, which may reflect a large excess of air. This
fuel consumption can be reduced more than 50% by using a minimum amount
of excess air and allowing a higher moisture content in the flue gas.
At the same time, the volume of vent gas to clean-up is similarly reduced.
4.2 Liquefaction and Filtration
Dried coal is pulverized to 1/8" and smaller and fed to the
liquefaction section at a rate of 416 tph. Again, control of dust and
noise is required for the handling operations.
The coal is mixed with twice its weight of recycle oil at 550"F,
to form a slurry at 368°F that is pumped to high pressure. Upon mixing,
moisture in the coal evaporates, is recovered in a condenser, and is
returned to the slurry, so that this water does not become an effluent
from the plant.
The slurry is mixed with recycle gas plus make-up synthesis gns
and fed to a pre-heat furnace where it is heated to 900°F. Operability
and erosion on this furnace,feeding a mixture of tar slurry and gas,
is considered to be a problem. Leaks or burn out of tubes could result
in serious emissions to the atmosphere. The furnace has a very large
heat-load and is fired with part of the product gas, generating 305 million
cubic feet a day of flue gas. Clean fuel is fired, and therefore sulfur
or particulates should not be a problem. A target value for nitrogen
oxides is 0.2 Ibs per million Btu's, as required on large stationary boilers
(15). It should be possible to meet this value by careful control of
combustion conditions in the furnace, possibly with staged firing of
fuel (16). Emission of nitrogen oxides needs to be estimated in any
actual application of the process.
Hydrogen is formed in the reactor by water-gas shift, consequently
considerable steam must be added to the reactor. This steam is
supplied by evaporating water recovered from the process which is thus
reused and does not become an effluent from the plant. This water may
contain some particulates and traces of oil. Fouling and corrosion of
exchangers used to evaporate such sour water streams can be a major
concern even if no particulates are present. In the Parsons design,
this process water is mixed with recycle gas and evaporated to dryness
by exchange with hot vapors from the reactor. This operation may
involve periodic depressuring for cleaning and special techniques
calling for careful consideration of environmental impact.
In general, this section of the plant is completely enclosed
and no streams are normally discharged to the atmosphere from the reactor
and filtering sections. However, the reactor operates at 1,000 psig,
so that any leaks on pumps, valves or other equipment can result in
serious pollution problems. For example, the air-fin coolers used
on the gas and liquid products have fans to move a very large volume
of air over the exchangers, and it is apparent that any leakage will
be dispersed in this large air stream. Further consideration of this
problem is needed to assure that the plant operations will be
environmentally satisfactory (17).
-------
- 23 -
Indirect best exchange versus recirculated cooling water is
used in the high pressure reaction section as well as in other parts of
the plant. It is common to find a small amount of leakage on conventional
exchangers in this type of service, particularly at high pressures such
as 1000 psig. Materials that leak into the cooling water can circulate
to the cooling tower where they will be stripped out by the large volume
of air passing through the tower. Special attention to this problem
has been given in the case of oil refineries and this experience should
be reviewed and applied in coal conversion operations (17).
Maintenance, depressuring, and purging of equipment will call
for special attention to control emissions. A special collection system
should be used to contain and clean up all purge and vent gas streams.
In the filtration section, slurry from the reactor passes
through pressure rotary filters to remove ash and residue from the oil
product. Again, the system is enclosed but is complicated due to the
operation of multiple units, pre-coating of filters, gas purge, and re-
slurrying of filter cake. Thorough consideration in the design is needed
with regard to potential leaks, spills, and pressure venting and shutdown
and servicing. A separate low pressure gas collection system may be
needed for purge from this area so that it can be scrubbed and reused, or
burned in one of the furnaces.
Pneumatic transport is provided on the filter aid used ss
precoat. Such systems can create a dust nuisance and efficient control
measures should be employed, such as bag filters at sub-atmospheric
pressure.
4.3 Product Handling and Hydrotreating
The primary product stream of filtered reactor liquid is
fractionated to give naphtha and a light distillate, both of which are
further hydrotreated. Heat for distillation is provided by a furnace
which generates a significant amount of flue gas. Since product gas is
used as fuel, it should be practical to meet the emissions requirement
for large stationary boilers with regard to sulfur, particulates, NOX,
and CO (16).
The product hydrotreating section also uses furnaces for pre-
heating before the reactor and on stripping the product. The comment
made on the distillation furnace applies here also. Hydrogen compression
is included in this section, and since it involves high pressure, the
possibility of leaks requires special consideration as discussed previously.
When the high pressure liquid products are depressured, a
considerable amount of dissolved gas is released, which should be recovered
or used for fuel. Similarly, when the sour water is depressured, ga.s will
be released which would cause a serious odor problem if vented to the air.
Facilities are, therefore, needed to recover this gas and send it to
the sulfur plant.
-------
- 24 -
When maintenance is needed on the high pressure facilities they
must first be depressured, and provisions should be made for recovering
materials released during the depressuring. In addition, the equipment
must be purged with inert gas, and again, recovery facilities should be
provided to avoid undesirable emissions to the atmosphere at such times.
A more detailed discussion is given in Reference (2).
4.4 Acid Gas Removal and Hydrogen Manufacture
Separate acid gas removal units are provided on: the gas recycled
to the reactor, product fuel gas, after the gasifier, and in hydrogen manu-
facture. Amine scrubbing is used to remove sulfur from the recycle gas to
aid desulfurization, and on the product gas so as to provide clean fuel for
use in the plant. Scrubbing removes H2S which goes to a sulfur plant. It
is expected that there will be other forms of sulfur present such as carbonyl
sulfide which will not be removed effectively by amine scrubbing. This is
particularly true for the gasification system supplying raw gas for hydrogen
manufacture since the high CO content of the gas results in a high furmatio::
of COS, as much as 1070 of the total sulfur content in some similar systems
(1). This will be removed by caustic scrubbing in the Ralph M. Parsons
design but creates a very large amount of spent caustic that needs disposal.
Some work has been reported on hydrolyzing COS etc. to l^S over catalyst, prior
to amine scrubbing (18), which would improve the situation. Scrubbing the
raw gas with hot carbonate may be preferrable, as it should remove COS
without consuming caustic. Perhaps a better alternative is to use the low
Btu gas from gasification as plant fuel where the clean-up requirements-
are less stringent, and then make hydrogen from product gas using well
demonstrated technology.
Trace components such as cyanides can react with amine to form
stable compounds which must be purged from the system. These can present
a disposal problem, although they can be incinerated. Also, some solid
materials are removed from the circulating amine liquid and the design
includes rather large filters for this purpose. The exact nature and
amount of these solids should be accurately determined so that proper
provision can be made for their disposal, and for control of atmospheric
contamination from odors, vapors and dust. The design shows vents to
the atmosphere from amine storage, the amine purge tank, and the amine sump.
These systems are blanketed with inert gas, and all such vent streams
should be collected and properly handled, for example, by passing to an
incinerator or furnace for destruction.
In the section making pure hydrogen for hydrotreating, all CO
in the feed gas is shifted with steam and the C02 scrubbed out using the
proprietary Benfield hot carbonate process (19). This makes a concentrated
C02 stream which is vented to the atmosphere (809 tpd C02), and assurance
is needed that it is low enough in sulfur, mist, and chemicals, etc., to be
acceptable, and that it is vented in a way to avoid hazards. One concern
xs that various sulfur and other compounds from gasification may be removed
along with C02 and contaminate the C02 vent stream. Additional facilities
may be required to clean up this stream, and we have added a scrubbing
system for this purpose to recover sulfur compounds. TTiese compounds arc
t lu'.n eoml> fiu.nl with the feed to the Claus plant for processing. Moisture
Ln this gas may cause a plume, which may be acceptable but should be
evaluated (1).
-------
- 25 -
The other effluents to the air from hydrogen manufacture are
flue gases from three furnaces supplying steam and sensible heat for
the hot shift reactors. Since fuel gas is fired, it should be possible
to meet target emissions, as discussed earlier in the section on
Product Handling and Hydrotreating.
4.5 Gasification and Slag Disposal
In this section the filter cake, mixed with twice its weight
of oil to facilitate handling, is gasified with oxygen and steam to
make low Btu synthesis gas. The gasifier operates at 1700°F in the'
top zone, 3000°F in the bottom zone, and 200 psig. It is a modification
of a system under development known as BI-GAS. Molten slag is removed at
the bottom and quenched to form steam which is returned to the gasifier,
while excess water forms a slurry with the fragmented slag so that it can
be withdrawn.
Of the oil-filter cake slurry charged to gasification, 3070 of
it goes to a top zone where the temperature is 1700°F. Consequently,
small amounts of tar or oil and soot may be present, in which case additional
recovery facilities may be required due to problems with exchanger fouling,
emulsion, etc. The design does provide a cyclone to recover dry char from
the raw gas and recycle it to the 3000°F zone, since the cake is not
completely gasified in one pass. A venturi scrubber is included for final
dust removal.
The main effluents to the air from this section are from two
furnaces preheating the feed streams to gasification. These furnaces
fire clean gas so that there should be no problem in meeting target
emissions, as discussed in the section on Product Handling and Hydrotreating.
One furnace preheats clean steam to 1050°F for feeding to the top of
the gasifier along with 30% of the slurry feed.
The other furnace heats recycle char suspended in gas and
steam, for feeding to the 3000°F zone along with the other 70% of the
slurry feed. This furnace is subject to erosion and possible plugging
due to the presence of solids. Tube failure, or maintenance and
cleaning could cause serious emissions which need further considera-
tion with regard to environmental impact.
Sour rater from scrubbing the raw gas contains sulfur compounds,
ammonia, phenols, etc. This stream is treated before discharge to extract
phenols, and goes to a sour water stripper which removes light gases
that are sent to the sulfur plant. It then flows through oil separators
and to a biox pond. This operation is enclosed and should be satisfactory
with regard to odors and air pollution, except that the oily .-ater
separator should be covered.
-------
- 26 -
'.?he slag quenching operation is described in general terms,
and the 3000rF gasifier zone is segregated from the water slurry,
quenching zone. No specific facilities are shown for particle size
control, such as grinding, and the system depends on the shattering
effect of quenching to form a pumpable slurry.
The design provides a slag storage pile in the coal storage
area, prior to back-hauling it to the mine. Since the slag is removed
as a slurry, it will have to be drained and stacked. Some of the slag
may be very fine, consequently there could be dust problems when it dries
out. The extent of odors and sulfur emissions in this operation needs
to be determined. Also, '--ater from draining must be recovered and reused,
since it will contain considerable suspended solids. It can be
recirculated through the storm pond, provided this does not cause
secondary pollution problems due to odors or leachable materials.
On the basis shown there should be no streams released to the
air from the process equipment on slag handling, since the steam from
i,uenching is returned to the gasifier, and the slag is handled as a slurry.
However, the possibility of secondary pollution must be clarified.
Dusting has been mentioned, and there could be release of sulfur and
odors since the slag is formed under reducing conditions. Studies on
the chemistry of the calcium-sulfur systems have been made in connection
with controlling sulfur pollution on coal fuel (20). In some cases the
spent ash has been reacted with CC>2 and water to remove sulfur before
the ash is disposed of (4), and this may provide one way to control
secondary pollution.
4.6 Auxiliary Facilities
In addition to the main process, various auxiliary facilities
are needed,such as the oxygen plant, sulfur plant, utilities, water
treating, and product storage, which must be considered from the
standpoint of effluents to the air. The oxygen plant is relatively
clean and the only major effluent is rejected nitrogen which can
be used for purging, in which case clean-up of the purge gas should
be provided. The oxygen plant is a large consumer of power and
therefore has an important effect on thermal efficiency and energy
consumption. One approach uses electric drives on the main air
compressor, but where clean fuel is available a flue gas turbine
may be more attractive. Or a high pressure bleeder steam turbine
can be used, for example generating steam at 600 psig or higher and
depressuring it through the turbine to say 125 psig to supply steam
for reboilers on acid gas removal, preheating, etc. When a specific
plant design is made, it will be important to optimize the utilities
system.
-------
- 27 -
The sulfur plant uses a Glaus unit, with tail gas clean-up.
Concentration of H2S in the feed is only 7.7 mole percent, resulting
in a low sulfur recovery on the Glaus unit. Therefore an efficient
tail gas clean-up system is needed and there are a number of available
processes to choose from. The design is based on using the proprietary
Beavon process to reduce residual sulfur compounds to H2S, which
is then removed in a Stretford type scrubbing operation (21) • Other
systems could be used for tail gas clean-up such as the IFF, Takahax,
Wellman-Lord or Scot processes (22)- Vent gas from the tail gas clean-up
operation can be vented to the atmosphere without incineration in some cases
The Stretford type process uses a scrubbing liquid containing.
catalyst to oxidize H2$ to free sulfur (23). The scrubbing liquid
is then reoxidized by blowing with air, and precautions must be taken
to avoid release of odors or entrained liquid etc. to the atmosphere.
This air effluent should pass through an incinerator or furnace unless
it is clear that P^S and other emissions will be acceptable.
Product sulfur may be handled and stored as a liquid in
completely enclosed equipment to avoid emissions. If it is handled
and stored as a solid, control of dusting will be required.
Several factors tend to reduce efficiency of a Glaus
plant, including the presence of combustibles such as ammonia or
hydrocarbons in the feed, which require additional air for combustion.
Carbon dioxide or water vapor act as diluents, with a corresponding
increase in volume of tail gas from the Glaus section. The effect of
inerts is illustrated by the following table which shows the relationship
between % H2$ in the feed gas, and tail gas volume relative to
feeding 100% H2S.
% H^S in Feed Relative Gas Vol.
100 1
25 2
15 3
10 4
8 5
Higher gas volume means that more tail gas must be cleaned up to a
lower residual sulfur content, for the same T/D sulfur to the air.
Moreover, at low % l^S, extraneous fuel may have to be fired in order
to hold the needed temperature in the 1st stage burner, further
contributing to inefficiencies.
-------
- 28 -
High CC>2 in the feed can significantly increase formation
of COS and €82, while ammonia contributes to NOX formation (24).
Techniques are available for removing these gases to give a higher
concentration of H2$ to the sulfur plant, but the desirability
of doing so will depend on the particular situation and should be
evaluated.
The largest volume of discharge to the atmosphere from the
utility area is on the cooling tower. Air flow through it is about
31,000 MM cfd, and it is therefore critical from the standpoint
of pollutants. It might be expected that the recirculated cooling
water would be perfectly clean and free of contaminants, however,
experience shows that there will be appreciable leakage in exchangers
and occasionally tube failures, especially with high pressure operations.
In the present design cooling water is exchanged with oil, sour water,
raw gas, amines, etc.; therefore, contaminants may get into the
circulating cooling water and then be transferred to the air in the
cooling tower, which necessarily provides effective contacting and
stripping.
In oil refining and petrochemical operations, the cooling tower
is often a major source of emissions from the plant, and techniques have
been developed for making quantitative estimates of the loss (17). Control
measures are also described, with emphasis on good maintenance on valves,
pump seals, etc., plus floating roof tanks or vapor recovery as needed.
In critical cases monitoring instruments should be used to detect leaks.
Cooling towers also have a potential problem due to drift
loss, that is mist or spray which is carried out with the effluent
air. Since this contains dissolved solids it can result in deposits
when the mist settles and evaporates. In addition there is a
potential plume or fog problem, if the atmospheric conditions are
such that moisture in the air leaving the cooling tower condenses
upon mixing with cooler ambient air. This occurs whenever the mix
temperature is below that corresponding to saturation. Although
reheating the effluent air will prevent the plume, it is not normally
warranted and consumes energy unless it can be accomplished using
waste heat.
The utilities section includes a boiler to provide steam
and electric power. It has a large gas effluent, so that
emissions of dust, sulfur, NOX and CO must be controlled. The
large fuel consumption of the boiler has a correspondingly large
effect on thermal efficiency of the overall plant.
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Dust emission can be controlled with demonstrated conventional
equipment such as cyclones, electrostatic precipitators, or scrubbers.
Sulfur can be removed as required, by one of the many processes offered
for this use (31,32,33). Processes are available from the following:
Wellman-Lord Chiyoda FMC Corp.
Chemico Showa Denko Mitsui S.P. Inc.
Combustion Engineering Babcock & Wilcox Davy Power Gas
Universal Oil Products Lurgi Stauffer Chemical Co.
Research Cottrell Enviro Chem. Systems
Some of these are commercially demonstrated and others are under-
going large scale tests.
NOX may be decreased by controlling the combustion conditions
and by staged firing (16). Even so it may be difficult in some
cases to meet the target emissions set for large stationary boilers.
Considerable work is under way on methods to remove NOX from the flue
gas. While N02 is relatively easy to scrub out, it is found chat
most of the NOX is in the form of NO which is very difficult to
remove due to its low solubility in water. One answer is to convert
NO to NOo which can then be scrubbed out, but a simple, efficient
way to accomplish this is not yet available. Other approaches are
to effect chemical reactions with NOX to decompose it to free
nitrogen gas. The problem is receiving in tensive effort and it
is expected that at least one demonstrated process will be available
in the near future for use on utility boilers.
Thermal efficiency of any coal conversion process must take
into account the fuel consumed in utilities generation, since this can
amount to 15-25% of the main process. In general it is desirable to
burn low grade fuel such as char or coal rather than high value product
gas or liquid. In the case of the SRC process its purpose is to produce
clean boiler fuel so that it is reasonable to use this product to supply
utilities fuel, as required. It is important to achieve high efficiency
in generating utilities and the combined cycle is, therefore, receiving
a lot of attention. In the combined cycle, a gas or liquid fuel is burned
at perhaps 10 atmospheres pressure, giving hot gases which are passed
through a turbine to generate electric power and then to a boiler generating
high pressure steam. Solid fuel, such as coal, can also be used by
gasifying the coal and cleaning up the raw gas to provide low Btu gas
fuel for the turbine. Such alternatives need to be evaluated carefully
in each specific application in order to define the best combination.
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water from liquefaction contains compounds with strong
odors, such as phenols, H2S, and ammonia. In the waste water treating
section, phenols, etc. are extracted from the sour water by contacting
it with a light oil, which is then recycled through catalytic hydro-
genation to destroy compounds containing oxygen or nitrogen. The raf-
finate is then stripped to remove H2S, ammonia, and traces of oil and
solvent which are disposed of to the sulfur plant. Ammonia might be
recovered as a by-product, as has been described in the literature (25).
However, most of the nitrogen in the coal remains in the oil product and,
therefore, the production of ammonia is small.
Depending upon the efficiency of the extraction and stripping
operations, the level of contaminants in the waste water may be reduced
to a level low enough to be acceptable without over-loading the biox unit.
An oil separator is provided ahead of the biox. Except for this and the
biox unit, these facilities are all enclosed in order to avoid any direct
effluents to the atmosphere. Sour water from the gasification and product
hydrotreating areas is also stripped to remove F^S and ammonia prior to
discharging to the biox unit.
In view of the very strong odor created by phenols and by
components in the sour water, careful consideration should be given
to this in planning and designing all plant facilities. All oil-water
separators should be covered to contain odors, and it is possible that
the biox unit will also need to be covered. Further experimental data
should be obtained to define the requirements for this. The SRC oil
product contains various oxygenated compounds, including phenols and
cresols^as well as relatively large amounts of nitrogen compounds such as
pyridine types. These have very strong odors and can create problems in
handling and storage.
If the product is solidified by cooling in a prilling tower
with direct contact with air, obnoxious fumes can be formed (similar
to those generated in asphalt oxidation). These cannot be discharged
to the atmosphere and might be incinerated, or gas recirculation could
be used with indirect cooling. An alternative is to solidify the product
OR a metal belt which is cooled by exchange with water. Instead of making
a solid product, it could be kept hot above the melting point and handled
as a liquid, in which case it will be important to exclude air from the
storage and handling facilities. Tests on similar type materials have
shown that oxidation reactions induce polymerization, resulting in a large
increase in viscosity, and potential gum and asphaltic deposits (26).
Storage tanks are needed with inert gas purge which is vented to the in-
cinerator to control emissions and odors.
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5. EFFLUENTS - LIQUID AND SOLID
5.1 Coal Preparation
Large size coal is brought from the mines by rail or truck
and passed through a breaker to reduce it to 3 inches and smaller.
Oversize refuse from this operation is returned to the mine, vhile the
coal is stored in a pile having 3 days capacity. In all of the storage
and handling area consideration must be given to the problems of spills
and contamination due to rain run-off. This water can become acidic
due to reaction for example with pyrite. There is also the possibility
of extracting organics or soluble metals from the coal or gangue.
Therefore, this run-off water should be collected and sent to a storm
pond, separate from that for the process area so that oil contamination
is minimized. This pond should have a long enough residence time for
solids to settle out and there should be a certain amount of biological
action which will be effective in reducing contaminants. It may be
desirable to add some limestone to this circuit if needed to correct
acidity. The problem is somewhat similar to acid mine water and should
be reviewed from this standpoint (27).
Water from this retention pond will be relatively clean and
low in dissolved solids and therefore is a good make-up water for the
plant cooling tower circuit and for preparation of boiler feed water.
Where all of the run-off can be used in this way, it will not constitute
an effluent from the plant.
Leakage or leaching from this storm pond must also be
considered. Normally, this should not be a serious problem but in
some cases overflow from retention ponds in heavy storms has contributed
to stream pollution. Seepage through the bottom of the pond into
the ground water must also be controlled. In some comparable situations,
seepage down through a process area can be a problem in addition to the
runoff. Even though storm sewers collect the runoff in a chemical plant
or oil refinery, leaks and oil spills can release enough material such that it
actually seeps down into the ground water supply. If the ground contains
a lot of clay this will not usually be a problem - in fact the clay can
absorb large quantities of metallic ions. In sandy soil it may be
necessary to provide a barrier layer underneath the coal storage piles.
This could be concrete, plastic or possibly a clay layer. Storm severs
from the process area should also be collected and sent to the pond. In
the present design this may be satisfactory, but if there is a likelihood
of serious spills of oil or phenols, the process area should be drained
to a separate holding pond for treatment.
In the washing and screening system,the coal is handled as a
slurry with the water recirculated, so there should be no net effluent from
this operation. The recirculated water passes through a thickener, the
over flow from which provides the recirculating wash water. Bottoms
from the thickener go to a tailing pond where particles smaller than 1 mm
are removed by settling, so that the water can be recirculated and reused.
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Some suitable provision will have to be made to dispose of
the Iprge amount of waste solids rejected from the coal cleaning
operation. The overall balance shows 2500 tpd of this material. To
the extent that this is coarse material it should not present f> serious
dusting problem, hovever, the pyrites content can be expected to
oxidize and subsequently be leached out, resulting in possible con-
tamination of natural water with acid, iron, or other materials.
Rejected fine solids, 1 ram and smaller,accumulate in the tailing pond.
The sheer magnitude of this stream poses a major problem which calls
for very careful and thorough planning. The fines amount to 52 tph of
solids. To put this in perspective, if the tailing pond has a surface
area of 1 acre and the fine solids are at 100 Ibs per cubic foot, then
the sediment will build up ft a rate of 180 feet per year. Obviously,
this material will have to be reclaimed from the tailing pond and
disposed of off-site. Perhaps it can be used as land fill provided
leaching is not a problem, but the material is very fine and if it dries
out it may constitute a dust nuisance. Land reclaimation studies have
been made on similar materials and these should be studied thoroughly
in planning disposition of refuse from coal cleaning operations. (14)
The next solid effluent is from coal drying, where the ground
coal is suspended in f> large volume of gas. Dust must be recovered
efficiently and a target is 0.1 Ibs of particulates emission per MM
Btu fired for large stationary boilers. For dust removal
bag filters, water scrubbing, or electrostatic precipitation might be
used. The recovered coal fines could be used in the process, or as fuel,
to the extent sulfur emissions are acceptable ; in which case, dry recovery
would seem to be advantageous. An alternative is to slurry the fines in
water and feed them to the liquefaction reactor. Moisture in the coal
evaporates in the slurry mixing tank and this water vapor is then con-
densed and returned to the reactor, therefore it provides a convenient
stream to use for slurrying fines returned to liquefaction.
5.2 Liquefaction and Filtration
The large volume effluents in this section are from the furnaces
and air fin exchangers. While these have a large impact on the air
emissions, they should not contribute substantially to the water or solids
effluents. There is considerable handling of coal slurry, and, in addition,
the precoat used in filtration requires storage and handling. All of
these operations are enclosed so that normally they will not generate
undesirable effluents. The process operates at high pressure
and therefore leaks on valves, pump seals, etc. can be expected, and '-'ill
cause pollution problems unless adequate plans and provisions are included
in the project planning.
For example, leaks in the process area will cause odors due to
the cresols and other minor components in the liquefied coal. Experience
shows that even a severely hydrotreated oil from similar operations still
retains a distinctive odor of cresols. Oil leakage vill be washed off
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by the rain and can get into the ground water or streams possibly causing
a very undesirable taste. Therefore, drainage from the process area
should be collected in separate sewers for special handling. Oil separation
on the water is needed, for example by API type separators as used
in oil refining, and possibly froth floatation, and activated carbon
for odor control. The effluent can then be discharged to a holding
pond and further treated as required to make it suitable for reuse as
make-up water.
Sour water is separated from the reactor effluent by settling,
and, in. the design, it is recycled to the reactor after mixing with the
coal slurry ahead of the preheat furnace. To the extent that this is
practical without undue corrosion and fouling, it affords a very desirable
disposition of sour water. If an alternative use is needed because of
operating problems, it may be necessary to add a sour water stripper.
As this is a large stream, such a sour water stripper would result in
additional fuel consumption.
The filtration step is an area of potential leaks and spills
in that it is complicated, involves solids handling, and operates at
elevated temperature and pressure on a heavy viscous oil. Also the filter
cake is scraped off pnd then reslurried with oil for transfer to
gasification. During normal operation there should be no intentional
effluents from this system since it is totally enclosed, but a question
arises with regard to start-up, shut-down, maintainence, and upsets.
No doubt there will be times when the filter cake must be temporarily
stored and later worked back into the process, so careful planning is
needed in this area. No mixing system is indicated for reslurrying the
filter cake, and presumably a mechanical system will be used.
For the specific design there are no major liquid or solid
effluents from the liquefaction and filtration sections. The system
is enclosed and all of the streams flow to other sections of the
process. However, it should be noted that if the sour water from the
reaction should become an effluent, rather than being recycled and
reused, then the clean-up of this vaste water stream would call for a
great deal of study. Some aspects to consider are discussed in Section 6.
Complications may result due to release of trace elements during
the liquefaction reaction. A few of these such as titanium tend to stay
with the oil, while heavy metals such as chromium would be expected to stay
with the ash, along with alumina, calcium, and silica. There are also
probably a number of trace elements that are released in volatile or
water soluble forms, including arsenic, antimony, cadimum, zinc,,selenium,
fluorine, etc. What ultimately happens to these in the process is not
clear at this time. Some of them may show up in the sour water, all of
which is recycled to extinction in the reactor, in which case they will
build up in concentration in the circulating sour water and have to he-
separated and purged from the system, and then disposed of in some
environmentally sound manner. If volatile compounds are formed such as
arsine and metal carbonyls, they will show up in the gas stream and have
to be removed. In addition to trace elements, compounds such as cyanides
and thiocyanates may form and tend to build-up in the recycle streams.
Possibly they will be converted in the reactor to reach an equilibrium
concentration - if not, then purging may be necessary.
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5. 3 Product: Handling and Hydro treat ing
The major effluents in this area are to the air from furnaces
and air fin exchangers, but there is also a significant production of
sour water. This is associated with hydrotreating part of the heavy SRC
product to lower its sulfur content, which produces H2S as veil as ammonia.
Water is injected and mixed with the oil to absorb these contaminants.
Production of sour water is about 32 ,000 Ibs per hour and it contains
about 1.5% each of ammonia and I^S. Some of the combined oxygen in the
oil is also removed as water.
The sour water stream must be cleaned up in the waste water
treating section. In addition to ammonia and H2S this sour vater will
contain oxygenated compounds such as phenols as well as traces of oil,
cyanides, etc. Hydrotreating of the naphtha product also produces a
sour water stream which is similar but smaller in volume and can be
combined for waste water treating. (See Section 6.)
Acid gas removal is used on the liquefaction reactor recycle
gas stream, on the product fuel gas, and in the gasification-hydrogen
manufacture section. Amine scrubbing is used in each of these. Some
purge of the amine solution will be needed because of the presence of
contaminants which form stable products, but additional data are needed
in order to define the amount. The purge can be disposed of by incin-
erating in one of the furnaces unless some other suitable disposal is
defined.
The design includes filters on the recirculating amine solution.
The nature of the solid removed by the filter is not specified, but if it
is residual ash from the coal then it may be possible to simply include it
in the slurry fed to gasification. Definition of the amount, composition,
and disposition of this material is needed.
In hydrotreating with pure hydrogen at high pressure most of the
sulfur removed will be in the form of H2S, which can be separated effectively
with amine. Since in this particular design the liquefaction reactor oper-
ates on synthesis gas rather than pure hydrogen, a considerable amount of
carbonyl sulfide will also be formed. Amine is not effective for removing
carbonyl sulfide, therefore, it would appear that additional scrubbing is
needed in order to remove it. Hot carbonate scrubbing may be satisfactory,
or perhaps the carbonyl sulfide could he hydrolyzed to H2S over a catalyst
prior to amine scrubbing. (18) Since it is expected that pure hydrogen will
be used rather than synthesis gas, this problem can be avoided.
The hydro-treated products will be liquid and can be stored
and sold as such. In liquid storage tanks, some ash may accumulate on
the bottom and have to be removed periodically. Perhaps this can be
processed ?>long with the filter cake. The gas product is all used as
plant fuel and should not cause pollution. The heavy SRC product will
be solid at room temperature and may be handled in this form, or it may
be melted by heating. It does contain some residual ash and when burned
most of this will appear in the flue gas. In order to meet the target
for particulate emissions from stationary power plants of 0.1 Ibs per MM
Btu, the ash content of this product should be less than 0.157.,. The
reported value of 0.1% ash should be satisfactory, provided the level
of trace elements is acceptable.
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In addition to the primary products from the process there will
be by-products such as sulfur. This can be stored and handled using well
established techniques to avoid pollution problems. There is also some
ammonia formed in the process from the nitrogen content of the coal. In
many cases, it will be feasible and desirable to recover this in pure
form for sale as a by-product. An alternative is to incinerate it or send
it to the sulfur plant, although it is undesirable as a feed constituent
in the Glaus Plant since it vill reduce the sulfur recovery.
Results of coal liquefaction indicate that most of the nitrogen
remains in the heavy product, so the ammonia yield may be too low to
make its recovery attractive. On the other hand, the high nitrogen
content of the product, over 17», will tend to cause a NOX problem when
it is burned so that special corrective measures may be needed.
5.4 Acid Gas Removal and Hydrogen Manufacture
Hydrogen is manufactured from part of the synthesis gas produced
by gasification, after it has been scrubbed with amine pnd then caustic.
This gas is heated, mixed with steam and passed over a shift catalyst to
react the carbon monoxide to carbon dioxide and hydrogen. Carbon dioxide
is then scrubbed out with hot potassium carbonate, using the proprietary
Benfield process. (19) The raw synthesis gps contains considerable
carbonyl sulfide and probably other forms of sulfur, which are not removed
by amine scrubbing. The specific means of removing carbonyl sulfide is
not described in the design. The caustic scrubbing step should give good
cleanup, but will generate a large amount of spent caustic to dispose of,
possibly more than 100 tpd, and a suitable process for reworking it would
be needed, or more likely, a different process could be used for acid gas
removal, such as hot carbonate, which would avoid this complication. A
final raethanation step is included to reduce the CO and C02 in the product
hydrogen to 50 ppm each.
The largest effluents from this section are the atmospheric
emissions from the furnaces which will be firing clean gas fuel. Little
contribution to liquid or solid effluents will occur.
A water stream amounting to 27,168 Ibs per hour is shovn as an
effluent from the Benfield C02 Removal Unit. It is also indicated that
this may contain some carbonate solution, which may include a purge clue
to contaminants in the gas. The exact nature of this discharge needs to
be defined and a satisfactory means of disposal worked out. The C02
stream removed by scrubbing is discharged to the atmosphere and presumably
is a clean gas stream. However, this also must be defined more exactly,
as it is sometimes necessary ro provide further cleanup, or incineration on
such streams. There are various water condensate streams from
the hydrogen manufacturing section, but these are clean and can be used ac
boiler feed water make-up. The operation uses fixed beds of catalysts fox
shifting and methanation which will require replacements at intervals, and
should be disposed of by returning to the manufacturer for re-working or disposal.
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5.5 Gasification and Slag Disposal
In this section, synthesis gas is made by reacting a slurry of
the filter cake with steam and oxygen in a slagging gasifier. The filter
cake contains residual ash from the coal amounting to 713 tons per day,
together with 818 tpd of unreacted char, and is mixed with 1530 tpd of
oil to form a pumpable slurry. Oxygen consumption is 1964 tpd while the
fot.-il steam rate to gasification is 1837 tpd and the steam conversion is
6 5%.
Hot raw gas is cooled in a waste heat boiler and then scrubbed
with recirculated water to remove dust. This water stream could present
a difficult disposal problem since it is sour water containing partirulnti-s.
In the specific design it is reused in the gasifier by first vapor i 7. \ ny,
it in an exchanger and then preheating to 1050°F in a furnact-. Tin.' pi^-snar
of particulates may cause plugging or erosion of the equipment, which
could result in emissions to the environment. There may also be some
tar or oil in the raw gas from gasification which would be scrubbed out
by the water and would require disposal. If an alternative disposition
of this stream is required, it could be passed through a settler to
remove most of the particulates, and processed in a sour water stripper
to remove ammonia and t^S, and then to an oil separator, if required,
before being discharged to a large settling pond. Water from this pond
would then be returned through make-up water treating facilities to assure
satisfactory operation of the steam generation and super-heating equipment.
There is a sour water stream from the raw gas clean-up section
which is essentially free of particulates since it comes from a second
stage condenser. This stream goes to a sour water stripper, and from
there to a biox unit and then to the settling pond for reuse.
While the amounts of H2S and ammonia have been reported for
the water recovered from the raw gas, results from other coal conversion
operations suggest that there will also be smaller amounts of other
contaminants such as phenols, naphthalene, tar, cyanides, thiocyanates,
etc. Information is needed on the amounts of these and on their rates
of destruction in biological oxidation, in order to avoid problems
such as the past experience on non-biodegradable detergents.
Information obtained on waste water from coking ovens (28) which
should be somewhat comparable, show that certain compounds, such as thiocyanates,
are decomposed very slowly, and various interactions also interfere with
biological oxidation. Other compounds such as benzene and naphthalene can
not be destroyed in a biox unit, and are not detected by the BOD and COD
determinations.
Waste chemicals from water treating are neutralized and sent to
the settling pond together with sludge and boiler blow down. Sediment from
the pond could be reclaimed and disposed of along with the slag from gasi-
fication or fines from the tailing pond.
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A major solid effluent from gasification is the slag. Molten
ash leaves the bottom of the gasifier and is shattered by dropping into
water to form a slurry, while the steam which is generated flows back
into the gasifier. The slurry of slag is flashed and pumped to a
storage pile in the coal feed storage area. There may be odors from the-
slag pile, as well as leachable materials such as sulfates or chlorides
of calcium and magnesium etc. Additional information is needed
on this subject.
Water drainage and storm run-off from this area should be
collected and sent to a pond. The slag can probably be used as land
fill or returned to the mine, provided odor, sulfur emissions, leachables,
and dusting are acceptable.
5.6 Auxiliaries
One of the auxiliary facilities is the oxygen plant. It has
no solid effluents and the only liquid effluent is condensed water
which can be used for boiler feed water.
The sulfur plant produces marketable sulfur as a major product
amounting to 317 tons per day. The basic Claus plant is conventional
and techniques for controlling effluents are well established. The
proprietary Beavon process is used to clean-up the tail gas by adding
a reducing gas to convert sulfur compounds to H2S, which can be removed
by processes such as a Stretford type. The latter operation will
generate liquid effluents, since some of the scrubbing solution must
be purged in order to maintain activity. One way to dispose of it
is by incineration.
Other auxiliaries include the usual generation of steam and
power utilities, as well as a cooling tower and make-up water treating.
Since the boiler is fired with clean product gas it does not gent-rate
solid effluents such as slag. Water treating produces most of the
solid and liquid effluents from this utility area. Chemicals used in
water treating include lime, aluminum sulfate, caustic soda and sulfuric
acid. The amount of various chemicals used in the plant are summarized
in Table 4. All of these will become effluents from the plant, part
as dissolved salts in the effluent water and the remainder as sludge
accumulated in the settling ponds. The sludge is relatively innocuous
provided the leachables are not excessive,and it can be disposed of along
with the slag from gasification.
The specific Parsons design shows a rather large waste water
discharge amounting to 30% of the make-up. This includes boiler feed-
water blow down, cooling tower blow down, sour water to biox,and the water
from sanitary sewers. The total waste water discharge is 1,064 gpm compared
to the make-up of 3,626 gpm. It appears that much of the water blow
down could be treated and reused without reaching excessive levels
of dissolved solids in the cooling tower circuit. Thus, the boiler
blow down of 120 gpm can be used as make up to the cooling tower.
Evaporation from the cooling tower is about 1800 gpm and it would be
expected that the water blow down rate could be appreciable less than
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the 600 gpm provided, without having too much build-up in dissolved
solids. The best disposition of the waste water effluent from the
plant will depend upon its location and the specific situation. It
might be used to slurry the ash and solid refuse from coal cleaning for
return to the mine, or it may be acceptable to discharge it to a river.
Composition of the major components in this discharge water are needed
in a specific case in order to determine whether the method of disposal
will be satisfactory.
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6. WATER TREATING AND WATER MAKE-UP
6.1 General
In considering the general problem of cleaning up waste water,
it is convenient to think in terras of the types of materials present that
can have detrimental effects if released to the environment. The following
types of materials can be expected in waste water from the SRC process (and
from many other coal conversion operations).
participates: ash, carbon, sludge
soluble inorganics that would require evaporation
if they must be removed: sodium chloride and
sulfate, etc.
suspended oil drops that may be removed by froth
flotation (or settling if high density)
soluble organics or inorganics that can be removed
by stripping: butane, benzene, ammonia, hydrogen
sulfide.
soluble organics that have to be removed by
extraction: phenol, cresols, etc.
The last item above warrants further comment, particularly for coal lique-
faction since it has substantial amounts of oxygenated compounds in the
product. If the product is used as boiler fuel, these would be burned
and should be no problem; however, some of them will be appreciably
soluble in the water layer separated from the reaction products, and
will complicate the clean-up of this waste water stream for reuse or for
discharge to the environment. An indication of the problem is shown by
the solubilities of pertinent compounds in water, as given below for 68°F.
Benzene 0.18 wt. %
Toluene 0.05
Cresols 2.0
Phenol 8.3
These are for pure compounds, so the concentration in the actual water
layer from coal liquefaction is probably much less, although data are not
available. Such data should be obtained early in the pilot operation.
The point is that the concentration of many organics and inorganics
in the water layer will be much too high to allow an effective biox clean-up
directly. In the present design, the water layer is extracted with light
oil to remove phenol, cresols, etc., which are recycled through hydrogenation
to destroy them. Other processes are offered for this service, such as
Phenosolvan (Lurgi). The water is also processed in a sour water stripper
to remove more volatile organics and inorganics which are sent to the sulfur
plant. At this point the contaminants are reduced to a low enough level
so that biological oxidation should be effective (e.g. 10-50 ppm ea.
NH3, H2S, phenol.)
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6.2 Biological Clean-Up
As in many coal conversion operations, the SRC process generates
water streams containing considerable quantities of chemicals which must
be removed. In general, the types of chemicals are oxygenated compounds
such as phenols and organic acids, nitrogen compounds such as cyanides
and ammonia, and sulfur compounds including hydrogen sulfide and thio-
cyanates. Most of these can be removed to a low level using known tech-
niques, for example, phenols can be extracted with a solvent and recovered
or recycled, while ammonia and HoS can be removed by a sour water stripper.
However, in any practical operation there will still be a residual content
of chemicals in the treated water which must be removed before the
water can be discharged from the plant or reused in the process. In general,
a biological oxidation (biox) system is depended upon to do the required
clean-up in an activated sludge system, a trickling filter, or an aerated
biox pond.
Biological oxidation has been found to be reasonably effective
on many contaminants that are of concern in coal conversion operations,
such as phenols, cyanides, ammonia, and t^S. However, it is less effec-
tive on certain compounds such as thiocyanates. In one extensive test on
waste water from coking plants (29) the percent removal in 24 hours was
found to be as follows for various compounds.
Phenols 99.9%
Ammonia 90%
Chemical Oxygen Demand 80%
Cyanides 57%
Thiocyanates 17%
A further concern is that certain compounds may be completely resistant
to biological degradation. An illustration of this is the past world-
wide experience with synthetic detergents made from alkylated benzene.
While these were very effective detergents, they were not degraded or
decomposed in the environment and often resulted in severe foaming of
large rivers and drinking water. It is quite possible that similar aromatic
type materials or other compounds may be present in the waste water from
coal gasification or coal liquefaction operations, and that these compounds
may not be biodegradable. This also raises the question as to whether such
materials can be determined by the usual analytical tests to measure BOD
and COD. Tests made on waste water from coking overs (28) show that these
are both problems, for example with benzene or naphthalene. One further
example is the use of cresols to protect posts or telephone poles from
decay in the ground. Such treatment is very effective for a period of many
years and would seem to indicate that the treating material is extremely
resistant to biological destruction.
'L'here are biological systems that will consume stable materials
such as asphalt, but the action is extremely slow as can be seen from
the long life of asphalt roads. Similarly, the high resistance of heavy
oils and carbonaceous materials is illustrated by the existence of
extensive deposits of tar sands, oil shale, and coal.
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- 41 -
A further point is that various chemicals are more or less
soluble in water and very resistant to biological degradation. For
example, the solubility of benzene in water is 1750 ppm at 68°F
and it would probably not show up in the biological oxygen demand
(BOD) determination, or as chemical oxygen demand (COD). Benzene
specifically may be partially removed in a sour water stripper, but
other compounds may not be removed.
Cresols are much more soluble in water than benzene (2-2.5 wt. %)
while phenol dissolves to the extent of 8.3 wt. %. Since these are among
the many types of compounds expected to be formed in the process, efficient
recovery of them is necessary, together with a very thorough clean-up
of all effluent streams to be sure that they do not result in serious
environmental problems.
An important consideration is that biological systems may take
weeks to become well established. Specific organisms are needed to
consume the various types of compounds present. Moreover, careful balance
is needed between the chemical loading and the available oxygen dissolved
in the waste water. In many cases, additional aeration is needed to
provide sufficient oxygen for the biological oxidation. In addition,
nutrients such as nitrogen, phosphorous, iron, copper, molybdenum,
etc. are also essential for cell growth. On the other hand, excessive
amounts of these same elements can be highly toxic.
The importance of oxygen availability can be illustrated in
more quantitative terms. A typical cell composition can be represented
by the empirical relationship C5H702N (30). On this basis it takes
at least 1/2 pound of oxygen per pound of hydrocarbon consumed, and
over 2 pounds of oxygen per pound of nitrogen incorporated into the
cell. Since the solubility of oxygen in water will be only 6 or 7 parts
per million it follows that re-aeration of the waste water will be
needed in most cases in order to maintain aerobic conditions. One way
to do this is with floating aerators on the biox pond, using one of the
many types being offered for this service.
Biological oxidation of ammonia requires additional food
containing organic carbon for the organisms. It has been shown that
methanol is suitable for this purpose. Thus, in some cases, it may
be necessary to add either organic carbon or nitrogen compounds to
provide the proper nutrient balance. It will, of course be difficult
to maintain exactly the correct balance and to completely consume all
of the different nutrient materials, therefore, very careful monitoring
and adjustment of the nutrient balance may be necessary for an effective
biox system.
Once it is established and stabilized, biological oxidation
can be very effective. However, it will be sensitive to surges in
input, for example an increase in inlet loading will increase the
-------
oxygen consumption and can result in anaerobic conditions which
would destroy the culture. On the other hand, a decrease in inlet
loading would cause cells to die because of lack of food. Decomposition
of the dead cells would then cause further problems. A variation in
loading of more than 2 to 1 from normal can be expected to disrupt a
biological system. This makes it difficult to accomodate upsets on
the plant, or shutdowns for maintenance.
In general, the biox system can be a practical and satisfactory
way to dispose of various contaminants that are present in small
concentration and would be difficult to remove from waste water by
stripping or extraction. In addition, use of activated carbon should
be carefully considered for final clean-up of the water, and it may
be needed in order to remove certain compounds that resist biological
degradation or that are not removed completely by it. In any event.
activated carbon may be useful in order to clean-up the water sufficiently
so that it can be reused in the process. While activated carbon has been
quite expensive in the past there are several indications that a low
cost substitute may be available as a by-product from coal gasification.
Tests have been made on the spent char from such operations, and the
char has been quite effective for adsorbing such things as phenols.
6.3 Sludge Handling
In designing facilities for biological oxidation of waste water,
consideration must be given to the resulting sludge to be handled and
disposed of. By way of example, if the plant generates 1064 GPM of waste
water containing 10 ppm ammonia, this could be expected to make roughly
0.5 tons per day of cellular material. It is difficult to concentrate such
cellular sludge by settling, and the settled sludge may only be at 5%
concentration in water. This would give 10 tpd of sludge (2 acre ft/yr)
which might be disposed of along with the ash or slag from the coal. The
sludge could be concentrated further by centrifuges or filters, and disposed
of by incineration to recover its fuel value. Or it can be used for land-
fill or soil conditioning provided it is shown that the particular sludge
is suitable and does not result in offensive odors for example. Some
sludges have been dried to a granular material which is sold for soil
conditioning.
There are particular biological systems that are active only
in the absence of oxygen (anaerobic). Such systems can decompose nitrates
to nitrogen gas provided suitable organic carbon is also available, and
at the same time generate methane and carbon dioxide. These systems
can also decompose other nitrogen and sulfur compounds, resulting in
strong offensive odors as is often the case for salt marshes and mud
flats in littoral areas. Anaerobic systems provide one possible way
to dispose of the cellular sludge from aerobic oxidation. It has been
proposed to use such a system and then bum the off-gas from it as a
source of valuable fuel. Unfortunately, the reaction rates for this
are so slow that this approach may not always be practical.
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- 43 -
Even though the waste water is cleaned-up and reused in the
process, there will eventually be a limitation due to the increase
in concentration of dissolved solids in the water such as sodium salts.
If the net water effluent contains 2000 ppm of total dissolved solids,
the concentration corresponds to 6% of that for sea water and is
approaching what would be called brackish water. It would not be suitable
for irrigation purposes.
In such cases the waste water may contain too much dissolved
solids to allow discharging it to inland waters or rivers. If so,
it may be necessary to send it to an evaporation pond where the salts
would accumulate. If they cannot be sold or used it would seem logical
to ultimately dispose of them in the ocean.
This specific design has a water make-up requirement of 3626 GPM.
The amount of dissolved solids in it at 500 ppm is 3600 tons per year.
At 100 Ibs. per cubic foot this would correspond to about 2 acre feet
per year for the dissolved solids alone. In addition, there is the
sludge from water treating to remove calcium and hardness components,
but this can probably be disposed of along with the coal ash, or used
as landfill. The tons per day of such sludge may be equal to or several
times that of the dissolved solids; however, it is normally much more
bulky and contains considerable water, therefore, its volume can be
many times that of the salts corresponding to dissolved solids.
6.4 Water Make-Up
When the concentration of dissolved solids in the available
make-up water and the allowable concentration in the effluent water have
been established, the minimum volume of make-up and effluent water can
then be calculated. Both of these are directly proportional to the total
amount of water consumed by chemical reactions or evaporated to the air
in the plant. Water consumed by reactions such as gasification will
generally be quite minor, so the major factor is evaporation of water
in the cooling tower. Therefore, the cooling tower load will determine
the water make-up requirement and the minimum amount of water effluent
from the plant. Load on the cooling tower can be decreased by use of
air fin exchangers which reject heat to the air as sensible heat rather
than by evaporation of water. In addition, improvements in overall
thermal efficiency of the process will decrease the total amount of
heat that must be rejected, and will therefore tend to allow lower
load on the cooling tower. Use of gas turbine drives rather than condensing
steam turbines for compressors and for electric power generation can
also reduce the overall load on the cooling tower.
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- 44 -
7. THERMAL EFFICIENCY
Thermal efficiency for the base design is 64.0%, arrived at
by dividing the heating value of salable products by the heating value
of the coal fed to the liquefaction and utilities sections. Excluding
the sulfur by-product lowers the efficiency to 63.0%. This does not
allow for the coal used as fuel in the coal drying operation, which
further reduces the overall efficiency to 60.3%.
Efficiency can be increased, as summarized in Table 5, by
various adjustments which appear reasonable. More efficient use of heat
in the coal dryer can cut the fuel requirement to about 1/3, giving a
thermal efficiency of 62.1%. Re-examination of the heat effects in the
preheat furnace and reactor further increases thermal efficiency to
64.6%. This allows for the heat released by the hydrogenation reaction
which is equivalent to roughly <400°F temperature rise on the coal alone.
Additional heat release from the water gas shift reaction of the syngas
used in the base design is equivalent to another 150°F on the coal alone.
Of course temperature rise would be less on the total slurry plus gas
stream flowing through the reactor. In addition the coal should be
available at perhaps 200°F from the coal dryer and this heat can be conserved
rather than feeding the coal at ambient temperature.
It is possible that all heat needed for coal drying could be
supplied by waste heat, for example in flue gas from the preheat furnace
or from the utility boiler. If so, a thermal efficiency of 65.5% is
calculated.
A combination of various potential improvements could increase
the thermal efficiency to well over 70%. A major loss in efficiency
results from hydrogen manufacture, since it has a thermal efficiency
of only about 60-65%. At a hydrogen consumption of 3 wt, % on coal,
the Btu contribution by hydrogen is about 15% of the coal heating value.
It would seem that the hydrogen consumption could be reduced below the
3 wt. % used in the base design, without exceeding the sulfur content
required in the product to meet present target sulfur emission for liquid
fuels. The latter is 0.8 Ibs. S02 per MM Btu, which would allow 0.6%
sulfur in the total SRC product. However, future sulfur emission targets
may be lower.
The base design includes some hydro-treating of the liquid
products, corresponding to an average sulfur content of 0.4% on the
total fuel product. Assuming that there are no operability or other
limitations that necessitate hydro-treating, the reaction severity might
be decreased in order to give a lower hydrogen consumption. Presumably,
this would also make less light gas, which contributes to hydrogen
requirement. By way of example, hydrogen consumption might be reduced
from 3% to 2% on coal.
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- 45 -
Table 5
SRC Process
Thermal Efficiency
Base design 64.0%
Excluding sulfur product 63.070
And incl coal fuel to dryer 60.3%
More efficient coal dryer 62.1%
Revised reactor heat load 64.6%
If use waste heat in flue gas for coal drying 65.5%
With Potential Improvements
Omit hydrotreating & distil.
Cut H2 consump. to ca 2%
Over 707.
Make H2 from prod, gas
Use pure H2 to reactor
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- 46 -
An improvement in thermal efficiency will result if the hydrogen
is made from the product gas by conventional steam reforming, instead of
gasifying the char. One advantage is that the gas has a higher hydrogen
to carbon ratio than char, and contains considerable free hydrogen.
If carbon oxides are excluded from the reactor, then the hydrogen partial
pressure will be increased for the same total pressure. Moreover, the
gas is reformed by reaction with steam which also introduces hydrogen,
rather than by reaction of carbon with pure oxygen. This means that
there is less CC>2 removal required for a given hydrogen production. In
addition, there are savings in compression since steam reforming operates
at 400 psig compared to about 200 psig for the gasifier in the base
design. Steam reforming, therefore, needs less compression of the product
hydrogen, since the raw gas is available at higher pressure, moreover, In
the alternative case, oxygen compression is required.
Low Btu syngas from gasifying the char can be used efficiently
as plant fuel instead of converting it to hydrogen. This approach
relaxes the requirements on a very difficult gas clean-up operation, com-
pared to the stringent specifications for hydrogen manufacture.
Potential improvements are discussed in detail in a later
sub-section of this report, and are summarized briefly in this paragraph.
If char gasification is used to supply fuel gas for furnaces and
utilities, then consideration can be given to using air instead of
oxygen for gasification, and thereby eliminate the oxygen plant. This
should be more efficient, and further evaluation appears warranted. In
addition there may be more efficient ways to handle the filter cake.
In the base design it is slurried with an equal weight of SRC product
and then gasified. The amount of oil is 127,000 Ibs per hour, or 33%
on net products, and could contribute additional product from the plant
provided a more efficient way of disposing of the char was used.
One such alternative would be to coke the filter cake in a fluid bed at
perhaps 1000°F to recover oil products overhead and then burn the fine
residual char, or gasify it to make low Btu fuel gas. Another approach
would be to burn the filter cake in a fluid bed furnace with stack gas
clean-up as required.
As pointed out earlier a modification may be desirable on the
handling and reuse of sour water, for example, the stream containing
particulates removed in scrubbing the low Btu gas from gasification.
If this water is not vaporized directly to make steam, then it may be-
come necessary to provide sour water stripping on the entire sour water
stream. This is a very large flow rate and could have a significant
effect on plant thermal efficiency. Heat load for reboiling on the
stripper would reduce thermal efficiency by about 1%, unless it can be
supplied by heat which is otherwise wasted, e.g., to air fin exchangers.
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- 47 -
SULFUR BALANCE
The fuel products from the process are indicated to be at or
below the sulfur content needed to meet environmental regulations.
Nearly all of the remaining sulfur from the coal feed ends up in the
gas streams from which it can be removed by scrubbing. This may involve
a separate reactor to convert compounds such as carbonyl sulfide to H2S
by hydrolysis, or they may be removed by hot carbonate scrubbing.
Sulfur in the gas can then be reduced to a very low level so that all
of the sulfur in the gas goes to the Glaus plant, which with tail gas
clean-up can give over 99% recovery.
There are a few other effluent streams containing sulfur
but these are small. Sour water from the process will be stripped
for odor control and the amount of sulfur discharge will be minor.
Slag from gasification will also contain some sulfur. Since it leaves
the gasifier in a molten condition the sulfur content may be acceptable
but this needs to be checked out, as well as the possibility of secondary
pollution from odor and leaching. These may depend upon the composition
of coal ash, particularly calcium content. Distribution of sulfur in the
products is shown in Table 6.
Glaus tail gas is cleaned-up in the Beavon process by first
reducing the sulfur compounds to H2S, which is then scrubbed out by
the Stretford process. The Stretford solution is regenerated by blowing
with air and careful examination of potential contaminants in the
effluent air is needed. Also the amount and composition of the purge
solutions from the operation need to be defined, including sulfur content.
The coal dryer is not included in the above sulfur balance, on
the basis that clean product gas will be used as fuel. If part of the
dried coal were used to supply all of the fuel for coal drying then the
sulfur emissions would be excessive. Instead, part of the product gas
or the SRC product can be burned to give acceptable sulfur emission.
As an alternative, heat could be supplied by using hot flue gas from
one of the furnaces, or possibly warm air from air-fin exchangers. The
fuel fired for coal drying is about 150 MM Btu per hour so that the
maximum sulfur emission allowable would be 180 Ibs SC>2 per hour.
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- 48 -
Table 6
In Coal Feed
In liquid products
Heavy prod. (0.5% S)
Plant fuel (0.5% S)
Light prod. (0.2% S)
Acid gas to S plant
From liquefaction
From hydrotreating
From gasification
From Sour Water
Sulfur Plant
Product Sulfur
In tail gas
S plant recovery
SRC Process
Sulfur Balance
Ib S/hr
27,987
1,215
50
240
1,505
15,450
1,744
9,053
235
26,482
26,417
65
26,482
26,417 _
26,482
Total emission to environment - from conversion
7
to
100.0
4.3*
.2*
.9*
5.4
55.2
6.2
32.4
0.8
94.6
94.4
0.2
94.6
99.8%
plant only
Plant fuel and tail gas from
sulfur plant
* Ultimately emitted to atmosphere at location where these products
are used as fuel.
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- 49 -
9. TRACE ELEMENTS
The SRC product contains appreciable amounts of certain trace
elements, especially titanium, and in many cases these constituents are
high relative to their content in most heavy petroleum oils. Therefore,
special consideration should be given now to their effects in order to
avoid unexpected problems that could complicate application of the process
in the future. Accompanying Table 7 gives published information on trace
constituents in the SRC product compared to the coal feed. An outstanding
feature is the high titanium content,up to 300 ppm. Although this is not
considered to be one of the more toxic elements, the significance and
impact of this need to be carefully evaluated. The content of beryllium,
cobalt, copper, and lead is also significant and could cause pollution
problems when the product is burned. Further study is needed to define
these potential problems and the control measures if required. Beryllium
is particularly toxic; consequently, it requires special attention in
view of the high reported content of 0.7 ppm.
Some of the trace elements in the product may simply reflect
residual ash; for example, the typical product contains perhaps 0.1%
ash compared to 7% in the coal. Therefore, if the ash in the product
is representative, it could contain 1/70 of the ash components in the
original coal. This applies very roughly in the case of calcium,
magnesium, and silicon. On the other hand, some ash components may
become concentrated in the oil. Thus, the iron pyrite in the coal
will decompose during hydrotreating, where the sulfur is removed as
H.2S while the iron may be converted to a very finely divided or colloidal
form. This could explain why the iron content of the SRC product is
relatively high, or it could result from carbonyl formation, or simply
corrosion of equipment.
Certain elements may be chemically associated with the oil;
in the case of petroleum, it is well-known that vanadium and nickel form
porpyhrin compounds which are surprisingly stable and oil soluble. These
compounds are condensed ring structures with boiling points of 1000°F
or higher, and are so stable that they can be distilled without decomposition.
The SRC product contains significant amounts of vanadium and nickel,
although they are still relatively low compared to many petroleum oils.
The high titanium content of the SRC product is most unusual, and it
would be very interesting to learn more about the form in which it occurs.
It probably would be converted to the oxide during combustion and might
cause fouling or corrosion problems such as are caused by vanadium in
the case of heavy oil fuels.
The potassium content of the SRC product is indicated to be quite
low, amounting to only a few tenths of a percent of the potassium in
the coal. However, the sodium content is quite high and amounts to several
percent of the sodium contained in the coal. Several other elements
appear in the oil rather than being strongly retained in the ash. These
include zinc, iron, copper, manganese and cobalt. It is interesting that
these are all elements which have been established as being essential
to plant life, so it is possible that they are intimately combined
in the carbonaceous molecules of the coal.
-------
Table 7
SRC Process
Analysis of Coal and Product Samples Composition, PPM
(Supplied by Pittsburg & Midway Coal Mining Co.)
Element
Sample *
Aluminum
Antimony
Arsenic
Barium
Beryllium
Bismuth
Boron
Bromine
Cadmium
Calcium
Cobalt
Copper
Chromium
Fluorine
Germanium
Gold
Iron
Lead
Lithium
Magnesium
Manganese
Mercury
Molybdenum
Niobium
Nickel
Potassium
Samarium
S e 1 e n i urn
Atomic Absorption
1000
psig
< 4.
0.7
100.
< .1
180.
2.2
3.7
< 2.
98.
< 2.
< .02
23.
3.
.05
< 50.
2.5
< 2.
Spl. 2
2000
psig
< 4.
0.4
51.
< .1
70.
0.8
2.5
< .2
161.
.4
< .02
9.
1.
.01
< 50.
4.
6.
Spl. 3
Feed
Coal
< 4.
0.9
94.
1.5
3400.
17.
6.
31.
24000.
8.
7.4
550.
39.
.05
< 50.
29.
1300.
Neutron Activation
Spl. 2 Spl. 3
1000 2000 Feed
psig psig Coal
.25 .30 10.6
1.4 .5 19.
.35 .23 6.
1.3 .88 38.
<100. <100. 300.
5. 17. 1790.
-36 .16 1.9
2 • <1 . 7 .
Air Emission
1000
psig
96.
.22
< .4
< .2
15.
3.8
< 1.
100.
< .4
1.1
1.1
< .4
< .4
30.
< .4
20.
2.8
1.7
< 2.
3.6
Spl. 2
2000
psig
130.
.55
< .2
< .1
36.
3.9
< .7
84.
< .2
3.9
1.5
< .2
< .2
160.
< .2
15.
2.7
1.4
< 1.
9.8
Spl. 3
Feed
Coal
12000.
50.
< 10.
< 5.
200.
7.2
< 33.
4800.
< 10.
8.6
78.
< 10.
< 10.
20000.
< 10.
890.
75.
49.
< 44.
120.
Ul
o
Samples are of products from 1000 psig and 2000 psig hydrogenation compared to coal feed.
-------
Atomic Absorption
Neutron Activation
Air Emission
Silicon
Silver
Sodium
Strontium
Tantalum
Tellurium
Thorium
Tin
Titanium
Tungsten
Uranium
Vanadium
Ytterbium
Zinc
Zirconium
1000
psig
< 2.
45.
300.
17.
6.
2000
psig
< 2.
25.
74.
16.
3.
Feed 1000
Coal psig
< 2.
166.
460.
175.
39.
600.
30.
1.4
31.
.39
4.5
2.0
2000 Feed 1000
psig Coal psig
900. 18000.
21. 367.
0.6 5.8
9. 104.
.025 .51
.8 42.
1.1 6.3
.02
10.
< .8
< 2.
< .8
2.9
260.
< 1.
< 4.
17.
5.4
2000
psig
.09
20.
< .5
< .9
< .5
2.0
160.
< .7
< 2.
12.
3.9
Feed
Coal
.8
320.
< 20.
< so:
< 20.
40.
600.
< 30.
< 100.
200.
35.
I
(J1
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- 52 -
From an environmental standpoint much more information is needed
on the trace elements and their fate upon combustion of the SRC product.
Some of these may end up as fumes or fine dust which should be removed
from the? flue gas. In any event, it must be determined whether or not
control measures are needed, and if so, they will have to be defined.
The emission limitations have been specified by EPA for a number of
toxic trace elements, and specifications for other elements are
under consideration.
The discussion so far has dealt briefly with trace elements
in the SRC product, pointing out that more extensive study will be
needed to prevent unusual and unexpected complications. In addition,
there are other aspects of the overall plant to be considered with
regard to emission of trace elements. It is obvious that all trace
elements in the coal feed must leave the plant either in the products,
or in other gas, liquid, or solid effluents. It is not yet possible
to make complete balances due to the early stage of process development.
but all data necessary for accurate and complete balances on toxic
or potentially toxic elements should be obtained in the pilot plant
program.
Many of the effluents from the SRC plant are from conventional
operations, such as process furnaces, utility boilers, waste water
treating, and ash disposal. These are common, or at least similar, to
other coal conversion operations or coal fired boilers, and the pollution
aspects and controls have been discussed in previous reports in this
series (1,2,3,4) or in other references (16,17,22,24).
A key step in the operation is gasification of char, with
disposal of the resulting slag. This introduces questions of what
happens to trace elements during gasification, what further information
is needed to define the problem, and what control measures may be
necessary. The same applies to the slag, including the question of
whether leaching of components in the slag will be excessive when it
is disposed of as landfill or in a mine. A discussion of these questions
is included in the above references together with some of the available
information on this subject and provides a basis for defining the problem,
and for determining what additional information needs to be obtained
during development of the process. For example, it is known that volatilization
is very significant for certain elements such as mercury, selenium,
arsenic, iead, cadmium, antimony, fluorine, bromine, boron, and zinc.
Most of these volatile elements are also toxic.
Although elements are lost, information is needed as to where
they will appear, and in what form (also vapor pressure, water solubility
etc.)- Such results will be needed for critical elements on all gasification
processes used commercially, to define what recovery or separation im)y
be required and to allow designing efft-cLive pollution control and disposal
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- 53 -
facilities. It is possible that part of the volatilized elements will
enter into side reactions in the presence of sulfur, phenols, and ammonia,
ash, etc., and may be soluble in water or oil, but this will not be known
until further information is available.
In some process designs for coal conversion operations, certain
streams are disposed of by recycling to extinction through a reaction zone.
For the SRC design, this is the case on the sour water from the liquefaction
reactor and from gasification. It will be apparent that if certain trace
elements are collected by this recycle stream, then they will tend to
build-up due to recycling since they may not be able to escape. This
could apply for example to volatile compounds of arsenic, lead, boron,
and fluorine. More information is needed to define the problem, but
some provision for separating and disposing of trace elements may have
to be added.
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- 54 -
10. PROCESS ALTERNATIVES
In examing the process to evaluate environmental impacts and
thermal efficiency a number of alternatives were considered, some of which
appear to have potential for improving these aspects of the process without
involving unproven technology or requiring major new developments. Some of
these are presented in this section for consideration and listed in Table 8.
The first item to consider in this category is the coal
dryer. Excessive sulfur emission would result when using the coal
fuel indicated in the base design. By substituting clean product
gas as fuel this problem is overcome. It is sCill necessary to clean
up the flue gas leaving the dryer system to remove particulates but
this can be done using bag filters. Also the amount of fuel consumed
in coal drying can be considerably reduced by reducing the amount of
excess air. While this will increase the moisture content of flue gas
and also the residual moisture in the dry coal, it should not be serious
since water is required in the liquefaction reactor. The important con-
sideration appears to be the ability to handle the dried coal as a powder
and this should not be significantly affected.
As mentioned earlier, revising and optimizing the heat balance
around the reactor and preheat furnace could increase the thermal efficiency
by about 2.57o. Full advantage should be taken of the sensible heat in the
coal leaving the dryer, at 200°F or higher. Also, the exothermic heat of
reaction makes a considerable contribution. In the base design, a naphtha
quench stream is injected at the furnace outlet and ahead of the liquefaction
reactor in order to drop the temperature from 900'" to 840°F. The purpose of
this quench stream is not described, but if it is for controlling reactor
temperature it may be that instead of using a quench, the excess heat could
be recovered by indirect heat transfer to generate high pressure steam. For
example, recycle slurry oil from the reactor could be passed through waste
heat boilers, using a technique similar to that employed on catalytic cracking
units in petroleum refineries. The amount of heat involved is about 150 MM
Btu's per hour, corresponding to about 1.4% on thermal efficiency.
There are a number of other places in the base design where
heat recovery might be improved. As one example, the product liquid
is cooled in air-fin exchangers to 1CO°F, then it is reheated to be
taken overhead in a flash zone, from which it is cooled, condensed,
and then reheated and fed to fractionation. If feasible from a process
standpoint, it would be more efficient to feed the product liquid directly
to the fractionator.
In a number of cases, air-fin exchangers are used to reject
heat that might otherwise be transferred to another stream for recovery.
For example, the overhead condenser on the separator after the reactor
removes 167 MM Btus per hour at a temperature level of 370°F to 130°F.
Possibly some of this heat could be used effectively in acid gas removal,
sour water stripping, or for boiler feed water preheat.
-------
- 55 -
Table 8
SRC Process
Process Alternatives
1. Dryer on Coal
coal fuel gives excessive sulfur emission, therefore change to gas fuel
or use product liquid.
high fuel consumption; design with low excess air can cut fuel consumption
in half.
2. Liquefaction Reactor
- optimize reactor heat balance and conserve preheat in coal from dryer,
to make large saving in fuel to preheat furnace.
3. Product Handling
more efficient heat recovery. Avoid cooling and reheat steps on product
liquid.
transfer to process streams part of the heat now rejected to air at 370-
130 F by airfin coolers, or use warm air for coal dryer or furnaces.
4. Gasification
use incinerator to burn filter cake directly and recover fuel value rather
than using gasifier, which consumes product liquid (to make slurry of cake)
equal to 1/3 of net clean product liquids. Use stack gas cleanup on incinerator.
5. General Efficiency Items
less excess air on furnaces, use heat pumps, pressure recovery, etc. as outlined.
6. Improve Thermal Efficiency to 70%
burn filter cake instead of gasifying it.
make hydrogen from product gas by steam reforming
optimize reactor heat balance
cut hydrogen consumption, omit product hydrotreating
7. Minimize Volume of Waste Water
cleanup and reuse blowdown from cooling tower
cleanup and reuse water from draining slag slurry
-------
- 56 -
A major loss in efficiency is associated with gasifing the
char, in that one-fourth of the potential liquid product is mixed with
the filter cake to form a slurry so that it can be handled. The slurry
contains equal weights of oil and cake, the oil amounting to 1,530 tons
per day. The weight of char excluding ash is only 818 tons per day,
so that there may be a better way to recover the fuel value from the
filter cake. The best disposition would seem to be as fuel rather
than for hydrogen manufacture, since the required hydrogen can be supplied
easily from the product gas by conventional steam reforming. A practical
and efficient system for burning the filter cake is needed, together
with adequate pollution controls.
One possibility is to burn it in one of the fluid bed incinerators
being offered for commercial use, together with a system to control
emission of sulfur and particulates. In effect, pollution would be controlled
on the flue gas, rather than by cleaning up the solid fuel. It will
be apparent that stack gas clean-up has the advantage of controlling
both particulates and sulfur emission at the same time. In addition it
inherently has a higher thermal efficiency by permitting direct combustion
of high sulfur solid fuel, without first processing it for example by
gasification which may have a thermal efficiency of 65-70%. A number
of processes are offered commercially for stack gas clean-up. Some
of these use throw away limestone, while others use a regenerable
salt to make a by-product from the recovered sulfur.(32)
Ways to reduce the overall energy consumption for the process
are of a special interest in view of the present high cost of energy
and fuel, which also has shifted the optimum design parameters. As one
example, the use of heat pumps now becomes more attractive. These can
best be applied when large amounts of heat are added and removed at
slightly different temperatures. Such a situation exists on the amine
regenerator, where the overhead condensor operates at perhaps 30 degrees
higher temperature than the reboiler on the bottom. It is, therefore,
possible to use a heat pump to compress the overhead vapors in order
to raise the condensing temperature so that the heat of condensation
can be used to provide the heat for reboiling. A second possible
application of the heat pump is on the sour water stripper where a
large amount of heat is required for reboiling and then must be removed
in the overhead condenser at somewhat lower temperature. The economics
of such heat pump applications is quite sensitive to the temperature
difference between the reboiler and the overhead condensor, as well
as to the cost of fuel. Therefore, potential applications have to be
evaluated and optimized for each particular case. Since the technology
involved is strictly conventional and straight forward, the necessary
engineering evaluation can be made without the need for additional
data.
-------
- 57 -
To summarize, a substantial improvement in overall process
efficiency should be possible by a combination of relatively straight
forward modifications and changes, as follows:
(1) Burn the filter cake directly rather than
gasify it.
(2) Make hydrogen by steam reforming of product gas.
(3) Optimize heat balance and heat recovery around the
liquefaction reactor.
(4) Minimize hydrogen consumption in the reaction and
omit hydrotreating to upgrade the products beyond
boiler fuel requirement.
(5) Optimize heat and energy recovery,heat pumps, and
general efficiency items.
In addition, these modifications will greatly reduce the formation
of compounds such as carbonyl sulfide, and thereby simplify the acid
gas removal system so that conventional amine scrubbing should be
adequate.
One modification of the base design that merits special
mention is reducing the amount of waste water effluent. This is a
contaminated stream which will be difficult to clean-up and it is,
therefore, desirable to minimize it. It appears that when this
water has been cleaned up sufficiently to meet waste water effluent
requirements, then it should also be suitable for reuse as make-up
water. By using this approach in the present design, the waste water
rate can cut considerably, perhaps in half, without exceeding reasonable
levels of dissolved rolids in the circulating water.
-------
- 58 -
11. GENERAL EFFICIENCY ITEMS
Ways to reduce the overall energy consumption of a process
are of special interest in view of the present high cost of energy
and fuel. This process is a representative one to examine for efficiency
improvement, in that is includes a wide range of operations including
furnaces, heat exchangers, compressors, pumps, utilities, etc. In
today's environment,a thorough examination is warranted to reoptimize
conventional operations, and reduce overall energy requirements. In
the course of this study, a number of such items have been considered
which should have general application. These are listed below for
cons ideration.
(1) Decrease excess air on. furnaces. In many cases
it has been practical to operate with as little
as 5 percent excess air, generally with automatic
control instrumentation.
(2) More extensive use of finned exchanger tubes in the
convection section of furnaces, particularly
those with gas fuel.
(3) Consider air preheating, especially on large
furnaces.
(4) Use expanders to recover energy when gas must be
depressured. This technique is well developed
on air liquifaction plants. Similarly, energy can be
recovered from high pressure liquids by using turbines--
this can be used to advantage in acid gas removal systems,
where a large volume of liquid is circulated between
high and low pressure zones.
(5) It is generally desirable to supply low pressure steam,
e.g. for reboilers, by first generating the steam at
very high pressure and then depressuring it through a
bleeder turbine to provide power for generating
electricity, or for some other use. The incentive
for higher pressure steam generation has increased
considerably.
(6) In selecting turbines, more emphasis should be
placed on turbine efficiency. For sizing pumps,
excessive oversizing should be avoided as it leads to
lower efficiency in normal operation.
(7) When a Glaus plant is used for sulfur recovery it is
advantageous to maintain a high concentration of
l^S in the feed in order to minimize the total gas
volume to be handled. Keeping hydrocarbons and
ammonia out of the feed gas will also help.
-------
- 59 -
(8) To minimize fuel consumption, the temperature of
the incinerator on the Glaus plant tail gas should be
no higher than necessary. In some cases a temperature
as low as 1000°F has been used.
(9) The total circulation of cooling water can sometimes
be decreased by reuse of the water. For example
cooling water may leave the condenser on a turbine drive
at 105°F, and by reusing this elsewhere it can be
heated to say 120°F before going to the cooling tower,
thereby decreasing the load on cooling tower fans
and pumps.
(10) The use of hnat pumps should be evaluated wherever
there is a reasonably low temperature difference
between the heating and cooling loads. This may
apply to the regenerator of amine scrubbers used
for acid gas removal, and on sour water strippers.
-------
- 60 -
12. POTENTIAL IMPROVEMENTS
This section of the report discusses potential improvements
that may require additional information and experimental work, in order
to evaluate them fully. They are presented here and in Table 9 for
consideration, and in some cases, have been mentioned in earlier sections
of the report.
One of the largest heat requirements in the process is on the
liquefaction reactor. A large preheat furnace is used and it may have
a fouling and erosion problem due to handling a mixture of
slurry containing heavy oil, together with recycle gas. It may be
possible to reduce the heat load significantly. As one step, the coal
feed might be preheated to about 500°F without excessive decomposition
in a fluidized solids system at low pressure, and then lock hoppers
would be used to introduce the coal to the high pressure system. As
pointed out earlier, the heat of reaction in liquefaction corresponds
to a temperature rise of about 400°F on the coal alone, which would then be
sufficient to bring the coal to reaction temperature. The make-up
hydrogen and recycle gas can be heated to reactor temperature or higher
so that these do not contribute to the heat load. Then the only other
large requirement is to reheat the recycle oil used to form the slurry.
It may be possible to reduce the amount of this recycle oil since it
is no longer necessary to form a slurry of the coal feed in order to
transport it and pump it to high pressure. Instead the coal would be
introduced into the reactor as a suspension in gas. If staging is not
important in the reactor, it could be operated as a perfectly mixed
reactor so that a high rate of oil recycle for temperature control is
accomplished simply by the turbulent mixing within the reactor. On
the other hand, if staging is desired,, then reactor product slurry could
be recycled to the inlet at a controlled rate. Rather than using
mechanical pumps for this service which would present operating problems
on the hot slurry, it is suggested that a gas lift system be used
wherein pumping energy is supplied by gas bubbles rising through a
vertical column of liquid, as is commonly used for handling corrosive
liquids. Start-up of the reactor would be handled by adding oil to
it, and then recirculating gas through the furnace to bring the reactor
up to temperature.
In looking at the utility balance,it is seen that clean product
gas is used as fuel in various furnaces, as well as for steam and power
generations. It would be more efficient to first burn at least part
of this fuel gas at high pressure, for use in flue gas turbines generating
electricity. This equipment might be similar to that used by public
utilities for stand-by power generation. The hot gases leaving the
turbine-generator would then go to the furnace used for preheating.
Most of the furnace heat loads in this design are at temperature levels
of 900-1000°F or less and, therefore, this approach would appear to be
feasible. As a further efficiency improvement item it is desirable to
generate steam at high pressure wherever possible and then to use it in
-------
- 61 -
Table 9
SRC Report
Potential Improvements
1. Changes to reduce heat load on reactor preheat furnace:
preheat coal to ca 500CF, feed directly to reactor via lockhoppers
rather than as a slurry in oil.
- preheat reactor gas to ca 1000°F and feed as a separate stream to
reactor
recycle oil as required to reactor with little or no cooling, using
"gas lift" for pumping.
2. Use low Btu gas from gasifying filter cake as plant fuel, instead of as
a source of hydrogen. Make required high purity hydrogen by conventional
steam reforming of product gas, thereby eliminating oxygen plant and de-
creasing the amount of C02 that must be rejected by acid gas removal.
3. Burn filter cake directly to recover fuel value, and avoid consuming
potential clean liquid product needed to make a slurry that can be handled.
4. Use hydrolysis step on acid gas removal system in gasifier section, to
convert COS and other sulfur compounds to H2S so that essentially all
sulfur can be removed by amine scrubbing, rather than depending on scrubbing
with sodium hydroxide for cleanup.
5. Where fuel gas is burned in furnaces, consider combined-cycle system
where the gas is used first in a gas turbine, and then goes to the
furnace. By-product power could supply all electricity needed for process.
6. Explore potential for energy savings:
expanders to recover energy from gases upon depressuring
turbines to recover energy on depressuring liquids, especially in
acid gas removal
heat pumps between overhead condenser and reboilers, especially on sour
water stripper and acid gas removal
make use of air preheat from airfin coolers, for coal drying or to
preheat combustion air on furnaces
-------
- 62 -
bleeder turbines to supply lower pressure steam requirements, such
as for reboiling in the acid gas removal system. Thus, steam might
be generated at 600 to 1000 psig and depressured through bleeder
turbines to supply 50 to 165 psig steam. A detailed utilities balance
is justified in order to optimize this system.
One possibility for energy saving is to send the warm air
discharged from air-fin exchangers to a furnace, where the advantage
of preheated air would be obtained. An air preheat of 100-200°F might
result, increasing furnace efficiency by 3-5%. A second possibility
is to use the warm air for coal drying. It is interesting that the
amount of heat from just one service, the air-fin condenser on the reactor
outlet^ is enough to provide all the heat required for coal drying.
Other ways to improve energy recovery also deserve thorough
consideration. Pressure recovery will be particularly important on
high pressure processes such as this. Gas streams from flash separators
and the like can be depressured through expanders in order to recover
energy. These could drive other equipment or be used to generate
electricity. Similarly, when liquid streams are depressured they can
be passed through turbines to recover energy* for example, on the amine
scrubbers after gasification, 9000 gpm of liquid is recirculated between
the absorber at 180 psig and the regenerator at 18 psig. Theoretical
pumping work is 900 HP, much of which might be recovered.
One change that would increase energy requirement is on the
handling of sour water containing participates. In the base design
this is evaporated by indirect heat exchange. If it should be
necessary to clean-up this water stream before evaporating, then it would
involve a large sour water stripper and the heat requirement for this could
decrease thermal efficiency by about 1%. Steam is commonly used for re-
boilers in such service, but it should be kept in mind that a direct fired
reboiler may be simpler and more efficient. The possible use of a heat pump
on the sour water stripper has already been mentioned.
The fate of carbonyl sulfide, and sulfur compounds other r.han
H2S, in the gas needs to be clarified. This applies to both the liquefaction
reactor and the gasifier. Compounds such as carbonyl sulfide are not
removed effectively by the amine scrubbing used for acid gas removal.
In the case of liquefaction, perhaps they will be recycled through the
reactor and be converted to H2S by hydrolysis. It may be preferrable
to include a separate reactor to carry out this hydrolysis, using
techniques described in the literature (18).
The gasification reaction also produces carbonyl sulfide,
as well as other sulfur compounds. The raw gas is first scrubbed with
amine but some of these sulfur compounds will not be removed- Caustic
is not a good way to remove them because of the problem of spent
caustic disposal or regeneration. Part of the scrubbed gas is used
-------
- 63 -
to make pure hydrogen for hydrotreating and this part is further
scrubbed with hot carbonate using the Benfield process. This will
remove a large part of the carbonyl sulfide, but in the specific design
case, the CQ? stream which is purged to the atmosphere has a sulfur content
that is excessive, and would need to be cleaned up, for example by molecular
sieves or by scrubbing with limestone. A preferred route would be to use an
effective hydrolysis reactor ahead of an amine scrubber, so as to convert
all forms of sulfur in the raw gas to H2S which can then be removed to any
desired level. This would reduce to a nominal level the load on the caustic
wash system used to remove sulfur compounds ahead of the shift reactor.
As it stands, a large consumption of caustic would be needed to give the re-
quired sulfur removal. Not only is this costly, but it also poses a difficult
problem of disposing of spent caustic.
A promising alternative is to use the low Btu gas from gasi-
fication as process fuel rather than as raw material for hydrogen
manufacture. One advantage is that it then does not have to be
cleaned-up as thoroughly from the standpoint of sulfur and participates.
For example, carbonyl sulfide may be less of a problem. Moreover,
consideration can then be given to using air for gasification rather
than pure oxygen, as may be more advantageous if the low Btu gas is
used in a combined cycle type of system. This type of gasifier is
well known, and several processes are being developed for commercial
use.
There is considerable incentive to burn the filter cake
directly, rather than to slurry it with a large amount of valuable
product liquid and gasify the mixture. It should be possible to burn
it in conventional incinerators, but there may be a question of opera-
bility on a fluid bed burner system in that the filter cake may agglomerate
and form large chunks, rather than disintergrate into small particles
when it hits the high temperature bed. If this is a problem, then it
should be possible to burn the filter cake in a mechanically agitated
furnace or in a rotary kiln. These techniques may not be as simple or
efficient as a fluid bed boiler, but the important point is to avoid
having to consume a large part of the product liquid in order to
dispose of the residual char. Of equal importance is the fact that
if the filter cake is burned, then there is no longer a need for the
special gasification operation, which entails considerable new development
and detracts from the basic efficiency of the process. Gasification
adds an oxygen plant and extensive raw gas clean-up, both of which
are high consumers of utilities.
-------
- 64 -
13. PROCESS DETAILS
Other details on the process including utility requirements for
fuel, power, water, and steam are shown in Tables 10-14.
-------
- 65 -
Table 10
SRC Process
Fuel Balance
Low Sulfur Fuel Needed
Description MM Btu/hr
Coal Preparation (1)(3) 115
Coal Slurrying and Pumping
Coal Liquefaction and Filtration 1039.5
Dissolver Acid Gas Removal
Coal Liquefaction Product Distillation 92.3
Fuel Oil Hydrogenation 57.0
Naphtha Hydrogenation 11.6
Fuel Gas Sulfur Removal
Gasification 41.1
Acid Gas Removal
Shift Conversion 96.3
C02 Removal
Methanation
Sulfur Plant 78.3
Oxygen Plant
Instrument and Plant Air
Raw Water Treatment
Process Waste Water Treatment
Power Generation 926.0
Product Storage
Slag Removal System
Steam Generation (2)(3) 443
Low Sulfur Fuel Consumed 2900.1
Total Fuel Gas Produced -2735.6
Additional Fuel Required
(SRC Heavy Liquid Product) 164.5
NOTES:
(1) Plus 2700 Ib/hr of dried coal, equiv. to 35 MM Btu/hr.
(2) Plus 9000 Ib/hr of dried coal, equiv. to 115 MM Btu/hr.
(3) Average sulfur emission is 1.2 Ib S02 MM Btu of gas plus coal fired
by way of example, but specific regulations may call for lower
levels.
-------
- 66 -
Table 11
SRC Process
Power Consumption
Description
Coal Preparation
Coal Slurrying and Pumping
Coal Liquefaction and
Filtration
Uissolver Acid Gas Removal
Coal Liquefaction Product
Distillation
Fuel Oil Hydrogenation
Naphtha Hydrogenation
Fuel Gas Sulfur Removal
Gasification
Acid Gas Removal
Shift Conversion
C02 Removal
Methanation
Sulfur Plant
Oxygen Plant
Instrument and Plant Air
Raw Water Treatment
Process Waste Water
Treatment
Power Generation
Product Storage
Slag Removal System
Steam Generation
Operating Horsepower
Pumps
350
10,261
630
105
1,179
76
493
107
380
142
32
--
1,504
--
--
6,845
160
524
--
--
Compressors
--
580
--
--
8,000
620
--
40
_-
3,520
--
--
--
24,444
800
__
--
__
--
--
--
Other
6,000
62
920
--
240
230
50
--
--
--
--
180
15
1,416
--
--
1,251
60
--
--
--
--
Total
6,000
412
11,761
630
345
9,409
746
493
147
380
3,662
212
15
2,920
24,444
800
8,097
220
524
--
~~
Total Horsepower 78,417
Equivalent electric power KW 58,500
Electrical Power for Lighting of Process and Outside Areas, Buildings and Warehouses - 5590 kW
-------
- 67 -
Table 12
SRC Process
Cooling Water Required
Description
Cooling Water
Circulated (gpm)
Coal Preparation
Coal Slurrying and Pumping
Coal Liquefaction and Filtration
Dissolver Acid Gas Removal
Coal Liquefaction Product Distillation
Fuel Oil Hydrogenation
Naphtha Hydrogenation
Fuel Gas Sulfur Removal
Gasification
Acid Gas Removal
Shift Conversion
C02 Removal
Methanation
Sulfur Plant
Oxygen Plant
Instrument and Plant Air
Raw Water Treatment
Process Waste Water Treatment
Power Generation
Product Storage
Slag Removal System
Steam Generation
Total
Raw Water Makeup
2,
1
,000
,760
32,676
37,500
410
2,259
45
3,100
6,209
17,220
422
80
17,400
90
121,171
2,666
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- 68 -
Table 13
SRC Process
Treated and Waste Water Balances
Use
Quantity
(Ib/hr)
Treated Water
Process Water (net)
Boiler Feed Water Makeup
Potable Water
Cooling Tower Makeup
Total
Waste Water
Boiler Feed Water Slowdown
Cooling Tower Blowdown
Cooling Tower Evaporation and Drift
Sour Water to Bio Pond
Water to Sanitary Sewer
Total
Actual Waste Water Discharge
121,183
213,738
149,909
1,528,378
1,813,208
(3,626 gpm)
61,123
301,555
1,026,823
19,606
149,909
1,559,016
532,193
(1,064 gpm)
-------
Table 14
SRC Process
Steam Balance, Ib/hr
Description
600 psig
150 psig
60 psig
15-25
psig
STEAM PRODUCED
Coal Liquefaction and Filtration
Coal Liquefaction Product Distillation
Gasification
Sulfur Plant
Raw Water Treatment (Deaerator)
Power Generation (Waste Heat Boiler)
Steam Generation
From 600 psig Steam
From 150 psig Steam
From Steam Turbines on Process Users
Total
124,840
388,579
472,960
242,331
1,228,710
37,500
37,500
155,230
70,000
138,710
4,490
790,410
1,158,840
2,570
5,250
8,570
19,400
35,790
STEAM CONSUMED
Coal Liquefaction and Filtration
Dissolver Acid Gas Removal
Coal Liquefaction Product Distillation
Fuel Oil Hydrogenation
Fuel Gas Sulfur Removal
Gasification
Acid Gas Removal
C02
Sulfur Plant
Oxygen Plant
Raw Water Treatment
Process Waste Water Treatment
Reduction to 60 psig
Steam Turbines on Process Users
Product Storage Area
Building Heating
Total
443,000
207,000
22,400
77,600
52,900
72,400
12,700
202,000
138,710
1,228,710
4,490
28,010
5,000
37,500
705,600
9,980
60,060
332,800
14,000
26,400
10,000
1,158,840
35,790
35,790
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- 70 -
14. TECHNOLOGY NEEDS
An important objective of this study is to point out areas
where additional information is needed in order to define environmental
problems and means for their control. Some of these have already been
touched on in earlier sections of this report, while items common to
other coal conversion operations such as coal preparation, drying, and
gasification are discussed in previous reports in this series. A number
of pertinent items are discussed below and summarized in Table 15.
(1) Further work is warranted on the coal cleaning
operation to be sure that the very large amount
of fine refuse from the tailing pond can be dis-
posed of without secondary pollution problems
due to leaching, dust, toxicity, etc.
(2) The basic coal gasification process has not yet
been proven out for commercial use, and involves
many research and development needs, as pointed
out in other references for similar types of
gasification operations. (1, 2, 3, 4)
(3) Information is needed on the fate of trace elements
during liquefaction and gasification. Some data have
been reported on trace elements in the SRC product,
but information is also needed on compounds in the
gas such as hydrogen fluoride, hydrogen chloride,
in the water such as soluble forms of toxic metals,
and in the ash. Trace materials in the coal such as
selenium, lead, and arsenic etc. will probably vaporize and
be removed in the gas clean-up section. The reducing
atmosphere in the gasifier might release zinc metal,
which has a boiling point of 1665''F. Ultimate disposal
from the clean-up system will need to be worked out as
more is learned about where these materials show up
and in what form. Both the entrained char and the sour
water are completely recycled to the gasifier, so
trace elements may build up in these recycle streams
and provide a convenient place to separate them.
Since hydrogen and carbon monoxide are present in the
liquefaction and gasification system at high temperature
and pressure, it is possible that compounds such as
arsine and carbonyls may be formed.
Available analyses on the SRC product show an unusually
high level of titanium. While this is not now considered
to be one of the highly toxic elements, it is most impor-
tant to consider what the impact may be on subsequent
handling and use of the SRC product.
-------
- 71 -
Table 15
SRC Process
Te_chnolpgY. Needs
1. Coal preparation: an environmentally satisfactory way to dispose of
large amounts of fine refuse from tailing pond on coal cleaning operations.
2. Coal dryer: a system to maximize fuel efficiency (and minimize vent gas
volume), with simple, effective control over pollution from sulfur, dust, etc.
3. Development of 2-stage gasifier:
1700 F zone: amount of tar, soot, trace elements, COS etc. in raw
gas and effect on gas cleanup and acid gas removal.
3000 F zone: slag quenching, particle size control, and slag removal
and disposal.
4. Use of SRC product as clean fuel:
effect of high content of trace elements, especially titanium and
beryllium.
effect of high nitrogen content on NO production.
5. Sour water cleanup from liquefaction and gasification:
practical technique to reuse sour water, for example by vaporizing
it in exchanger or furnace to make process steam. Potential problems
to be overcome are: fouling due to small amounts of oil, tar, solids,
etc.; corrosion froml^S, COo, etc.; erosion due to solid particles.
waste water cleanup to remove phenols and other oxygenated compounds,
nitrogen and sulfur compounds, so that it can be returned as makeup water
demonstrate that biox system is practical on actual waste water compo-
sition, and that it is dependable for a commercial plant subject to
upsets and startups.
6. Acid gas removal:
methods to hydrolyze COS etc. to l^S so that they can be removed
completely by amine scrubbing or by other techniques
a way to handle cyanides and thiocyanates so that they do not interfere
with acid gas removal, or necessitate purging chemicals from the operation
a system that will provide a high concentration of ^S (eg 25-500/,)
to the Glaus sulfur plant, if one is used, so as to improve sulfur
recovery and decrease the amount of tail gas.
-------
- 72 -
Table 15 (continued)
7. Trace elements - where they appear, in what form, and suitable control
measures:
on burning the liquid product
in the gasifier raw gas
in slag from the gasifier
in sour water from liquefaction and gasification
in refuse from coal cleaning
-------
- 73 -
(4) When the SRC product is burned as fuel, trace
elements in it will be released and may form
vapors or fumes. Although the release of total
particulates may be within the required 0.1 Ibs.
per MM Btu, there could be excessive release of
certain trace elements such as beryllium, cobalt,
or arsenic. This potential problem needs to be
defined, together with clean-up and disposal
methods if required.
The product is quite high in nitrogen content which
can be expected to cause a considerable increase
in production of nitrogen oxides during combustion.
Since this effect cannot be predicted accurately,
it should be measured in combustion tests.
It is apparent that actual combustion tests are
needed on the product to determine what the
environmental problems are, if any, so that control
measures can be worked out as needed.
This is a new product and it should be examined
carefully from the standpoint of handling and use.
Due to its high content of oxygen and nitrogen,
it may have a strong odor which could call for
special control measures. In addition, it is known
that coal tars are carcinogenic, consequently the products
should be carefully evaluated from this standpoint.
(5) It will be very important to define an effective
clean-up system for the sour water so that it can
be reused to minimize Che amount of make-up water
required. This water may contain particulates in
addition to ammonia, hydrogen sulfide, phenols, cyanides,
and traces of oil and tar. The proposed reuse of
this water to generate steam for the process is a
very desirable objective to demonstrate. If this
entire stream had to pass through sour water stripping
and water treating, then it would increase the fuel
requirement. Vaporizing the sour water to make
process steam could have an adverse effect on plant
service factor, and the resulting impact on the
environment should be considered since emissions
during start-up and upsets are often much worse
than for normal operation. It would appear that
developing ways to make useful steam directly from
sour water represents a very important technological
need.
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A biox unit is used for final clean-up of the
waste water, which may contain compounds that
are quite resistant to biological destruction,
such as cyanides, thiocyanates, phenols, and
ammonia, as well as small amounts of oil or tar.
There may also be some trace elements in soluble
form that could affect biological activity, for
example, copper is known to be a poison at concentra-
tions of only a fraction of a ppm. Therefore,
experimental work is needed on an actual water sample
in order to be sure that the operation will be
adequate, and should be included in the pilot plant
program.
(6) Gasification of char has research and development needs
similar to those for other coal gasification processes,
as discussed extensively in previous reports of this
series (1,2,3,4). The proposed gasifier is a
modification in that it operates at 200 psig with
two stages - an upper one at 1700°F and a lower
slagging stage at 3000°F. Some 30% of the slurry
to be gasified is introduced near the top of the
1700^ zone, and it may be that some tar
and possibly soot will be formed and appear in the
raw gas; at least during startup, or upsets. In-
formation is needed on this since if it occurs the
raw gas clean-up and sour water processing will be
more complicated than shown. The raw gas passes
through a dry cyclone to collect char, which is then
recycled to the gasifier since it is not converted
completely in one pass. If a higher char conversion
could be maintained in the gasifier, as for some
other gasifiers, then this recycle stream would be
decreased, and efficiency would improve by re-
ducing the heat load on the gasifier.
Molten slag from the gasifier drops into water to
shatter it into particles that will form a pumpable
slurry. The particle size from this operation needs
to be established, so that the exact nature of the
slag can be defined, and its disposal or use evaluated.
The slurry is sent to a drainage pile and information
is needed on the contaminants in this water, both
as regards participates and soluble materials that
are picked up from the slag.
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(7) Filtration to separate ash from the product liquid
is an essential part of the process which needs to
be well defined. Overall efficiency would improve
if it were not necessary to add product liquid to
the filter cake in order to form a slurry that
can be handled. One alternative is to burn the
filter cake directly in a fluid bed combustor or a
mechanically stirred kiln. A second possibility is
to feed the filter cake to a fluidized coking reactor,
on the basis that the oil content would be distilled
out for recovery, and the cake would break-up into
small particles. These char particles might then
be gasified or burned by various conventional techniques
with suitable gas clean-up. Research in this area
of char disposal could result in a considerable
increase in thermal efficiency for the process, and
at the same time simplify the development by avoiding
the need to demonstrate a novel gasification system
with its complicated and difficult gas clean-up
system.
If the char is directly burned as fuel instead of being
gasified, then information is needed on the combustion
operation and clean-up of the flue gas resulting from
it. There will be particulates and sulfur present and
probably also trace elements, but all of these can probably
be controlled adequately by suitable scrubbing.
(8) The process uses acid gas removal on the gas from
liquefaction, on the raw gas from gasification, and in
hydrogen manufacture. While removal of hydrogen sulfide
is conventional and straight forward, there will be
other sulfur compounds and materials in these gas streams
which will complicate the acid gas removal, including COS,
cyanides and thiocyanates. If some of these combine
with amines and are not regenerated by the normal
procedures, a purge stream will be needed. The presence
of phenols may also affect the operation. Data are needed
in this area as to the amount of purge, its composition,
and its disposition.
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A further item for research in this general area of
acid gas removal is to develop a simple and efficient
process for removing all forms of sulfur selectively,
while giving a concentrated feed to the sulfur plant,
for example 50% or more l-^S. This would minimize the
total amount of gas to be handled in the sulfur plant,
improve sulfur recovery, and thermal efficiency.
(9) There is potential for an appreciable improvement in
thermal efficiency by a modified operation of the lique-
faction reactor and preheat furnace. The coal feed is
mixed with recycled oil in order to form a pumpable
slurry, introducing certain limitations. The amount
of oil recycled is set at twice the weight of coal
in order to form a slurry that c;in be handled and pumped.
This may be considerably more oil than is needed to
form a satisfactory slurry in tiie reactor itself. All
of this recycle oil is cooled from furnace outlet
temperature of 900°F, down to 550°F entering the slurry
mixing tank. Moreover, the stream is depressured from
1000 psig down to essentially atmospheric pressure.
Although the heat can be recovered and used, the overall
operation is inefficient and requires considerable
pumping.
A further limitation of this system is that the
coal feed cannot be preheated because the slurry
mix temperature would be too high. An alternative
approach is to feed the coal directly into the
reactor rather than pumping a slurry. This would
involve a certain amount of development, since the
present commercial lock hopper operations are at
perhaps 500 psig and low temperature, but with this
system it should be possible to preheat the coal
to about 500 F without having volatiles given off.
The proposed modification should result in a much
smaller reactor preheat furnace, since it has been
estimated that heat given off by the hydrogenation
reaction is equivalent to about 400 F temperature
rise on the coal alone.
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15. QUALIFICATIONS
As pointed out, this study does not consider cost or economics.
Also, areas such as coal mining and general offsites are excluded. These
will be similar and common to all conversion operations.
The study is based on a specific process design and coal type,
with modifications as discussed. Plant location is an important item of
the basis and is not always specified in detail. It will affect items
such as the air and water conditions available, and the type of pollution
control needed. For example, this study is based on high sulfur eastern
coal, although it can be used on low sulfur western coal. Because of
variations in such basis items, great caution is needed in making compar-
isons between coal conversion processes since they are not on a completely
comparable basis.
Some other conversion processes are intended to make SNG or
low-Btu gas fuel, and may make appreciable amounts of by-products, such
as tar, naphtha, phenols, and ammonia. Such variability further increases
the difficulty of making meaningful comparisons between processes.
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16. SRC REPORT REFERENCES
1. Koppers-Totzek report January 1974, EPA 650/2-74-009 a, (PB-231-675/AS,
NTIS, Springfield, Va. 22151).
2. Synthane report June, 1974, EPA 650/2-74-009b, (PB-237-113/AS, NTIS,
Springfield, Va. 22151).
3. Lurgi report July 1974, EPA 650/2-74-009 c (PB-237-694/AS, NTIS, Springfield,
Va. 22151).
4. C02 Acceptor Report, December 1974, EPA 650/2-74-009 d.
5. COED Process Report, February 1975, EPA 650/2-75-009e.
6^ Economic Evaluation and Process Design of a Coal-Oil-Gas (COG)
Refinery. Marshall E. Frank and Bruce K. Schmid. AICHE Annual
mtg NY city. November 26-30, 1972.
1^ Production of Ashless; Low-sulfur Boiler Fuel from Coal.
B. K. Schmid and W. C. Bull. ACS Div. of Fuel Chemistry.
September 1971.
g^ Pilot Plant for De-ashed Coal Production. V. L. Brant and
B. K. Schmid. Chem. Eng. Progress. Vol 65. No. 12. December 1969.
9^ Development of a Process for Producing an Ashless, Low-Sulfur Fuel
from Coal. R&D Report No. 53. Interim Report No. 4. Vol. 1 -
Part 2 - Phase 1 for OCR.
•J^Q^ Economic Evaluation of a Process to Produce Ashless, Low-Sulfur
Fuel from Coal. R&D Report No. 53, Interim Report No. 1. Contract
No. 14-01-001-496 for Office of Coal Research.
11. Demonstration Plant. Clean Boiler Fuels from Coal. R&D Report No. 82.
Interim Report No. 1. Volume I and Vol. II for Office Coal Res.
12. Design of Bi-gas Pilot Plant. R. J. Grace and V. L. Brant.
Fifth Synthetic Pipeline Symposium. Chicago. October 29-31, 1973.
13. Coalgate, J. L., Akers, D. J. and From, R. W. "Gob Pile Stabilization,
Reclamation, and Utilization", OCR R&D Report 75, 1973.
14. EPA Symposium "Environmental Aspects of Fuel Conversion Technology"
Colony Oil Shale Development M. T. Atwood. St. Louis, Missouri
May 13-16, 1974. (EPA 650/2-74-118 dated October 1974).
15. Federal Register Vol. 36. No. 247. December 23, 1971. pg. 24879
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- 79 -
16. Bartok, W., Crawford, A. R., and Piegari, G. J., "Systematic Field
Study of NOX Emissions Control Method for Utility Boilers", P.B. 210739,
Dec. 1971.
17. Atmospheric Emissions from Petroleum Refineries, U.S. Dept, of Health,
Educ, and Welfare, Public. No. 783, I960.
18. Pearson, M, J., "Hydrocarbon Process, 5_2_, (2), p. 81.
19. Hydrocarbon Processing, April 1973. pg. 92
20. Interim Report No. 3, "Phase II - Bench Scale Research on CSG Process"
(January 1970) Book 3, "Operation of the Bench - Scale Continuous
Gasification Unit".
21. Hydrocarbon Processing April 1973. pg. Ill
22. Hydrocarbon Processing April 1973. pg. 109-116
23. Lee, R. E-, et al., "Trace Metal Pollution in the Environment", Journ.
of Air Poll. Control, 23_, (10) October, 1973.
24. Hydrocarbon Processing July 1974. pg. 129. "Impure Feeds Cause Glaus
plant problems", G. G. Goar.
25. "Profit in processing Foul Water" Oil Gas Journal June 17, 1968. pg. 96-98.
and US Patent 3,518,056 and 3,518,166.
26. Coal Tar Auto-oxidation - Kinetic studies by Viscometric and Refractometric
methods. Yung-Yi Lin, L. L. Anderson, W. H. Wiser. ACS Div. Fuel Chem.
Preprint. Vol 19. No. 5. p. 2-32. September 1974
27. Control of Mine Drainage from Coal Mine Mineral Wastes" August 1971.
Water Pollution Control Research Series 14010 DDH 08/71 (P.B. 208326).
28. "Biological Removal of Carbon and Nitrogen from Coke Plant Wastes".
J. E. Barker, R. J. Thompson EPA R2-73-167 April 1973. (P.B. 221485).
29. Purification of Waste Water from Coking and Coal Gasification Plants
using Activated Carbon. Harold Jungten, Jurgen Klein. ACS Div Fuel
Chem. Preprint. Vol. 19. No. 5. p. 67-84. September 1974.
30. "Waste Water Engineering" Handbook by Metcalf and Eddy Co. (McGraw Hill)
31. National Public Hearings on Power Plant Compliance with Sulfur Oxide
Air Pollution Regulations, EPA, January 1974.
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- 80 -
32. Chemical Engineering: Environmental Engineering, October 21, 1974
pages 79-85.
33. Status of Flue Gas Desulfurization Technology, F. T. Princiotta
EPA Symposium on Environmental Aspects of Fuel Conversion
Technology. St. Louis, Mo. May 13-16, 1964, (EPA 650/2-74-118,
dated October 1974).
34. Environmental Factors in Coal Liquefaction, J. B. O'Hara et. al.
EPA Symposium on Environmental Aspects of Fuel Conversion Technology
St. Louis Mo. May 13-16, 1974, EPA 650/2-74-118, October 1974.
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TECHNICAL REPORT DATA
(Please read liiuriictivns on the reverse before completing)
1. REPORT NO.
EPA-650/2-74-009-f
4. TITLE ANDSUBTITLE
Evaluation of Pollution Control in Fossil Fuel
Conversion Processes
Liquefaction: Section 2. SRC Process
7. AUTHOR(S)
C.E. Jahnig
9. PERFORMING ORG "vNIZATION NAME AND ADDRESS
Exxon Research and Engineering Co.
P. O. Box 8
Linden, NJ 07036
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
3. RECIPIENT'S ACCESSION*-NO.
5. REPORT DATE
March 1975
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO
GRU.8DJ.75
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADD-023
11. CONTRACT/GRANT NO.
68-02-0629
13. TYPE OF RE PORT AND PERIOD COVERED
Final (Task)
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The report gives results of a review of the Solvent Refined Coal (SRC) process of
the Pittsburg and Midway Coal Mining Company, from the standpoint of its
potential for affecting the environment. It includes estimates of the quantities of
solid, liquid, and gaseous effluents, where possible, as well as the thermal
efficiency of the process. It proposes a number of possible process modifications
or alternatives which could facilitate pollution control or increase thermal
efficiency, and points out new technology needs.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Air Pollution
Coal
Liquefaction
Fossil Fuels
Thermal Efficiency
b.lDENTIFJ t HS/OPEN ENDED TERMS
Air Pollution Control
Stationary Sources
Clean Fuels
SRC Process
Research Needs
. COSATI I
13B
2 ID
07D
20M
3. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
20. SECURITY CLASS (This page)
Unclassified
21. NO. OF PAGLS
8_7
"22. PRICE"
EPA Form 2220-1 (9-73)
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