EPA-650/2-74-009-g
May 1975
Environmental Protection Technology Series
ALUATION OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION
PROCESSES
GASIFICATION: SECTION 5. BI-GAS PROCESS
U.S. Environmental Protection Agency
Office of Research and Development
Washington, 0. C. 20460
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EPA-650/2-74-009-g
EVALUATION OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION
PROCESSES
GASIFICATION: SECTION 5. BI-GAS PROCESS
by
C. E. Jahnig
Exxon Research and Engineering Company
P. O. Box 8
Linden . New Jersey 07036
Contract No. 68-02-0629
ROAP No. 21ADD-023
Program Element No. 1AB013
EPA Project Officer: William J. Rhodes
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH AND DEVELOPMENT
WASHINGTON, D. C. 20460
May 1975
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EPA REVIEW NOTICE
This report has been reviewed by the National Environmental Research
Centt-r - Research Triangle Park, Office of Research and Development.
EPA. and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development. U.S. Environ-
mental Protection Agency, have been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These series are:
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOCIOECONOMIC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
Publication No. EPA-650/2-74-009-g
11
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TABLE OF CONTENTS
. SUMMARY . -. -
2. INTRODUCTION ' ' v......;... 3
3. BASIS AND BACKGROUND « >' * ' 5
4. PROCESS 'DESCRIPTION......... ........... - 6
4.1 Coal Preparation 'and Drying. - 6
4.2 Gasification j>
4.3 Quench and Dust Removal 10
4.4 Shift Conversion 10
4.5 Acid Gas Removal j°
4.6 Methanation and Drying j^
4.7 Auxiliary Facilities 12
5. EFFLUENTS TO AIR 13
5.1 Coal Preparation and Drying 13
5.2 Gasification 21
5^3 Quench and Dust Removal 21
5.4 Shift Conversion 22
5.5 Acid Gas Removal 22
5.6 Methanation and Drying 23,
5.7 Auxiliary Facilities 2A
6. EFFLUENTS - LIQUIDS AND SOLIDS 26
6.1 Coal Preparation 2^
6.2 Gasification 2^
6.3 Quench and Dust Removal 2^
6.4 Shift Conversion 2°
6.5 Acid Gas Removal 30
6.6 Methanation and Drying 31
6.7 Auxiliary Facilities 32
7. GAS HANDLING AND SOUR WATER CONSIDERATIONS 33
8. SULFUR BALANCE 36
9. THERMAL EFFICIENCY 38
10. TRACE ELEMENTS 41
111
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TABLE OF CONTENTS (Cont'd)
11. ALTERNATIVES TO CONSIDER 44
12. TECHNOLOGY NEED.S ... 50
13. PROCESS DETAILS... 54
14. QUALIFICATIONS , 62
15. BIBLIOGRAPHY 63
iv
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LIST OF TABLES
Table
2
Table of Conversion Units. ... . - ' >
8
1 Coal Feed - W. Kentucky No. 11 .......... ...............
. ~ 9
2 Products from BI-GAS Process. ......... .............. ...... .-
3 BI-GAS Process - Inputs and Effluents.- ..-....-........-....
4 Flue Gas Flow Rates and Composition
From Boiler Plus Steam Superheater. .
37
5 Sulfur Balance ................................. .........
6 Thermal Efficiencies for BI-GAS Process.. ...............
7 Example of Trace Elements That May ^
Appear in Gas Cleaning Section ..........................
45
8 Alternatives to Consider ................................
9 Technology Needs ...... .................................
10 Steam Balance for BI-GAS Base Case ............... .......
11 Water Requirements for BI-GAS Base Case. ..... ...........
12 Electric Power Consumption ..............................
13 Make Up Chemicals and Catalyst Requirements ............. 58
59
14 Potential Odor Emissions ................................
15 Potential Noise Problems ................................
61
16 Miscellaneous Inputs ................................
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LIST OF FIGURES
Figure
1 Flow Plan and Flow Rates for Plant
Making 250MM SCFD of Pipeline Gas
From W. Kentucky No. H Coal
Block Diagram Showing Streams In
& Out of Specific Sections of Plant
Possible System for Pumping Coal
to High Pressure, Using Slurry ........................... 47
vl
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- 1 -
1. .SUMMARY
The BI-GAS Process of Bituminous Coal Research, Inc. has been
reviewed from the standpoint of its effect on 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 reducing environmental impact, a number of possible process
modifications or alternatives have been proposed and new technology
needs have been pointed out.
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- 2 -
To Convert:From
Btu
Btu/pound
Cubic feet/day
Feet
Gallons/minute
Inches
Pounds
Pounds/Btu
Pounds/hour
Pounds/square inch
Tons
Tons/day
TABLE OF CONVERSION UNITS
To
Calories , kg
Calories, kilogram
Cubic meters/day
Meters
Cubic meters/minute
Centimeters
Kilograms
Kilograms/calorie, kg
Kilograms/hour
Kilograms/square centimeter
Metric tons
Metric tons/day
Multiply By
0.25198
0.5552
0.028317
0.30480
0.003785.
2.5400
0.45359
1.8001
0.45359
0.070307
0.90719
0.90719
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- 3 -
2. INTRODUCTION
Along with improved control of air and water pollution, the
country is faced with urgent needs for energy sources. To improve the
energy' situation, intensive efforts are under way to upgrade coal, the
most plentiful domestic fuel, to liquid and gaseous fuels which give less
pollution. Other processes are intended to convert liquid fuels to gas.
A few of the coal gasification processes are already commercially proven,
and several others are being developed in large pilot plants, these pro-
grams are extensive and will cost millions of dollars, but this is war-
ranted by the projected high cost for commercial gasification plants and
the wide application expected in order to meet national needs. Coal con-
version is faced with potential pollution problems that are common to
coal-burning electric utility power plants in addition to pollution prob-
lems 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 No. EPA-68-02-0629, using
all available nonproprietary information.
The present study under the contract involves preliminary design
work to assure that the processes are free from pollution where pollution
abatement techniques are available, to determine the overall efficiency of
the processes, and to point out areas where present technology and informa-
tion are not available to assure that the processes are nonpolluting. This
is one of a series of reports on different fuel conversion processes.
All significant input streams to the processes must be defined,
as well as all effluents and their compositions. This requires complete
mass and energy balances to define all gas, liquid, and solid streams.
With this information, facilities for control of pollution can be examined
and modified as required to meet Environmental Protection Agency objectives.
Thermal efficiency is also calculated, since it indicates the amount of
waste heat that must be rejected to ambient air and water and is related
to the total pollution caused by the production of a given quantity of
clean fuel.
Suggestions are included concerning technology gaps that exist
for techniques to control pollution or conserve energy. Maximum use was
made of the literature and information available from developers. Visits
and/or contacts ^?ere made with the developers to 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.
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- 4 -
Considerable assistance was received in making this study,
and we wish to acknowledge the help and information furnished by EPA
Bituminous Coal Research, Inc., and by Steams-Roger Inc. The process
design and balances used in this study are based on a detailed report
on the BI-GAS process prepared by Air Products and Chemicals, Inc. (9)
Acknowledgement is also made to Dr. Henry Shaw of Exxon
Research and Engineering who made the initial contacts to assemble
background information on the BI-GAS process.
Four previous reports in this series on gasification were
issued as Section 1 with the various process names listed. In reality
they were Sections 1, 2, 3, and 4; thus, this report is labeled as
Section 5.
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- 5 -
3. BASIS AND BACKGROUND
A number of processes have been evaluated for making clean fuel
from coal (1,2,3,4,5,6). These include gasification at pressures from near
atmospheric in the case of Koppers-Totzek, to 1,000 psig, for example
with BI-GAS or Synthane. Reaction temperatures also cover a range of
from moderate temperatures in the Lurgi process, to very high temperatures
in the Koppers-Totzek process with slagging of the ash. Some processes
such as Lurgi and Synthane make byproduct char or tar, while others make
no by-products (C02 Acceptor and Koppers-Totzek processes). The BI-GAS
process avoids making by-product char or tar, using a two zone gasifier
with the upper zone at 1700°F, while the lower zone is at 3000°F and
produces slag from the coal ash.
As a result of early studies, Bituminous Coal Research concluded
that an optimum type gasification process would have the following features:
(1) Operation at high pressure to avoid the need for
compression when supplying pipeline gas.
(2) Make no char by-product.
(3) No tars or liquid products would be produced
which would complicate the clean-up.
This led to the concept of a high-pressure,two zone gasifier. Temperature
of the upper zone is high enough to prevent tar formation, while the
lower zone is at 3000°F so that residual slag is low in carbon content
and can be discarded. A further advantage of high pressure is that
it increases the amount of methane formed in the gasifier, thereby significantly
reducing the heat load on the gasifier and the gas volume to be handled
in the downstream operations.
Information is available in the literature on the BI-GAS process,
including the design of the pilot plant facilities (7,8 ), and projections
of a commercial plant design and operation (9). In the present study
to evaluate environmental aspects of the process, we have used as a starting
basis the commercial plant projections developed by Air Products and
Chemicals, Inc. (9). Some modifications were made where necessary to assure
environmentally sound operations, as for example, to reduce sulfur emissions
from coal fired furnaces. Also, in the course of the study, other modifications
became apparent which could give better environmental control or improve
thermal efficiency of the process, and these are described briefly in this
report for consideration.
The plant is sized to make 250 million SCFD of pipeline gas by
gasifying coal with steam and oxygen. The design includes shift conversion
and methanation to give a gas with a heating value of 943 Btu per cubic foot,
available at 1,075 psia. Western Kentucky coal la used, and after cleaning
and washing, the amount is 14,535 tons per day (at a nominal 8.4% mois-
ture) which provides all of the fuel for coal drying and utilities
production in addition to the gasification requirements.
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- 6 -
4. PROCESS DESCRIPTION
A flow plan of the process is shown in Figure 1, together with
major flow rates and operating conditions. Coal used is shown in Table 1,
while products are shown in Table 2. It is convenient to subdivide
the process into the following operations, each of which will be described
in the following subsections: (1) Coal Preparation, (2) Gasification,
(3) Quench and Dust Removal, (4) Shift Conversion, (5) Acid Gas Removal,
(6) Methanation, and (7) Auxiliary Facilities.
4-1 Coal Preparation and Drying
This process section includes crushing, cleaning and drying as
well as a storage pile with 30 days capacity. Run of mine coal feed
amounts to 23,243 tons per day. This is crushed and coarse refuse is re-
jected amounting to 4,804 tons per day. The coal can then be sent to
storage, or to the washing operation which rejects an additional 3,904
tons per day. Drained coal from washing, containing 8.4% moisture, is
used partly as fuel to the utilities plant supplying steam for the pro-
cess, while the remainder goes to the grinding and drying facilities.
Here it is ground to 70% smaller than 200 mesh, dried to 1.3% moisture,
and sent to storage silos. Some of the dried coal is used as fuel in
the dryer, amounting to 11,137 pounds per hour or about 134 tons per
day.
Since the gasifier operates at 80 atmospheres, it is necessary to
pressurize the coal feed. The original design used piston feeders to push
the coal into a high pressure feed hopper and is the system used in the
present environmental evaluation. Subsequent work has indicated that other
methods such as lock hoppers or slurry feeding may be preferable; however.
the change would make only minor modifications in effluents to the
environment, although thermal efficiency would be lower than for the case
using piston feeders.
4.2 Gasification
The coal is gasified using steam and oxygen in a two zone reactor
at 80 atmospheres. Operation of the reactor is based on entrained flow
rather than using a fluidized bed or fixed bed reactor. Coal is fed
to the top 1700°F zone where it mixes with steam and hot synthesis gas
entering from the lower zone. Conditions in this upper zone favor high
formation of methane, with negligible amounts of tar or oil. Although
the volatile content of the coal feed is completely consumed, there is
considerable unreacted char remaining which is carried out with the gas
and recovered by cyclones following the reactor.
The char is recycled by means of lock hoppers to the lower
gasification zone where it is reacted with steam and oxygen at 3000°F.
A special char feeding system is provided, since it is indicated that
a reliable and very uniform feed rate must be maintained, so as to avoid
conditions that could give excessive flame temperatures. Synthesis gas
is formed and passes to the upper reactor as described earlier. Slag is
withdrawn from the bottom, quenched with water, and removed by way of
lock hoppers. Since it has little or no combustible content, it can be
discarded (from an energy viewpoint).
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STORAGE
30
DAYS
R.O.M. COAL FEED
1,936,899
8.4V. racist 1
(23,243 cp_d)[
TO BOILER 148 400
TO SUPHTR 31 200
1,211,256 '
\
-" BREAKER "'
WASHINC
\WA
CO
k . 946,307
1.31 MOISTURE
\
SHED
AL
/ "
CRUSH
DRY
;ROUND\
COAL \
COAL 8-4% MOIST 11,137
SILOS
10 @
800T
each
BICAS - PROCESS
FLOWPIAN AND FLOW RATES FOR PLANT MAKING 250MM SCFD OF PIPELINE GAS FROM W. KENTUCKY NO. II COAL
(NUMBERS ARE LB/HR EXCEPT AS NOTED) 1115°F
RAW
QUENCH
VESSEL
REFUSE
400,357
(4804 tpd)
REFUSE
325,286
(3094 tpd)
SULFUR
35,132
(422 tpd)
TAIL GAS
513,287
(Includes 4.3 tpd
of sulfur)
v ' s~\
A /O,3823
/
,._
650°F i^
CLEANED
WET
GAS
68,391
PIPELINE GAS PRODUCT
250MM SCFD
1075 psia
943 Btu/SCF HHV
Vol.% CH4 91.8%
H, 5.1
N2 1.9
CO, 1.1
CO 0.1
100.0%
SAND FILTERS
(Back blow not Included
in flow rates)
-/
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- 8 -
Table 1
Coal Feed - W. Kentucky No. 11
Proximate Analysis' Wt %
Moisture
Volatile matter
Fixed carbon
Ash
Ultimate Analysis Wt. %
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen (by diff.)
As Rec'd.
8.4
39.5
45.4
6.7
68.15
4.67
1.37
3.48
7.24
Dried
1.3
42.5
49.0
7.2
73.40
5.03
1.48
3.75
7.84
Moist &
Ash Free
46.5
53.5
--
80.20
5.50
1.62
4.10
8.58
84.91
91.50
100.00
Heating Value
HHV Btu/lb.
12,330
13,285
14,510
Coal Consumed
Coal Dryer
Gasification
Utility Boiler
Steam Superheater
% Moisture
1.3
1.3
8.4
8.4
Ib/hr
11,137
946,307
148,400
31,200
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- 9 -
Table 2
Products from BI-GAS Process
Pipeline gas
Volume, MM SCFD
Pressure psia
Temperature °F
High Heating Value Btu/SCF
Composition vol%
N2
co2
CO
By product Sulfur' tpd
Slag (dry basis) tpd
Gaeifier
Dryer
Boiler + Superheater
NH . potential tpd
(@ 60% of N in coal)
250
1075
95
943
91.8
5.1
1.9
1.1
0.1
100.0
422
820
10
144
974
112
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4.3 Quench and Dust Removal
Hot raw gas from the gasifier passes to cyclone separators which
remove most of the char and solid particles in the gas. Quench water is
added to the cyclone in order to moderate the temperature, and additional
quench water is added in a quench vessel after the cyclone separator.
The quenched gas still contains some dust that was not removed
by the cyclones, but must be removed so as not to plug the fixed bed of
shift conversion catalyst. Rather than scrub the dust out with water,
which would require considerable cooling, the dust is filtered out
at high temperature using sand beds. These operate in parallel in a
cyclic manner. Pressure drop will build-up during the onstream cycle,
and the bed is cleaned when necessary by back flushing with clean gas
so as to lift and agitate the sand particles. Entrained dust from back
flushing is then returned to the gasifier where it leaves with the slag.
4.4 Shift Conversion
After dust removal, the gas next goes to a shift converter where
carbon monoxide reacts with steam to form hydrogen and carbon dioxide increasing
the ratio of H2 to CO to three to one as required in the final methanation.
A sulfur resistant shift catalyst must be used, resulting in relatively
low activity compared to those used on sulfur free gases. A large excess
of steam is maintained to give 50 mol. % steam in order to facilitate the
desired reaction and to prevent catalyst degradation or carbonaceous
deposits. Steam conversion in this shift reactor is about 21L.
After shift conversion, the gas is cooled to remove most of the
an^n^^^
disposed of by using itas part of the quench water and thereby provides steam
required for shift conversion. One advantage of this specific design is
that a very large quantity of sour water can be disposed of by injecting
ft into the hot'gas for quenching. A further advantage is that no facilities
are then needed for generating steam used in shift conversion, and neither
are exchangers needed for cooling the hot raw gas from the gasifier.
4.5. Acid Gas Removal
Removal of all sulfur compounds is needed to meet pipeline gas
specifications and to protect the methanation catalyst. The bulk of the
sulfur, as well as CO , is removed using the proprietary Benfield process
based on hot carbonate scrubbing. Two separate absorber towers are used
in series. The first of these produces a gas relatively high in sulfur
content, about 8% H S, to facilitate sulfur recovery in the Glaus plant.
The second absorber is for final cleanup of sulfur from the gas and for
CO- removal.
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- 11 -
Most of the C02 is removed in this second absorber and vented
to the air;, however, this COo vent stream contains excessive amounts
of ^S, namely 3400 ppm,, and further processing is needed to clean it up.
Therefore, adsorption using molecular sieves has been' provided to recover
the H2S content and send it to the Glaus sulfur plant. Air Products
has indicated, (9) that .a Rectisol process which uses scrubbing with refriger
ated methanol would be preferable for acid gas removal, and that it would
produce a reasonably concentrated stream of I^S for the Glaus plant
while at the same time giving a clean C02 stream which could be vented
directly to the air. However, other studies indicate that this vent stream
from a Rectisol unit requires incineration or cleanup because of excessive
content of combustibles and sulfur (5). The Rectisol process uses methanol
scrubbing at low temperature, and can remove carbonyl sulfide and other
contaminants. Gas leaving the hot carbonate scrubbing system used in the
present design contains moisture, most of which is removed by cooling the
gas ahead of methanation. This is a clean condensate which can be used
for boiler feed water make-up.
Gasification can produce many compounds in addition to
such as cyanides and thiocyanates as well as large amounts of ammonia.
There are also various sulfur compounds, particularly carbonyl suicide
and some carbon disulfide. It is essential to completely remove all of
these before methanation in order to protect catatlyst activity.
Most of the ammonia and compounds that are highly soluble in water will
be removed in the condensation after shift conversion. Hot carbonate
systems for acid gas removal have the important advantage that they do
remove carbonyl sulfide. Amine systems, in general, do not remove . carbonyl
sulfide, 'and moreover react irreversibly with cyanides thus requiring purge
of the chemical solution.
4.6 Methanation and Drying
Clean synthesis gas is methanated in this section to increase
the heating value of the gas up to pipeline quality. The reaction of
CO with 3 volumes of H2 to make methane and water can be carried out in
a fixed bed of nickel catalyst. A guard bed of zinc oxide ahead of the
reactor removes traces of sulfur compounds in order to protect the
methanation catalyst. Methanation is a highly exothermic reaction,
releasing about 207, of the heating value in the reacting gases. Reactor
temperatures of 500°F at the inlet and 850°F at the outlet are maintained
by recirculating some of the gas leaving the reactor through exchangers
to generate high pressure steam. Methanation is carried out to a high
conversion so that the residual CO content is no more than the 0.1 Vol. 70
specified for pipeline quality gas. Residual hydrogen content is 5.1 Vol. 7o.
Since methanation generates a considerable amount of water, this is
recovered as clean condensate upon cooling. More complete drying of the
gas is then carried out using a glycol system to meet the requirement
of 7 lb water maximum per MM SCF of gas.
For the present study the processing sequence used by Air
Products has been followed. Their flow rates and utility requirements
were reviewed and used in the evaluation of environmental aspects.
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- 12 -
4.7 Auxiliary Facilities
In addition to the gasification system, auxiliary facilities are
needed to make .the plant completie and self-sufficient. A Glaus plant is
included to make by-product sulfur from the H2S that is recovered in acid
gas removal. The basic Glaus plant will not give adequate sulfur recovery
or clean-up, since the feed gas will contain no more than 157o H2§, therefore
tail gas clean-up was added.
A conventional air separation plant is included in the base design
to provide oxygen needed for gasification. It does not generate contaminated
waste streams, but it is a large consumer of utilities and therefore has
an important effect on thermal efficiency.
As would be expected, the process uses large amounts of steam
and electricity. All utilities needed to make the plant self-sufficient
are provided in the design, including high pressure and low pressure steam,
electric power generation, water make-up treating, circulating cooling
water, and waste water treating. Fuel requirement for these has been
been included on the basis that coal would be used for fuel. Since the
coal has a high sulfur content, pollution control will be needed .on
these fuel consumers. The simplest approach is to add flue gas clean-up
so that coal can still be used as fuel, and a number of processes are
available (10). An alternative would be to use low sulfur, low Btu gas
made in the process for fuel in utilities generation and in coal drying.
The particular study includes, utilities requirements for offices
shops, laboratories, and cafeteria (e.g. 50,000 Ib/hr of steam for heating'
buildings). These are not always included in similar studies of other
processes; therefore, caution is required in making comparisons with other
studies.
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- 13 -
5. EFFLUENTS TO AIR
Overall flow rates for the process were shown in Figure 1. Figure 2
and Table 3 show all of the streams entering and leaving specific units,
some of which are returned to other units within the plant. All streams
which are actually discharged to the environment are indicated by heavy
dashed lines in Figure 2 and by asterisks in Table 3. For discussion these
are grouped according to whether they are released to the air or represent
liquid and solid effluents. Effluents to the air are discussed in the
following subsections.
5.1 Coal Preparation and Drying
The first effluent to the air is from the coal handling and
preparation area. Run of mine coal is delivered by rail and truck and
conveyed to a breaker where it is crushed to 1-1/2 inches and smaller.
Refuse amounting to 4804 tpd is rejected at this point and must be disposed
of in a suitable manner. Such operations will normally have a dust problem,
and careful consideration.and planning is required for control. Covered
conveyers should be provided wherever possible; even so> there may be
vent streams or leaks that could release dust. If needed, a dust collection
system could be used operating at slightly below atmospheric pressure
to collect vent gas and pass it through bag filters. Since spills from
conveyers and leaks can also create dust, facilities such as clean-up
equipment and water sprays may be needed.
The coal storage pile is also of concern in that wind can pick
up and disperse fine particles. Evaluation is needed for each specific
situation in order to provide proper control measures. Proposals for
dust control have been made such as spraying oil or asphalt on the surface
of the pile, or covering it with plastic. The amount of coal handled is
so large that a loss of even a small fraction of a percent could be
excessive.
A further consideration on any coal storage pile is the possibility
of fires and spontaneous combustion which would result in evolution of odors,
fumes, and volatiles. One control measure is to compact the pile by layers
as it is being formed. In any event, plans and facilities should be
available for extinguishing fires if they occur (11).
The next step is to wash and screen the coal, and in this operation
another 3904 tpd of refuse is rejected. Disposal of this refuse should
be carried out in a way to avoid pollution. Since it is wet there should
be little or no dusting problem except when it dries out. However, it can be
expected that there will be spills of the refuse or coal in the coal preparation
area, and that these will create a dust nuisance when they dry out and are
disturbed by the wind or by trucks- Again this calls for plans and facilities
for cleaning up dust and for flushing to the storm sewers. Although a
detailed design of this coal preparation and handling system is not available,
it will no doubt include a tailing pond to allow recovery and disposal
of fine material from the washing operation. Proper environmental controls
are needed as discussed in the literature (12).
-------
Figure 2
BIGAS PROCESS
BLOCK DIAGRAM SHOWING STFAMS IN & OUT OF SPECIFIC SECTIONS OF PLANT
2345 .67
t||| j|
RUN OF
MINE COAL
"
CRUSH
AND
WASH .
CLEANED
COAL
~^
GRIND
AND
DRY
line, other streams are returm
8 9
_L _i^
GROUND
COAL
GASIFIER
QUENCH
RAW GAS & CLEANED_GAS ^-
SAND J~
FILTERS
ttf It lit n
,J il-li U » >' ""
20 21 22 23
24 25 26
1 ill! _LL
CLEANED
/GAS .^
SHIFT
COOL
SHIFTED GAS ,
ACID GAS
REMOVAL
M
27 28
SCRUBBED GAS
^
METH.
DRYER
^__ PIPELINE GAS
1
29
30 31 32 3334353637 383940 414243 444546
4 fc $ HI'
f I ? lit
SULFUR
PLANT
WASTE
WATER
[j III Hi \\\
TREAT.
MAKEUP.
WATER
TREAT.
COOLING UTILITY
TOWER BOILER
i J /, A ft A
TTT
47 48 49
TT
50 51
It
52 53
TTT
54 55 56
57 58 59
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- 15 -
Table 3
Stream
Number
1
2
3 *
4 *
5 *
6 *
7 *
BI-GAS
Identification
Coal to gasifier
Rain runoff
tfind
Refuse
dash water
Flue gas
Spent limestone
Process - Inputs and
Flow Rate
Ib/hr
946,307
e.g. 6" in 24 hrs.
--
400,357
e.g. 4000 gpm
131,700
2,970
Effluents
Comments
Dried cleaned coal 1.37= moisture
Runoff from coal storage pile
Can cause dust nuisance
Rock waste from coal cleaning
Recirculate through clarifiers and
tailing pond for cleanup & reuse.
Vent gas from coal dryer.
(For analyses see Table 4)
From vent gas cleanup on coal
8* 'Slag from gasifier
Dust recovered by
sand filters
10 Rain
11 Wind
68,391
e.g. 6" in 24 hrs.
12
13
14
15
16
17
18
19
Wash water
Air
Limestone
Steam
Oxygen
Quench water
Sand
Quench water
e.g. 4000 i
122,700
2,500
409,719
497,625
68,270
--
1,254,87
dryer, e.g. spent limestone
plus ash from coal fuel
Plus equal wt.,of water to fo.rm
slurry for handling
Returned to gasifier by back :
blowing with part of cleaned gas,
e.g. 5% of total gas
Rain on coal storage and handling
area
Wind effect on coal storage and
handling area
Used to clean crushed coal
For burner on coal dryer
Raw materials used for stack gas
cleanup
To gasifier to react with coal
Oxygen to gasifier to generate
heat
To quench 3000^ slagsteam Is
returned to gasifier
Makeup to sand bed filter
Quenches 1700"F raw gas from
gasifier, includes sour water
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- 16 -
Table 3 (Cont.)
BI-GAS Process - Inputs and Effluents
Stream
Number Identification
20 Sour water
21* Chemical purge
22 H2S stream
23 H2S (pure)
24* C02 vent stream
25 Water
26* Water reject
27 Chemical makeup
28 Molecular sieve
29 Glycol
30* Tail gas
31* Sulfur
32* Purge chem.
33* Ammonia
34 H2S
35* Phenols
Flow Rate
Ib/hr
866,613
e.g. 50,000
451,429
3,825
1,147,115
214,818
27,219
513,287
35,132
7,689
e.g. 87
Comments
Condensed from raw gas, contains
H2S. NHo etc. Is returned to
Quench (#19 above)
Purged to reject contaminants from
acid gas scrubbing solution. Will
contain potassium carbonate
Acid gas sent to Glaus plant for
sulfur recovery (6.9 vol. 7« H2S,
44.7 vol. % C02, 48.4 vol. % H20)
To Glaus plant. From molecular
sieve recovery on C02 vent gas.
From acid gas removal (mol. sieve is
used to control sulfur emission).
Formed by methanation reaction
Removed by glycol dryer on product
gas
Makeup chemicals to acid gas removal
system. Will include K^CO-j and
possibly inhibitors, antifoam
agents, etc.
Makeup on sieve to clean up C02
vent stream
Makeup agents to glycol dryer
From sulfur plant after tail gas
cleanup
By-product sulfur recovered
From tail gas cleanup operation,
purged to reject contaminants
Potential by-product separated in
waste water treating
Stripped out of sour water and
sent to sulfur plant.
Potential by-product or to disposal
from waste water treating -- amount
unknown
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- 17 -
Stream
Number
36
37i
38
39*
Table 3 (Cont.)
BI-GAS Process - Inputs and Effluents
Identification
Treated water
Sludge
Makeup water
Chemical waste
Flow Rate
Ib/hr
86,000
see Table 13
3,489,000
see Table 13
Comments.
Water after, treating. A small
stream of sour water will probably
have to be purged to reject conta-
minants and trace elements from
the system. Further information
is needed to define cleanup require-
ments.
Sludge formed in waste water treating,
e.g. from biox,misc. solids. May have
odor problem: Should be incinerated.
To cooling tower and boiler feed
water
Chemicals used in treating makeup
water
40*
Sludge
41*
42*
43*
44*
45*
//:*
46
47
48
49
50
Air
Water mist
Water
Flue gas
Slag
Spent limestone
H2S stream
Air
Chemical
Sour water
51
Chemicals
see Table 13
272,000,000
(85 MMM SCFD)
e.g. 263,000
ca. 600,000
1,971,000
12,033
44,530
455,254
93,165
e.g. 86,000
see Table 13
Sludge formed in treating water
makeup with lime, alum., etc. can
be disposed of with slag.
Air flowing through cooling tower
(plus evaporated water 2,626,000 Ib/hr)
Drift loss from cooling tower
(0.2% of circl.)
Slowdown1from cooling tower
From utility boiler (see Table 4).
From coal used as fuel on utility
boiler (may dispose of with gasifier
slag)
Used to desulfurize flue gas on
utility furnaces
To sulfur plant for recovery (Streams
22 and 23)
Used in Claus plant to burn H S
To tail gas cleanup on Claus plant.
Purge of sour water may be required
to prevent build up of trace elements
etc. in recirculated sour water.
As required to clean up purge
stream of sour water.
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- 18 -
Table 3 (Cont.)
BI-GAS Process - Inputs and Effluents
Stream
Number Identification
52 Makeup water
53 Chemicals
54 Air
55 Cooling water
56 Chemicals
57 Air
58 Coal
59 Limestone
Flow Rate
Ib/hr
3,489,000
see Table 13
272,000,000
(85 MMM SCFD)
262,580 gpm
see Table 13
1,837,000
179,600
37,500
Comments
Treated and used as makeup for
cooling tower and boiler feed
water
Used to treat makeup water, e.g.
lime, alum, caustic, acid, ion ex-
change resin
Air flow through cooling tower
Recirculated cooling water
Antifouling (e.g. chlorine) and
anticorrosion (e.g. chromate)
agents in cooling water circuit.
Combustion air used in utility
furnaces
Coal fuel used in utility boiler plr
superheater (8.4% moisture)
Used for stack gas cleanup on
utility furnaces
* Streams emitted :to the environment.
Other streams are returned to process.
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Noise control should be carefully considered since it is often a
serious problem in solids handling and size reduction. If the grinding
equipment is within a building, the process area may be shielded from
undue noise, but additional precautions are needed for personnel inside the
building.
Following the washing operation, cleaned coal is sent to the
crushing and drying system and also to the utility areas as fuel. Adequate
dust control is needed on all these handling operations. In the dryer,
moisture content is reduced from 8.4% to 1.37» by contacting with hot
flue gas. Heat is supplied by burning part of the dried coal. Since this
fuel has 3.75% sulfur, corresponding to 5.64 Ib SC>2 per MM Btu, it will
be necessary to clean up the vent gas to remove sulfur as well as particulates.
It will be desirable to recover and use the coal fines, for example, by
using dry cyclones, then sulfur in the flue gas can be removed by one of
the processes that are offered for stack gas clean-up (13). Some of these
have proposed to use a throw-a-way limestone medium, while others provide
for regeneration of a chemical scrubbing agent to make by-product sulfur,
sulfuric acid, or gypsum.
In the drying operation a large volume of hot gas is contacted
with the coal. Oxygen content is normally limited to about 10 Vol. "/
by safety considerations. Also the maximum temperature should be limited
to avoid heating the coal above 500°F, so as not to release volatile matter.
It is common practice to use a large amount of excess air, such as 10070,
in order to minimize moisture content of the drying gas and thereby
facilitate drying. In some cases effluent gas may be recycled or inert
gas added to control gas temperature and oxygen content.
With the present high price of fuel, the design of drying facilities
should be reconsidered and optimized to minimize fuel consumption. This
subject is discussed more fully in a previous study (4). In brief, it is
desirable to operate the dryer with minimum excess air, for example 107,
excess, and to recycle vent gas as needed to control temperature of the
hot gas. This gives minimum fuel consumption as well as minimum volume
of vent gas to be cleaned up. Of course, the moisture content of the
drying gas will be higher than when a large amount of excess air is used
making it more difficult to achieve the same degree of drying, although
the moisture content of the dried coal could be allowed to increase slightly.
Further details on flue gas composition are given in Table 4 and accompanying
notes.
In general, it will be desirable to maximize the preheat temperature
on the coal feed, and to preserve this sensible heat so as to reduce heat
load on the gasifier and reduce oxygen requirement. Preheat temperatures
as high as 500°F have been used without substantial evolution of volatile
matter from coal. This temperature has also been considered practical from
the standpoint of using lock hoppers.
The coal feeding system for pressurizing the coal in this specific
design is based on a piston feeder as originally proposed. Storage silos
are also included. Normally there will be no effluent to the air from this
system, although it may involve pneumatic transport of coal,in which case
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- 20 -
Table 4
Flue Gas Flow Rates and Composition
From Boiler Plus Steam Superheater
Fuel Fired (Alternatives)
Fuel Ib/hr
Air Ib/hr
Flue Gas Ib/hr
Flue Gas Comp. Vol- °/°
C02
H20
S02
N2
02
Coal
179,600 (8.4% Moist)
1,837,000
1,971,000
(586 MM SCFD)
Low Btu Gas
132,663
,
(562 MM SCFD)
NOTES :
(1) Sulfur contained in above coal amounts to 6,250 Ib/hr, and
flue gas cleanup must be provided. Using limestone scrubbing,
for example, would require 37,500 Ib/hr of limestone, at
twice the theoretical consumption.
(2) On coal dryer, flue gas composition from combustion of coal
fuel will be similar to above. In addition, moisture amounting
to 74,212 Ib/hr is removed from coal, giving a total of 5I/c
in vent gas.
(3) Ash from coal used for fuel to be disposed of:
Coal dryer
Boiler plus Superheater
803 Ib/hr
12,033 Ib/hr
(4) High heating values are: 12,330 Btu/lb for coal, and 16,695
Btu/lb for low Btu gas.
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- 21 -
recovery and clean-up of the conveying gas is needed. In the event-that
lock hoppers are used instead of the piston feeder, then there will be.
considerably more vent gas from depressuring the hoppers which should
be cleaned-up and returned to the system. A promising way to reduce the
volume of gas from the lock hopper operation is to use pressure stages
so that the highest pressure gas from the final stage can be used to
pressure the initial lock hopper stage to an intermediate pressure level.
Instead of using stack gas clean-up on the coal dryer for sulfur
control, it would be possible to use part of the low Btu product gas for
fuel. Dust removal- on the vent gas could then be by bag filters or a
scrubber. This route would, of course, call, for an increased capacity
on the gasification system.
5.2 Gasification
In normal operation there will be no effluents to the air from
the gasification section, since all of the gas streams are contained and
processed in downstream equipment.
Slag formed in the lower zone of the gasifier is quenched with
water and the resulting steam flows back up into the gasifier. Quenched
slag is removed by way of lock hoppers. It is handled as a water slurry,
and reliance is placed in the shattering effect of the quench to control
particle size of the slag and provide a slurry that can be handled. Typically,
the slurry may contain equal weights of slag and water. Depending on the
final disposition of the slag slurry, there may or may not be a dust problem.
For example, if it is used as land fill or if it goes to a storage pile,
there could be a dust problem when it dries out. The possibility of odors
needs to be defined for the handling and disposal system. Also, other
emissions will occur and need to be defined.
5.3 Quench and Dust Removal
Raw gas leaving the gasifier goes through cyclones to recover
entrained dust or char, which is then returned to the lower stage of the
gasifier by means of lock hoppers. It should be possible to contain this
system and the pressurizing gas so that normally there will be no emissions
to the air.
After quenching, the gas goes through sand bed filters in parallel
to remove dust. These filters are cleaned by back blowing with part of
the synthesis gas, and this dusty stream is returned to the gasifier for
disposal and thereby contained within the system.
Normal maintenance will be needed on the sand filters and possibly
also as a result of upsets. Precautions are needed to control emissions
to the air during such periods, for example, in cleaning or replacing
the sand and on depressuring the equipment. Gas released on depressuring
should be recovered and returned to the system. Similar comments apply to
the lock hoppers and other parts of the process with regard to depressuring
and maintenance.
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- 22 -
5.4 Shift Conversion
Shift conversion does not generate gaseous effluents, but
a large amount of water is condensed following the shift converter and ahead
of acid gas removal. This water will contain ammonia, l^S and possibly
small amounts of other materials such as cyanides, phenols, etc.} if these
are formed in gasification, or during startup or upsets. The sour water
will have a very strong odor and care must be taken to avoid possible
leaks or spills. Normally, it will all be returned to the process and
used as part of the quench water ahead of the sand filters in order to
dispose of it without causing emissions to the air. A nominal amount of
sour water storage capacity would be desirable to assure that none will
have to be discharged during start-up or upsets.
While not directly associated with effluents to the air, it
should be pointed out that the closed system for handling sour water
and disposing of it by total recycle may have to be modified. Compounds
such as ammonia, phenols, etc., will be removed rather completely from
the gas during condensation and recycled to the quench point. Since
they are not destroyed in quenching, they will build-up in concentration
in the circulating sour water stream, so that facilities may have to be
added to separate them and purge them from the system. A similar situation
can occur with volatile trace elements. This subject is discussed further
in Section 6. EFFLUENTS - LIQUIDS AND SOLIDS.
5.5 Acid Gas Removal
This system removes sulfur compounds such as l^S and COS as
well as C02, using the proprietary Benfield process (14). It uses a
hot solution of activated potassium carbonate in two separate absorber
systems in series. The first of these produces an acid gas stream with
a relatively high content of H2S, which is sent to a Claus sulfur recovery
plant. There should be no specific emissions to the air from this first
scrubbing system.
In the second step residual sulfur is removed together with most
of the C02, producing a gas stream which is discharged to the atmosphere.
A further description of this acid gas removal operation is given in
Reference (9), which points out that the sulfur content of this C02 stream is
3400 ppm and will require additional processing to clean it up before
release to the atmosphere. One method is to use molecular sieves to adsorb
the H2S which is then desorbed and sent to the Claus plant, and this provision
is included in our environmental study.
The use of molecular sieves was said to be quite expensive, but
other techniques are available for consideration. One possibility is
to use an absorption/oxidation type process to remove l^S from the C02
vent stream. I^S would be oxidized using an activated scrubbing liquid
to form free sulfur which is separated as a by-product. Such processes
are offered for commercial use by Stretford, IFF, and Takahax (15).
Subsequent to the original study, Air Products indicated that the Rectisol
process which uses methanol scrubbing at low temperature would be better
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- 23 -
for acid gas removal in this application. However, results from plant
operation (38) and from planning studies (37) show that the CO- vent
stream from Rectisol also has an unacceptably high sulfur content. More-
over, it contains over 1 vol % combustibles including ethane, ethylene,
methane, and carbon monoxide. Incineration of this vent gas is necessary
from the standpoint of odors, combustibles, and H_S content (3,5).
Since flue gas desulfurization is used elsewhere in the process,
on the coal drier and utility boiler, it may be that this CC>2 stream could
be blended in and cleaned up with incremental additions to the flue gas
desulfurization system.
This particular BI-GAS design does not use air-fin cooling; instead,
all of the waste heat is transferred to cooling water. However, in many
applications the design will use air-fin cooling in order to minimize the
load on the cooling tower and the water make-up requirement. In such cases
careful consideration must be given to potential emissions to the air.
With air-fin exchangers, a very large volume of air is passed over the exchanger
surface, and in the event of leaks or tube failures, a considerable amount
of material can be dispersed in the air, causing serious emissions to the
atmosphere. This can be more of a problem for operations at very high
pressure, as at 1000 psig, and on contaminated streams such as sour water.
The problem is not avoided by using cooling water, since any
leakage will be into the cooling water which then flows through the cooling
tower where it is efficiently stripped by a large volume of air.
5.6 Methanation and Drying
After acid gas removal, the gas is reheated, passed through a
sulfur guard bed, and then to the methanation reactor. The system is all
enclosed, hence there should be no major effluents to the air. However,
there is considerable equipment that can be expected to contribute miscellaneous
emissions, including:
- Exchangers that may leak or fail.
Recycle gas compressors and valves.
- Circulating cooling water.
Leaks can be expected from such equipment operating at 1000 psig, especially
from seals. Methods have been developed for estimating the amount of
leakage in oil refineries,and techniques for monitoring and reducing
emissions have been carefully considered (16). Such background should
be applied in designing gasification plants so as to minimize potentially
undesirable emissions.
Clean condensate is recovered after methanation, and when this
is depressured, some gas will be released which should be recovered or
incinerated. Water is also separated in the final glycol drying step,
and should be recovered rather than being released to the atmosphere.
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- 24 -
5.7 Auxiliary Facilities
One of the auxiliary facilities associated with the process is
the Glaus plant to recover sulfur. The acid gas containing sulfur compounds
is first burned with added air to form free sulfur which is condensed and
recovered. This is followed by additional stages using a catalyst .to allow
operating at lower temperature so as to increase the sulfur recovery. A
typical value for sulfur recovery may be 977, in a three-stage operation,
provided the feed gas contains 20% or more of I^S. This would still give
excessive sulfur emission in the Glaus plant tail gas, amounting to about
25 tpd of SC-2 for this case. It is, therefore, necessary to add tail
gas clean-up, and this modification has been included in pur balances
and calculation of thermal efficiency. A number of processes are offered
commercially for such tail gas clean-up (17).
One other consideration on the sulfur plant'is to control odor
emissions due to leaks or associated with handling the .product sulfur.
There is an appreciable solubility of H2S in molten sulfur, and it may
escape during handling or storage; however, there are well established
techniques for controling this and other possible sources of contamination
such as sulfur dust.
The plant producing oxygen-for gasification is'relatively clean,
and the major effluent to the air is waste nitrogen. The operation is
conventional and is hot expected to emit undesirable compounds or odors.
It is, of course, a large energy consumer and so affects the size of the
utilities system, and contributes significantly to the total amount of .
waste heat that must be dissipated from the process.
Perhaps the major source of contaminants emitted to the air is
the utilities system which includes steam generation, power .generation,
cooling water, treating of make-up water and waste water, as well as
miscellaneous items such as utility air and instrument air supplies. Coal
is used as fuel in the boiler and steam superheater.; It has a high sulfur
content corresponding to 5.64 Ib of S02 per MM Btu vs. an allowable
value of 1.2 for large stationary boilers. Consequently, control measures
such as flue gas clean-up will be needed. A sulfur removal of 807» would
be sufficient, and this level of desulfurization has been achieved or
exceeded by many of the processes offered for commercial use. In addition,
control of fly ash emission is required when burning coal. For this case
an ash removal of 98.167, is needed in order to meet the target of 0.1 Ib
of dust emission per MM Btu's. This level of removal has been obtained
with flue gas scrubbing.
Instead of burning coal, it would be possible to use part of .the
low sulfur, low Btu gas made in the process as fuel in order to limit
the .emissions of sulfur and dust. This would consume a sizeable part
of the total raw gas since the boiler fuel consumption corresponds to 16.47,
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- 25 -
of the gas production, while the steam superheater consumes an additional
3.4%. There is also a loss in efficiency, since gasification to make
low Btu gas has an estimated thermal efficiency of 77%, whereas flue
gas desulfurization is indicated to have a considerably higher efficiency (95%).
For any specific case, these alternatives need to be considered and evaluated,
including credits for the gas fuel route which may result from using a
combined cycle wherein the gas is first burned in a flue gas turbine to
generate power, and is then used in a furnace for steam generation.
Emissions of NO must also be defined and controlled in a speci-
fic application of the process. The amount will depend on the furnace
design, use of staged combustion, fuel nitrogen content, etc. In general,
NO production can be decreased by designing for a lower flame temperature
an? by using low nitrogen fuel. Low Btu fuel gas is attractive from these
standpoints. Processes are being developed to remove NO from flue gas,
and a satisfactory progress will probably be available soon.
The flow rate and composition of the flue gases from the boiler
for burning either coal or low Btu gas were compared in Table 4. Including
the steam superheater furnace, the volume of flue gas from the utilities
area is more than twice the volume of pipeline gas produced.
As is true for many other gasification processes, by far the
largest effluent to the air is from the utility cooling tower. Flow of
air through the cooling tower is 85,000 MM SCFD. In addition, there is
a drift loss due to mist carried out by the air. A typical estimate of
this would be about 263,000 Ib/hr, although it could be reduced considerably
by using some of the newer techniques that are being developed to control
drift loss from cooling towers (18). Drift can cause deposits in the
nearby area due to dissolved solids in the cooling water. Careful consideration
should also be given to the potential fog problem or plume associated
with cooling towers due to condensation under unfavorable atmospheric
conditions. One way to avoid the plume is to provide reheat on the air
leaving the cooling tower, but this will not normally be warranted. It
may be that these problems can be taken care of by proper design and
placement of the cooling tower.
Normally, there will not be contaminants introduced into the
cooling water circuit that might be stripped out by the air flowing through
the cooling tower. However, experience has shown that leaks can be expected
in exchangers used in cooling water service, especially at high pressures
such as the 1000 psig in this process. Leaks, for example, in exchangers
on sour water service could introduce sulfur, cyanide and ammonia into
the cooling water, which would then be stripped out into the air. Special
precautions and possibly monitoring equipment may be needed from this
standpoint.
The volume of air passing through the cooling tower is so large
that every precaution should be taken to see that it does not inadvertently
become contaminated. For this design, the air flow is about 85,000 MM CFD,
or roughly 340 times the volume of pipeline gas produced, and is by far
the largest gas stream released to the environment.
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- 26 -
6. EFFLUENTS - LIQUIDS AND SOLIDS
Emissions to the environment of liquid and solid effluents will
be discussed in the order in which they appear on the flow plan of Figure 1.
Individual streams are identified on Figure 2 and described in Table 3.
6.1 Coal Preparation
A first and major effluent is the refuse from coal preparation
and cleaning. This includes the rock and gangue delivered with the run
of mine coal. Such refuse is separated and rejected after the first breaker,
which crushes run of mine coal. Additional refuse is separated in the
washing operation. These streams amount to 4,804 and 3,904 tpd respectively
and will contain some coal as well as pyritic sulfur. They are therefore
subject to oxidation and leaching, can cause pollution problems similar
to acid mine water, and should be reviewed and considered from this standpoint
(28).
The refuse might be returned to the mine or used as land fill
provided the potential problems of secondary pollution are evaluated and
controlled. The enormous magnitude of this effluent stream is illustrated
by the fact that it amounts to over 860 acre feet per year of refuse to
be disposed of. It is obvious that very careful and thorough planning
will be necessary to avoid unexpected problems due to pollution from leaching
of acid or soluble compounds and metals, or from dust.
In the washing operation, wash water will be sent to a settling
pond where fines will be removed so that the water can be reused. Disposal
of.these fines, or tailings, must be provided for. Handling of the fines
will call for special precautions, since if they are spilled on the ground
they can dry out and then become dispersed by the wind or by trucks using
the area. The system should be designed for complete recycle of the
wash water so that there is no water effluent from the operation, which
would present a difficult clean-up problem from the standpoint of dissolved
and suspended materials.
Leaching, or seepage, through the bottom of the tailing pond
should also be controlled. In a heavy clay-type soil this may not be
a problem; however, in sandy soil it may be necessary to provide a barrier
which might be a layer of plastic or clay.
A further consideration on the coal preparation area is with
regard to the coal storage pile. The design includes 30 days' storage,
or about 700,000 tons; so the coal storage pile will cover a very large
area. Rain runoff can lead to undesirable effluents. A large part
of the rain can run off quickly and carry suspended particles, while
the remainder will have a long contact time with the coal and can pick
up acids and organics. Therefore, rain runoff from the storage area
should be collected in storm sewers and sent to a separate storm pond.
With a certain amount of treatment, this water can then be used as make-
up for the process. Control of seepage may be desirable on the pond,
. and particularly on the coal storage area, using for example, a layer
of concrete, plastic or clay.
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- 27 -
Other effluents from the coal preparation area are associated
with coal drying. Coal fines that are picked up by the drying gas should
be.recovered by bag filters, or scrubbers and returned to the process.
In addition, where coal is used as fuel on the dryer there will be by-
product ash to be recovered and disposed of. It might be included along
with the refuse from coal cleaning, or it could be combined with the
slag from gasification and disposed of as land fill.
6.2 Gasification
Coal feed is reacted with steam and oxygen at high temperature
and about 80 atmospheres pressure in the gasifier. The major effluent.
from this section is the slag formed from ash in the coal. Essentially,
all of,the ash in the feed is rejected here, after having been fused in
the lower zone of the gasifier which operates at 3000°F. Molten slag
is quenched in water and thereby shattered to form a slurry which is
then depressured using lock hoppers for removal from the high pressure
system. The slag should be relatively sulfur free and unreactive, having been
fused at high temperature. Also, it contains little or no carbon and
therefore can be discarded. For handling, it can be mixed with an equal
weight of water to form a slurry. This water will pick up dust from the
slag, and can leach out soluble salts and metals; therefore, it should
be collected and reused so as not to become an effluent from the plant.
The ash slurry might be dewatered for disposal in the mine and the water
sent to a holding pond for reuse.
Production of dry slag is 68,391 Ib/hr, corresponding to about
90 acre-ft. per year; consequentlyAdequate provision for disposal is needed.
The other major stream leaving the gasifier is the raw gas product. It
contains a large amount of char which is blown out of the gasifier and
recovered in cyclones for recycling to the lower zone of the gasifier.
No other streams are normally released to the environment from the
gasification section.
6.3 Quench and Dust Removal
A large part of the coal feed to the gasifier is blown overhead
since the reactor operates at high velocity and with high entrainment.
This char is separated in a cyclone where quench water is introduced.
The recovered char goes to lock hoppers and a feeder which returns it to
the lower zone of the gasifier. Except for leaks and maintenance, there
should be no emissions fromi these facilities.
The raw gas is further quenched with sour water in a quench
vessel ahead of the sand bed filters. These filters operate in parallel,
and when the pressure drop builds up, one unit is cleaned by back blowing.
Dusty gas from the backblowlng operation is returned to the gasifier. The
cleaned sand filter is then placed back in service.
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An important feature of the sand bed filters is that they provide
dust removal at high temperature, such that water does not have to be
condensed. This is a major advantage when using a sulfur resistant shift
catalyst so that shift conversion is carried out before the raw gas has
been cooled and the moisture condensed out. Thus, the steam required for
shift conversion is provided partly by residual steam leaving the gasifier,
together with sour water which is introduced as quench. This arrangement
provides a convenient and effective way to dispose of sour water.
Ash removed by the sand filters will be returned to the lower
gasification zone and can leave with the slag. However, there will be
some volatile components, such as arsenic and zinc compounds etc., that
will be revaporized and carried up with the gas. They can then condense
again and be caught by the sand bed filters. It will be seen that this
constitutes a system with total recycle, with no way for certain materials
to escape. Therefore, it may be necessary to provide a purge stream in
order to remove such materials. For example, part of the dust recovered
by the sand bed filters could be removed for disposal. The composition
and nature of this stream"cannot be estimated at this time, neither can
the amount be predicted. The required information should be obtained during
operation of the pilot facilities.
Similarly,, it may be necessary to provide a purge stream, or
separation system, on the sour water if certain chemical compounds or
trace elements tend to recycle and build up in concentration.
6.4 Shift Conversion
.. .As pointed out, shift conversion is carried out before sulfur
has been removed from the raw gas. Therefore, a sulfur resistant shift
catalyst is required, and these normally have lower activity than catalysts
which are used on sulfur free gas. Steam in the entering gas is adjusted
to give about one mole per mole of dry gas. Steam conversion in the shift
reactor is about 27%, while 62% of the CO entering is reacted.
After shifting, the gas is cooled to condense out most of the
remaining moisture, which gives 866,613 Ib/hr of sour condensate. This water
will, contain l^S and other sulfur compounds as well as ammonia and probably
traces of phenols, cyanides, etc. that are present in the gas. This
sour water can all be disposed of by recycling to the process to provide
part of the quench required at the outlet of the gasifier.
In this particular BI-GAS design, the amount of water consumed
in the shift reaction is 385,630 pounds per hour so that this much unreacted
water in the gases leaving the gasifier could be disposed of without having
a net production of sour water from the process. In addition there is
68,270 pounds per hour of water used for quenching the slag, and perhaps
this could be an additional consumption of sour water.
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It should" be pointed out that compounds such as ammonia and
phenol will dissolve in the sour water and be recycled through the quench.
Of course, quenching does, not actually destroy these materials, although
they might be'destroyed in the shift reactor, -and this is a distinct
possibility which would be worthwhile to explore. If they cannot be
destroyed then -it will be necessary to provide a purge stream, which is
further processed to separate compounds that build up in the recycle
stream. For example, ammonia and phenol could be separated and taken .
off as by-products for sale or for incineration. Trace elements that
are volatilized in the gasifier, such as arsenic, boron, lead, etc., may
also tend to build-up in the.' circulating, sour water stream and have to
be removed and disposed of. This subject is discussed further in
Section1 10'- TRACE ELEMENTS.
One possible modification is to provide stripping on a portion
of the recycle sour water stream so as to remove volatile materials -such .
as ammonia. In the case of less volatile soluble materials such as phenols,
these will tend to build up and it may be necessary to add an extraction
step to separate them and remove them from the system. It is possible
that contaminants may be destroyed in the shift conversion reactor by
hydrogenation as a result of the large amount of hydrogen present. Further
exploration of this possibility would be desirable. Oxygenated compounds
might -also be destroyed, and perhaps the rate of the ammonia equilibration
reaction would be sufficient to control the concentration of ammonia to
an acceptable level. 'On the other hand, such recycling might undesirably
increase 'the concentration of some materials such as cyanides and thiocyanates.
Obviously, more information is required to define the situation.
While this particular design of the BI-GAS process does not show
liquid or solid effluents or by-products from this section of the plant,
further clarification and information is needed from pilot plant operations
regarding contaminants such as ammonia, cyanides, phenols, etc., that may
be formed in gasification and tend to concentrate in the recirculated
sour water. They will either have-to-be destroyed in the recycling
operation or removed from the system by using appropriate separation
technique's. Ammonia is of particular -concern since in many gasification
processes about 607, of the nitrogen in the coal is converted to ammonia.
It is relatively easy to separate and remove as a valuable by-product, and
for this design the production of ammonia could be of the order of 100
tons/day.
Other trace materials may be much more difficult to separate
and dispose-"of. For example, it is known that many trace elements will
volatilize to a considerable extent during gasification. Such, elements
include mercury, arsenic, antimony, cadmium, zinc, fluorine, boron etc.
and many of these can be quite toxic. To some extent, they may be removed
by the sand filters and thereby returned to the gasifier. However, it
is unlikely that they will leave with the molten slag, and therefore
may recycle between the gasifier and sand filters and build up in concentration.
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If this happens, perhaps they could be removed by purging some of the
dust recovered on the sand filters to a separate metal recovery system.
It is also likely that some of these metals will pass through the sand
filters and show up in the sour water stream. Since this is also recycled
completely, there is no place for such metals to leave the system;
consequently*they will build-up in concentration in the recycled sour
water stream. Again, it may be that part of this stream could be
processed to separate and recover such materials.
In any event, it is apparent that provisions will have to be
made for removing from the system materials such as trace elements that
are volatilized in the gasifier. It is most important to obtain the
additional information needed in this area to define the problem and
proper controls. The amount and nature of the trace elements leaving
the gasifier 'should be carefully determined during pilot plant operation,
so that environmental aspects can then be properly evaluated. This is
one area where additional information is urgently needed.
6.5 Acid Gas Removal
The acid gas removal system is intended to remove sulfur compounds
as well as CC^, prior to methanation. Amine scrubbing is commonly used
for this purpose but is not effective on removing forms of sulfur other
than H-S, such as COS and CS2 which may be present. Other techniques
may use hot potassium carbonate scrubbing or absorption with refrigerated
methanol both of which are effective for removing carbonyl sulfide.
Another route is to use absorption/oxidation systems where the HoS is
reacted directly to free sulfur, which is then separated as a by-product.
This type of system is offered by Stretford, Takahax, IFF and others,
but may not give adequate removal of COS,etc. Of course, a separate system
is then needed for C02 removal.
This particular BI-GAS design uses the Benfield hot carbonate
system to provide two separate gas streams. One of these is relatively
high in H2S content for processing in the sulfur pliant, while the other
is a C02 stream relatively low in sulfur to be vented. There are no
major liquid or solid effluents from this operation; however, it is necessary
to purge a small amount of the scrubbing solution since certain contaminants
build-up and interfere with the operation. The amount and composition of
this purge have not been given, but it probably contains an appreciable
amount of potassium carbonate, and might be disposed of by neutralizing
it with sulfuric acid that is used in the water treating system for
regenerating ion exchange residence. It might also be processed for
recovery. Some suitable disposal needs to be defined.
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One complication that occurs in all processes where coal.is
gasified with oxygen results from the formation of carbonyl sulfide in
the gasifier. it generally results in complications and limits the
choice of processes for acid gas removal, since carbonyl sulfide is not
removed adequately by conventional amine scrubbing. An interesting
possibility is to react COS with steam over a catalyst at moderate
temperatures so as to convert it to H2S, which can readily be removed.
It has been shown that catalysts such as alumina will promote this
reaction (19) . Possibly, COS conversion could also be carried out in
the shift reactor or in a separate bed of suitable catalyst.
The scrubbing towers of the acid gas removal system will no
doubt be very effective for removing trace amounts of dust or other
materials which have not been separated by the upstream -processing.
Such materials will also accumulate in the scrubbing solution and may '
have to be separated and purged. In some other processing schemes, filtering
of the scrubbing solution has been included to separate solid particles
which are then rejected from the system. Depending on the nature of
such materials they might be disposed of along with the slag from gasification
or possibly processed for recovery.
Again, it should be pointed out that certain trace elements
will be volatile to some extent in the gasifier and will be carried out
in the raw gas. These must show up in the downstream processing, where
they will be separated out. The amounts can be very significant. For
example, a concentration of only 10 parts per million in the entering
coal corresponds to a total of 240 Ib/day, a large part of which may
volatilize in the gasifier. Since there are a large number of elements
to consider, the total amounts to be disposed of can be very formidable,
particularly if they are toxic,- as is the case for many volatile elements.
Information is needed on where they will appear, and in what form, so
that the situation can be evaluated and proper control measures included
as required.
606 Methanation and Drying
Following acid gas removal}the gas is quite clean and should not
contain significant amounts of undesirable contaminants. Methanation
produces 214,818 Ib/hr of water, which is condensed and is suitable for boiler
feed water make-up. The large heat release in the methanation reaction is
used to generate high pressure steam, but this is used within the process
and is not an effluent from the plant., Finally, the gas is dried with glycol
to meet pipeline specifications. Water removed at this point is 27,219 Ib/hr
and,again, should be suitable for make-up water if it is recovered. There
may also be a small amount of purge from the system containing glycol,
which could be incinerated or passed through the biox system for clean-up.
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6.7 Auxiliary Facilities
As previously discussed, there will be solid effluents from the
furnaces burning coal for utilities production. Residual ash can be
disposed of together with the, slag from gasification. In addition, there
is spent limestone from flue gas desulfurization which can be similarly
handled and also sludge from water treating. Sludge from biological
oxidation should be incinerated to avoid,odor problems.
Some water must be purged from the cooling water system in order
to control concentration of dissolved solids. This represents the minimum
net discharge of water from the plant. While there will also be blowdown
from boilers, it can be used as cooling tower, makeup, and the sour water
will be cleaned up for reuse. Water discharged from the plant will contain
sodium chloride, sulfates, and other dissolved solids. The amount, com-
position, and disposition need to be carefully defined and evaluated in
any large scale application.
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7. GAS HANDLING AND SOUR WATER CONSIDERATIONS
There are a number of possible ways, which can be used to clean-up
the raw gas leaving the gasifier so that it can be methanated to high
Btu pipeline gas. The choice can have a very large effect on effluents
and 'particularly on the production of sour water and the disposal of it.
To a large extent, the choice is a matter of selecting the order in which
the processing steps are carried out, and some of the routes are as follows:
(1) The hot gas goes first to shift conversion using
a sulfur resistant catalyst, followed by acid ,gas
removal and methanation.
(2) The raw gas is cooled and scrubbed for acid gas
removal, and then goes to shift, C02 removal, and
methanation.
(3) The gas is desulfurized at high temperature such as
700°F instead of using amine or hot carbonate scrubbing,
and is then methanated directly with steam, followed by
C02 removal.
The first of these is the route usually planned in making SNG by coal gasi-
fication. It requires gas clean-up ahead of the shift reactor in order to remove
materials that might foul the shift catalyst, particularly dust and tar.
Catalyst activity is relatively low due to the presence of sulfur and a
large excess of steam is generally needed to control deposits on the catalysts.
The second type of system is more typical of operation to manufacture
high purity hydrogen, where the shift reaction must be maximized. An
active shift catalyst can be used since it is not exposed to sulfur. However,
if this route is used in making SNG, the gas must be cooled after shifting
in order to scrub out C02 before methanation. This introduces an extra
heating and cooling step which is inefficient. Thus, the entire gas
stream is cooled three times compared to twice in the first case.
The third approach is a new proposal for gas processing which
should be simpler and more efficient, although it requires development
of technology. With this combination the gas is only cooled once, and
that is after the final methanation. The gas is first desulfurized at
high temperature using a process such as that studied by the Bureau of
Mines based on the reaction of iron with sulfur (30), or that studied by
CONSOL based on half-calcined dolomite. Next, the. CO is methanated di-
rectly by .reaction with steam rather than with hydrogen. It should be
possible to react CO .with steam to form methane and CO,-,, since this type
of reaction Is^carried out in a number of processes making .SNG from
naphtha by reacting It with steam to form methane and C0« (31,32,33).
It would also be possible to use conventional shifting and
methanation in two separate stages, but it is more efficient to react the
CO to methane directly since it requires less steam. In other words, it
combines the steam consumption of the shift reaction together with the
steam formation in methanation, whereby the actual steam requirement is
reduced.
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With this route it will be necessary to remove sulfur, dust and
tar at high temperature ahead of methanation. As mentioned, sulfur might
be removed in a bed of iron type adsorbent, which might also remove dust,
or the dust could be removed in sand bed filters. Tar could be removed
by scrubbing, for example, at 500-600°F. While the projected methanation
reaction has been used effectively on naphthas, it will probably be more.
difficult to'obtain the desired conversion on heavier oils or .on aromatic
type compounds. Therefore, the system may be best suited for those
gasification processes that do not make tar or naphtha.
An advantage for removing C02 after methanation is; that there
is less volume of gas and the concentration of CC>2 is higher. Of course,
the total amount of C02 to be removed is the same as in the other
routes.
It should be pointed out that compounds such as phenol and
ammonia in the raw gas can pass through the system and; may not be removed
until the final cooling step. In addition, the effect of volatile trace
metals must be considered. It is not clear whether these would be removed
along with the dust or whether they might deposit on the catalyst and
affect its activity.
The potential savings and simplification possible with this
modified system.for gas cleaning would seem to provide considerable
incentive to develop suitable techniques for removing sulfur and dust'
at high temperatures. Techniques are known for removing small amounts
of sulfur at high temperature, for example, using iron, zinc oxide, or
nickel base materials. The problem has been that these cannot be
conveniently regenerated, and therefore are not practical for removing
large amounts of sulfur. It should be possible to develop practical
regeneration techniques, so that the sulfur adsorbent could be recirculated
and used continuously or batch wise.
Dolomite may also be a promising prospect for such a system
based on background available from the CC>2 Acceptor process development (4).
This work has shown that dolomite will remove sulfur compound from gases
at high temperature. It has also been shown that the spent material
can be desulfurized and regenerated by reacting with CC>2 in a water slurry
at 190°F to produce a stream of t^S which is available at a reasonably high
concentration so that it can be processed efficiently in a conventional
Claus plant.
If techniques were developed for removing dust -and sulfur at
high temperature, then they would also.be useful for making clean,low
Btu fuel gas from coal. For example, coal could be gasified with air
or oxygen, and after clean-up used in process furnaces or utility.boilers,
which would then not require individual stack gas clean-up. The system
should have a higher thermal efficiency than conventional systems to -'make
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low Btu gas in that little or no sensible heat in the hot gas from
gasification would be wasted. A further very important advantage is
that the clean fuel gas could be used in a .combined cycle for power
generation. That is, the low Btu gas would first be used in a gas
turbine generating electric power, and it would then go to a furnace
for final combustion and steam generation.
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8. SULFUR BALANCE
Details on the amount of sulfur in the various streams entering
and leaving the plant are shown in Table 5. Essentially all of the sul-
fur emission from the plant is to the air, and most of this is in the
flue gas discharged from the steam boiler and super heater. Of the sul-
fur entering the plant in the coal feed, 83.4% is recovered as by-product
sulfur from the sulfur plant. An additional 12.4% of the sulfur is re-
moved and rejected by the flue gas desulfurization facilities on the
utilities furnaces and coal dryer. A number of processes are offered
for stack gas cleanup, and many of these can give a sulfur removal well
above the 79% target, at little or no added cost.
Streams such as the waste water discharge and the CO vent gas
will be cleaned up to avoid odor problems, and will then contain negligible
amounts of sulfur. Thus, the raw C0~ stream from acid gas removal contains
3400 ppm H?S which is removed by molecular sieve adsorption and sent to
the sulfur plant. Similarly, the slag is assumed to be free of sulfur
and not a contributor to pollution. These items should be examined care-
fully in a final plant design. While the gas liquor contains considerable
H_S, most of this will be removed in the sour water stripper and sent to
tRe sulfur plant. The biox unit provides final cleanup on the effluent
water.
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Table 5
Sulfur Balance (1)
Sulfur Input in Coal (1) Ib/hr %
To gasifier 35,487 84,2
To coal dryer 418 1.0
To utility steam boiler 5,164 12.2
To steam superheater 1,Q86 2.6
TOTAL IN 42,155 100.0
Sulfur Output (1)
From Glaus plant (2) 35,132 83.4
In Glaus tail gas (2) 355 0.8
In pipeline gas product nil
In treated sour vater nil
In CC>2 vent gas nil
In slag nil
From flue gas desulfurization coal dryer (3) 330 0.8
From flue gas desulfurization boiler (3) 4,080 9.6
From flue gas desulfurization superheater (3) 858 2.0
In flue gas on coal dryer (3) 88 0.2
In flue gas on boiler (3) 1,084 2.6
In flue gas on superheater (3) 228 0.6
TOTAL OUT 42,155 100.0
NOTES:
(1) Does not include refuse from coal cleaning operations which
could be sizable and needs to be defined.
(2) Basis: 99% S recovery including tail gas clean-up.
(3) Based on flue gas desulfurization with 79% S removal.
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9. THERMAL EFFICIENCY
The base thermal efficiency for the process is obtained by
comparing the heating value of the net pipeline gas produced, with that
for the total coal used including gasification and all utilities production.
As shown in Table 6, the base efficiency is 65.9%. Coal is used as fuel
in the coal drier and the utilities systems, requiring flue gas clean-up;
but, the fuel required for this is not included in the above number. How-
ever, it is estimated that this will increase the fuel requirements by
less than 5% on the individual furnaces, and less than 1% on the total
coal delivered to the plant. Base efficiency with this allowance will then
be about 65.3%
An alternative would be to use low sulfur low Btu gas made in
the process as fuel to the furnaces. Pollution due to sulfur and ash would
then be avoided, but it would still be necessary to provide good dust removal
on the coal dryer. Obviously, such use of gas fuel will appreciably reduce
the amount of gas available to the pipeline, and correspondingly decrease
thermal efficiency of the process, as illustrated below:
Fuel used in;
Coal dryer coal gas gas gas
Steam superheater coal coal gas gas
Utility boiler coal coal coal gas
MM Btu/hr in:
Coal consumed 14,920 14,775 14,390 12,560
Low Btu gas 11,191 11,046 10,661 8,831
Pipeline gas 9,830 9,703 9,365 7,757
Thermal Efficiency % 65.3 65.1 64.6 61.8
Using all gas fuel instead of coal decreases thermal efficiency from 65.3%
to 61.8%. At the same time, production of pipeline gas is reduced by 217=,
for a given size of gasifier.
These results again emphasize the desirability of applying an efficient
flue gas clean-up operation, so as to allow using high sulfur coal as
fuel.
It is also of interest to look at the thermal efficiency for this
specific design as a way to make low sulfur, low Btu gas. Heating value in
the gases prior to methanation corresponds to about 74% thermal efficiency
for the gasification step, including an allowance for flue gas clean-up.
Of the total heating value in the low Btu gas, 41.67» is contributed by its
methane content.
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In considering thermal efficiency of the process as a source of
clean low Btu fuel gas, it is proper to exclude the shift conversion
operation since it is not needed. Then the quenching can be omitted and
replaced with a more efficient heat exchanger to generate high pressure
steam, thereby decreasing the size of the utility steam boiler. This
reduces the total coal consumption and adds another 37, to the thermal
efficiency,, bringing it up to 77% for making clean fuel gas.
Thermal efficiencies for the various alternatives considered
In the BI-GAS process are summarized in Table 6.
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Table 6
Thermal Efficiencies for BI-GAS Process
Base Coal * Consumption
Gasifier
Coal dryer
Steam Superheater
Utility boiler
Ib/hr
1,018,700
12,000
31,200
148.400
1,210,300
Base Case Thermal efficiency
Without flue gas desulfurization
With flue gas desulfurization
With low Btu gas fuel to;
Coal dryer
and steam superheater
and utility boiler
Alternative to make only low Btu gas
Base case design
Without shift conversion
MM Btu/hr
12,560
145
385
1,830
14,920
Efficiency
65.9
65.3
65.1
64.6
61.8
74.0
77.0
* Based on 8.4% moisture
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10o TRACE ELEMENTS
Coal contains many trace elements present in less than 1%
concentration that need to be carefully considered from the standpoint
of potential impact on the environment. Many of these may volatilize
to a small or large extent during processing and many of the volatile
components can be highly toxic. This is especially true for mercurv,
selenium, arsenic, molybdenum, lead, cadmium, beryllium and fluorine. The
fate of trace elements in coal conversion operations, such as gasification
or liquefaction, can be very different than experienced in conventional
coal fired furnaces. One reason is that the conversion operations take
place in a reducing atmosphere, whereas in combustion the conditions are
always oxidizing. This maintains the trace elements in an oxidized condition
such that they may have more tendency to combine or dissolve in the major
ash components such as silica and alumina. On the other hand,the reducing
atmosphere present in coal conversion may form compounds such as hydrides,
carbonyls or sulfides which may be more volatile. Studies on coal fired
furnaces have indicated that smaller particles in fly ash contain a higher
concentration of trace elements, presumably due to volatilization of
these elements in the combustion zone and their subsequent condensation and
collection on the fly ash particles (20). Other studies on coal fired
furnaces are pertinent (21,22,23) and some of these report mass balances
on trace elements around the furnaces (24).
Considerable information is available on the analyses of coal,
including trace constituentSj and these data have been assembled and evaluated
(25,26). A few studies have been made to determine what happens to various
trace elements during gasification (2,27). As expected these show a very
appreciable amount of volatilization on certain elements. As an order of
magnitude, using the factors for this specific BI-GAS design would result
in 240 Ib/day carried out by the gas for each 10 ppm of trace element
volatilized from the coal.
In order to make the picture on trace metals more meaningful9
the approximate degree of volatilization shown for various elements has
been combined with their corresponding concentration in a hypothetical
coal (as typical), giving an estimate of the pounds per day of each element
that might be carried out with the hot gases leaving the gasifier. Results
are shown in Table 7 in the order of decreasing volatility. Looking at the
estimated amounts that may be carried overhead, it becomes immediately
apparent that there can be a very real problem. For each element the net
amount carried overhead must be collected, removed from the system, and
dispose of in an acceptable manner. In the case of zincs boron and fluo-
rine the degree of volatilization has not yet been determined, but they
would be expected to be rather volatile. Even if only 10% of the total
amount is volatile, there till be large quantities to remove in the gas
cleaning operation and to dispose of.
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Table 7
Example of Trace Elements That May Appear in Gas Cleaning Section
Possible % Volatile In Gas
Element ppm in Coal (a) for example (b) lb/day(c)
Cl 1500 >90+ 32,400
Hg Oo2 90+ 5
Se 2.2 74 39
As 31 65
Pb 7.7 63
Cd 0=14 62 2
Sb Ool5 33 i
V 35 30 252
Ni 14 24 81
Be 2 18 9
Zn 44 (10) 106
B 165 (10) 396
F 85 (10) 204
Ti 340 (10) 816
Cr 22 nil nil
(a) Mainly based on Pittsburgh Seam Coal (2)=
(b) Mainly based on lower temp gasifier (27) and indicated at
10% for Zn, B, and F? in absence of data.
(c) For 12,000 tons/day of coal feed
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A complication results in the gas clean-up section due to the
presence of volatile trace elements. In the BI-GAS design, raw gas from the
gasifier is cooled and cleaned to remove all dust and other contaminants
except for the more volatile ones such as H2S. Contaminants collect in
the dust and sour water both of which are returned to the system and presumably
recycled to extinction. Chemical compounds such as cyanide taay thereby
be destroyed but this cannot be the case for trace elements. It will be
difficult for volatile elements to leave with the slag through the 3000°F
zone, they will therefore build up in the recirculating streams and have
to be purged from the system.
The preceding discussion has been directed primarily at trace
elements that are partially volatilized during gasification and that
therefore must be recovered and disposed of in the gas cleaning section.
Consideration must also be given to trace metals that are not volatilized
and leave in the solid effluents from the plant, one of which is the slag
from gasification. Undesirable elements might be leached out of this
slag since it is handled as a water slurry and will ultimately be exposed
to leaching by ground water when it is disposed of as land fill or to the
mine. Sufficient information is not now available to evaluate the potential
problems and the situation may be quite different from the slag rejected
from coal fired furnaces since the slag is produced in a reducing atmosphere
rather than an oxidizing one. Background information on slag from blast
furnaces used in the steel industry may be pertinent from this standpoint,
since the blast furnace operates with a reducing atmosphere. However, a
large amount of limestone is also added to the blast furnace, consequently
the nature of the slag will be different.
An additional source of possible contamination from trace elements
is associated with the disposal of refuse from coal cleaning. It is known
that contained sulfur compounds will oxidize upon exposure to the air and
form an acid solution in the presence of water. It is quite likely that
a number of trace elements can be extracted from the refuse by this acid
solution. For example, similar systems have been proposed and studied
for recovering copper, nickel, iron, etc. from low grade ores. It might
be thought that this situation is no worse than that existing for natural
mineral deposits; however, the conditions are quite different. First,
the mineral has been crushed and reduced in size so that vastly more
surface is exposed and available for extraction. In addition, the mineral
is exposed to a large amount of oxygen, which together with the large
surface area can cause considerable oxidation of sulfur compounds, organic
materials, and minerals in the refuse, whereas natural mineral deposits are
not subject to such conditions. Some studies have been made in this general
area (28,29),but much more work is needed.
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11. ALTERNATIVES TO CONSIDER
This section of the report covers various modifications to the base
design that warrant further consideration and evaluation. Some of these are
added as required to control pollution. Other alternatives are discussed
that may improve thermal efficiency of the process, some of which will require
additional experimental work or development of new technology. Table 8
summarizes a number of items. The first modification to consider is the
addition of facilities to control sulfur emission on furnaces firing high
sulfur coal as fuel.
In the base design, high sulfur coal is used for fuel on the coal
dryer and in the utilities furnaces. Flue gas clean-up is therefore needed
on each of these, and a large number of processes are offered commercially
for this purpose (10,13,34,35). Some of these use scrubbing with lime, lime-
stone, magnesia, or sodium carbonate solutions. In the case of limestone,
the spent material is discarded, whereas in most other processes the scrubbing
medium is regenerated to produce a by product sulfur compound such as
sulfur, sulfuric acid, or gypsum. Those processes that use scrubbing will
also remove particulates, as is required when burning coal as fuel.
Instead of using coal with flue gas clean-up, it would be possible
to use part of the clean, low Btu gas produced in the process as fuel for the
furnaces. In evaluating this route, allowance should be made for the large
difference in thermal efficiency compared to burning coal directly. Some
energy is required to operate flue gas desulfurization, such that the thermal
efficiency corresponds to about 95%, whereas gasification to make low Btu
clean fuel gas has a thermal efficiency of about 75%. This specific BI-GAS
plant design used about 15.8% of the total coal feed for firing in the coal
dryer and in the utilities area. Therefore, the energy for flue gas
desulfurization will decrease overall plant thermal efficiency by about
0.6%, while the gasification route reduces it by about 3.0%.
In any event, the coal dryer will require dust recovery. Fortunately,
fuel consumption for coal drying is small relative to the utility furnaces,
so it is reasonable to use low Btu,clean gas as fuel on the coal dryer. One
advantage is that this avoids complications that may result if coal is used
as fuel, and the ash from this coal mixes with and contaminates the coal
fines picked up by the gas in the dryer.
A second modification to consider is on the system for recovering
and handling dust carried out by the raw gas leaving the gasifier. In the
base design a large amount of char is entrained from the reactor and separated
in a cyclone for return to the lower zone. Lock hoppers are used for
repressuring the recovered char, and since these require the use of mechanical
valves, the 1700°F raw gas and char are cooled to 1115°F by injecting quench
water into the cyclone. Recovered char is then injected into the lower
gasification zone which opesates at 3000°F. It would of course be more
efficient to return the char without cooling, but since mechanical valves
are used, some cooling is necessary. However, there is an alternative to
-------
- 45 -
Table 8
Alternatives to Consider
- Add stack gas clean-up to remove sulfur and dust on coal fired furnaces,
or use low Btu,clean gas fuel.
- Omit cooling on cyclone after gasifier and use standpipe to return
hot char to gasifier at 1700°F instead of 1115°F.
- Design coal dryer for coal fuel and low excess air (e.g. 107») with
vent gas recycle, to minimize fuel consumption and volume of vent gas
to dust removal.
Pressurize coal feed by pumping a water slurry, which is evaporated in
a fluid bed using indirect heating, to form steam which is used in
gasifier and shift converter, while at the same time preheating the
coal feed to 500-550°F.
Evaluate alternate of using light hydrocarbon instead of water
to make slurry. Hydrocarbon would then be condensed and reused.
- Remove excessive sulfur from C02 vent stream by using absorption/
oxidation process instead of molecular sieves.
- Instead of cooling to scrub out acid gases, remove sulfur at high
temperature and then react CO with steam catalytically to form
methane directly. Dolomite or iron system might be effective for
sulfur removal. Final step is then cooling and C02 removal from
smaller volume of gas.
- General efficiency items to conserve fuel:
- heat pumps on acid gas removal and sour water stripper
- air-fin exchangers to save cooling water
- air preheat on furnaces
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- 46 -
using lock hoppers which would not require cooling, in which the char
would be recovered in cyclones at 1700°F and flow down through vertical
standpipes to build up pressure on the fluidized char, as needed in order
to return it to the lower zone. This general technique is well established
for use in many fluidized solids operations, such as fluid catalytic
cracking in oil refineries. Returning the hot char without cooling significantly
reduces the heat load on the gasification zone, so that oxygen requirement is
decreased by about 15%. This also reduces the gas volume to be handled,
and the amount of C02 to be removed in the acid gas removal section.
Another modification that could improve efficiency of the process
and simplify the operation is in the method of pressurizing the coal
feed. It was originally proposed to use a piston feeder on the dry
coal powder, since this inherently has minimum power consumption. At the same
time it was suggested that lock hoppers could be used with pressure staging
to minimize the amount of vent gas that would have to be collected and compressed.
Lock hoppers ©re used commercially but are expensive, and the cyclic operation
of valves requires considerable maintenance.
It has also been proposed to mix the coal with a liquid to form a
slurry which then can be pumped into the high pressure system where the liquid
is evaporated. The liquid may be water in an amount approximately equal to
the weight of coal so that the slurry can be handled and pumped. In some cases
a light hydrocarbon such as naphtha is used instead of water so as to reduce
the heat load, in which case the vapors can be condensed and reused. Latent
heat to evaporate naphtha is about 150 Btu per pound, compared to roughly 700
for water at high pressure.
This route is promising, especially with water, since large quantities
of steam are used in the gasifier and in shift conversion. The combined steam
consumption is about 1.7 million pounds per hour, and heat for generating this
steam must come either from waste heat or from furnaces. The quantity of
steam is large relative to the coal feed rate of slightly less than 1,000,000
pounds per hour, and would be sufficient to form a pumpable slurry for feeding.
If the coal feed were slurried with an equal weight of water and pumped to about
1100 psig, then it could be evaporated by indirect heat exchange with the hot;
raw gas available at 1700'F from the gasifier, after the char has been separated
by means of a cyclone as previously described. Latent heat to evaporate the
water amounts to about 600 million Btu per hour, which could be provided by
sensible heat of the raw gas if it were cooled from 1700 to 900°F. It is
therefore of interest to consider flowing the hot gas through a heat exchanger
which would transfer heat to the coal slurry in order to evaporate it to dry-
ness. The operating temperature would be about 550°F. and past work has shown
that coal can be preheated to this temperature without evolving a large amount
of volatiles or becoming plastic and sticky.
It may not be practical to carry out such an operation in a conven-
tional tubular exchanger because of local overheating or plugging, but one
possibility is to use a fluid bed in which there are heat transfer tubes, as
proposed for fluid bed boilers. Such an approach is illustrated in Figure 3.
A \sater slurry is injected into the fluidised bed where it is evap-
orated to dryness. Similar systems have been used successfully on small commercial
-------
Figure 3
POSSIBLE SYSTEM FOR PUMPING COAL TO HIGH PRESSURE, USING SLURRY
COAL FEED
HOPPER
946,307
WATER
(Can be sour water)
946,307
200°F
SLURRY MIXING
TANK
PUMP
(To 1100 psig,
2300 theo. HP<0
STEAM TO GASIFIER AND
SHIFT CONVERSION
^ 946,307
HEATING COILS,
1050 MM Btu/hr
(e.g. Dowthertn, or hot raw gas
from gasifier) i
PREHEATED COAL TO GASIFIER
946,307
Numbers are flow rate, Ib/hr.
-------
- 48 -
units to evaporate various slurries. Heat is supplied indirectly by exchanger
coils submerged in the bed, which are found to provide excellent heat transfer
without fouling. Hot gases from the gasifier could flow through the coils to
supply necessary heat. Instead of this arrangement, heat could be supplied
from a furnace using for example Dowtherm or liquid metal to assure good heat
transfer and temperature control.
Steam from evaporation of the slurry can be fed to the upper and
lower zones of the gasifier as desired. Part of the steam can also be used
in the shift converter., Although the steam will contain some solid particles,
this should not matter. Dry coal is withdrawn from the bed and fed to the
gasifier, for example, using a standpipe or screw feeder arrangement.
It will be noted that the coal is preheated to 550°F in this system. Its
sensible heat content is thereby increased by about 150 million Btus per
hour, giving a corresponding saving in the overall heat load on the
gasifiero
The base design uses hot carbonate scrubbing for acid gas removal
and it has the advantage that it will remove carbonyl sulfide whereas amine
scrubbing is not effective. Of the total sulfur in the raw gas some 10% of
it may be present in forms other than H S, such as carbonyl sulfide, conse-
quently these other forms of sulfur must also be removed in order to give
satisfactory cleanup. This particular hot carbonate system makes a vent stream
of CO, which is excessively high in sulfur content and needs to be cleaned up.
Therefore we have added a molecular sieve unit to remove H S from this
CO, stream and sent it to the sulfur plant for recovery. Further con-
sideration should be given to catalytic hydrolysis of carbonyl sulfide
to form H.S. This would be used prior to acid gas removal, and might be
combined with the shift operation as suggested by Bituminous Coal Re-
search (36) .
Acid gas removal is a large consumer of utilities, equivalent to
about 10% on overall thermal efficiency. It therefore warrants thorough
consideration of alternatives in order to arrive at an optimum system. In
this connection, the desirability of hydrolysing carbonyl sulfide prior to
acid gas removal should be emphasized. If this can be done it allows a much
wider choice of processes for acid gas removal, including conventional amine
scrubbing as well as adsorption/oxidation type systems such as Stretford,
Takahax, or IFF.
The adsorption/oxidation system could also be used for cleaning up
the C02 vent stream, since it will remove HjS without removing C02. Other
methods may be cheaper or simpler, such as scrubbing with limestone slurry.
This would pickup sulfur and have to be disposed of in a suitable manner.
One possibility is to return it to the gasification zone* If flue gas
desulfurisation is used on furnaces in the plant, it is quite possible that
the CO, vent stream could be included along with the flue gas for processing.
As deacribed more fully in the section on Gas Handling and Sour
Water Considerations, there appears to be a large potential advantage for
developing practical techniques to remove sulfur at high temperature and avoid
the need for liquid scrubbing. The major potential advantage would be to
mathanate CO directly, without having to shift or cool the gas for acid gas
removal. It would also be necessary to remove dust at high tempereture9 but
this could be done with sand bed filters. Thus the gas might first be cooled
to about 600-900°F, $nd the dust removed. Then it would be desulfurized and
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- 49 -
sent through the methanation reactor, where the CO would be reacted with steam
and whatever hydrogen is present to form methane and C02° Finally the gas would
be cooled and scrubbed for CCL removal and dried to provide pipeline quality
gas. With this route the gas would never have to be reheated and cooled again,
as is necessary with the present conventional systems.
Efficiency of the process and fuel consumption might be improved
by reoptimizing a number of general items which are more or less conventional,
such as the use of heat pumps, air-fin exchangers, and increased air preheat
on furnaces (4,5).
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- 50 -
12o TECHNOLOGY NEEDS
From this review and examination of environmental aspects of the
BI-GAS process, a number of areas have been defined where further information
is needed in order to evaluate the situation, or where additional studies
or experimental work could lead to a significant improvement from the stand-
point of environmental controls, energy consumption, or thermal efficiency
of the processo Items of this nature will be discussed in this section of
the report, and a summary is shown in Table 9.
Any coal conversion operation has solid refuse to be disposed of. Coal
cleaning for the present design generates over 860 acre feet per year of refuse.
In addition, the production of slag from gasification is 820 tons per day or
another 10 acre ft/yr. More work is needed in order to define methods of
disposal that do not create problems due to leaching of acids, organics,
or sulfur which could contaminate natural water.. In addition, adequate
controls are needed with regard to the potential dust nuisance and washing
away of particulates. In many cases the material may be suitable for land
fill with revegetation. Although there is already a lot of background
on this subject, specific information is needed on each coal and for each
specific location in order to allow thorough planning to be sure that the
disposal will be environmentally sound.
Coal drying is used on most coal conversion processes; consequently,
considerable effort is warranted to optimize the operation from the standpoints
of-fuel consumption, dust recovery, and volume of vent gas to be handled.
It will often be attractive to burn high sulfur coal rather than clean gas
fuel, and to include facilities for cleaning up the vent gases.
The need for a simple ^efficient means of feeding coal to the high
pressure gasifier has been apparent and has received considerable study.
For pressure levels of 400=500 psig, lock hoppers have been used satisfactorily,
although they are expensive. For systems at 1,000 psig it may be attractive
to pump a water slurry of the coal in order to pressurize it, particularly
if it is possible to then evaporate the slurry at high pressure and thereby
supply steam to the process.
One item that is critical in the BI-GAS process is the need for
efficient removal of dust from gas at high temperature= In general, this
is required in any coal gasification system where the gas is shifted before
it is cooled and scrubbed. An important advantage is that particulates are
kept out of the sour water stream, and consequently it is easier to clean up.
Sand bed filters are promising for dust removal from hot gases, although they
have not been fully demonstrated commercially.
In the area of acid gas removal, systems based on amine or hot
carbonate are not completely satisfactory and leave room for improvement»
Amine scrubbing is not effective on carbonyl sulfide, while contaminants
such as cyanide interfere with regeneration of the scrubbing liquid.
Hot carbonate systems do remove carbonyl sulfide*, but it is often difficult
to provide a highly concentrated stream of H2S to send to the sulfur plant.
In addition the C02 stream vented to the atmosphere may contain too much
sulfur« Adsorption/oxidation systems are often not effective on carbonyl
-------
- 51 -
(
Table 9
Technology Needs
- Environmentally sound disposal of large amounts of refuse from coal
cleaning and washing, with regard to dust, leaching and sediment,
trace elements, land use, etc.
- An optimized design for coal drying to use low excess air and give maximum
allowable coal preheat, with good dust recovery.
An improved system to feed coal into high pressure zones, for example
using a piston feeder on water slurry. Slurry could be evaporated
in heated fluid bed to make steam for gasifier and preheat the coal
feed. Light hydrocarbon might be used instead of water, and condensed
for reuse.
A simpler and more efficient process for acid gas removal which would
provide an l^S stream of high concentration (e.g. 50 vol. 7») to the
sulfur plant, while giving a separate clean stream of CC>2 that can be
vented to the air. Desirable features to include:
good sulfur clean up, to a few ppm
- a clean CC>2 vent stream that does not require incineration
low utilities consumption
little or no chemical purges to dispose of
- An effective process to remove sulfur at high temperature could lead
to improvements, such as reacting CO directly with steam to form
methane.
-. Ways to handle COS, CS2, thiophene, etCc, that are usually present
and may not be removed by many acid gas removal processes. Hydrolysis
to H2S is probably one good approach.
Sour water cleanup. Most of it may be used for quenching, but some
purge will probably be needed to remove trace elements and perhaps
ammonia and phenols. There is a great need for a practical system
to evaporate sour water to make steam for use in the gasifier, and a
fluid bed system appears promising.
Information on trace elements and techniques for their disposal.
- Extent of volatility for specific process and coal.
- Where they appear in gas clean up system, and in what form.
They may collect on the char or sand bed filter and build up
by recycling. Others may appear on shift catalyst and in sour
water or acid gas removal.
- Many may be toxic and require separation and decontamination treatment
before disposal.
- Leaching may occur on the slag or on refuse from coal cleaning»
Information is needed to define the potential problem and to
devise environmentally sound disposal techniques.
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- 52 -
sulfide and in any event do not remove CC>2 as required, and therefore
additional processing is needed. The available systems for acid gas
removal have very high utility requirements, causing a significant loss
in thermal efficiency for conversion of coal to clean fuel products.
In addition there is often a waste stream of chemical scrubbing medium
which may be difficult and expensive to dispose of.
Desirable objectives for. an acid gas removal process can be
summarized as follows :(a) good clean up of all forms of sulfur to give
a stream high in sulfur concentration for processing in a Claus sulfur
plant, (b) effective C02 removal while producing a vent stream satisfactorily
low in sulfur and pollutants, (c) low utility and energy consumption,
(d) no waste streams that present a disposal problem.
The need for a process to remove sulfur at high temperature has
been discussed fully in preceding sections of this report. Systems based
on dolomite or iron appear promising; however, they may give less complete
sulfur removal than conventional scrubbing systems, in which case a methan-
ation catalyst that is tolerant of higher sulfur (e.g. 50 ppm) may have to
be developed. If the sand bed filtering technique could be incorporated
to remove particulates at the same time that sulfur is removed, such systems
would be even more attractive. A further need is to destroy or remove un-
desirable contaminants such as carbonyl sulfide, cyanides, and possibly
phenol and ammonia. This function might also be provided by a high temper-
ature gas cleanup system.
The need for a simple,effective method to clean up sour water
for reuse is another item that is common to most fossil fuel conversion
operations. Sour water generally contains sulfur compounds, ammonia, I^S,
phenol, thiocyanates, cyanides, traces of oil, etc. These are generally
present in too high a concentration to allow going directly to biological
oxidation, but their concentration is often too low to make recovery
attractive. Particulates, if present, further complicate the processing
of sour water. Usual techniques for clean up include sour water stripping
to remove HoS and ammonia, and in addition, extraction may be required
to remove phenols and similar compounds. Such operations are large
consumers of utilities and have a large effect on overall thermal efficiency.
In most cases the net amount of sour water produced is less than the amount
of steam consumed by reaction in gasification plus shift conversion, which
suggests a way to dispose of sour water. One approach is to use the
sour water as quench on the hot gas leaving the gasifier, as is done in
this BI-GAS design. However, it is not clear that compounds such as phenol
and ammonia will actually be destroyed by recycling, so they may have to
be separated and withdrawn as by-products.
An alternative approach is to vaporize the sour water to make
steam which can be used in the gasifier. In this case,compounds such as
phenol should be destroyed and reach equilibrium concentration in the
circulating sour water. It may not be practical to vaporize sour water
in conventional equipment such as exchangers, due to severe fouling and
corrosion problems. Therefore, new techniques may be required, and one
possibility would be to vaporize the sour water by injecting it into a
hot bed of fluidized solids. The system could be very similar to that
proposed for evaporating a water slurry of coal feed as discussed in
connection with Figure 3. In fact, sour water may be used in some cases
to form the slurry.
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- 53 -
On trace elements, information is needed on the amount vaporized
in the gasifier and what happens to them, where they separate out and in
what form, so that techniques can be worked out for recovering or disposing
of the materials. Again specific information is needed for each coal and
for each coal conversion process since operating conditions differ. In
many cases, the trace elements may tend to recycle within the system and
build up in concentration. This offers an interesting opportunity to
perhaps recover some of them as useful by-products. The toxic nature of
many of the volatile elements should be given careful consideration from
the standpoint of emissions to the environment, as well as protection of
personnel during operation and maintenance of the plant. Carcinogenicity
of coal tar and other compounds present in trace amounts or formed
during start up or upsets should also be evaluated.
Protection of personnel, especially during maintenance operations
should be given careful attention, which will require that additional
information be obtained. Thus, toxic elements that vaporize in the gasifier
may condense in equipment such as piping and exchangers where they could
create hazards during cleaning operations. This may apply particularly
to sand bed filters and to shift conversion reactors.
In this specific BI-GAS design, there is no sour process water
effluent from the plant which might contain trace elements. Moreover the
slag is drained and disposed of as a moist solid rather than a slurry.
On this basis the question of cleaning up waste water effluent does not
apply. However, in an actual application there will very likely be a water
effluent, and detailed study of the facilities for clean up will be
needed. In any event, the water make-up that is brought to the plant
will contain dissolved solids including sodium and calcium salts. Calcium
salts may be precipitated during the water treating operation to form a
sludge which can be disposed of with the other waste solids, but the
fate of the sodium salts in the make-up water calls for further study.
These will leave with the blowdown from the cooling tower. If the concentration
of dissolved solids is too high in this blowdown water to allow discharging
it to the river, then some suitable method of disposal will have to be
worked out. On one proposed commercial plant, this has been handled
by using an evaporation pond where the water is evaporated to dryness.
The salts accumulate and will ultimately have to be disposed of. If they
cannot be used or sold then it would seem logical to dispose of them in
the ocean.
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- 54 -
13. PROCESS DETAILS
Additional details on the process are given in Tables 10
through 16.
-------
- 55 -
Table 10
Steam Balance for BI-GAS Base Case
1265 psig steam Ib/hr
Generated
Shift Outlet WHB 545,700
TOTAL 545,700
Consumed
Gasifier
Shift
Q£ preheater
410,100
65,400
70.200
545,700
600 psig steam Ib/hr
Generated
Auxiliary boiler 1,329,400
TOTAL
1,329,400
Consumed
Power gener. 606,400
Acid gas remov. 430,700
to 400 psig steam 292.300
1,329,400
400 psig steam Ib/hr
Generated
From 600 psig 292,300
Shift & Meth. WHB 1,056,100
TOTAL
1,348,400
Consumed
Coal feeding
SNG compressor
Glycol dry.
02 plant
02 compressor
9,600
192,900
4,700
743,400
397.800
1,348,400
50 paig steam Ib/hr
Generated
Raw gas WHB
Glaus plant
Turbo generator
TOTAL
600,600
70,000
298.900
969,500
Consumed
Acid gas removal
BFW deaerator
Building heat
833,100
86,400
50.000
969,500
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- 56 -
Table 11
Water Requirements for BI-GAS Base Case
Cooling Water Circulation GPM
Coal preparation 0
Gasification 450
Quench & dust removal Q
Shift conversion 0
Acid Gas removal 114,000
Methanation & drying 1,930
Oxygen plant 117,600
Sulfur plant 1,100
Power generation 27,500
262,580
Cooling Tower Makeup GPM
Drift Loss 526
Evaporation 5,252
Slowdown (net) 1,200
6,978
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- 57 -
Table 12
Electric Power Consumption
KW
Coal preparation 24,000
Gasification 3,500
Quench & dust removal 0*
Shift conversion 0*
Acid gas removal 0*
Methanation & drying 2,250
Oxygen plant 0*
Sulfur plant 270
Condensate pumps 4,700
Cooling Water pumps 7,140
41,860
* A small amount of power will be used for
instruments, lights, etc.
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- 58 -
Table 13
Make Up Chemicals and Catalyst Requirements
Chemicals
Acid Gas Removal:
- scrubbing solution
- additives
Sulfur Plant tail gas cleanup
Glycol for drying prod, gas
Cooling Tower Additives
Anticorrosion, e.g. chromate
Antifouling, e.g. chlorine
Water Treating
Lime
Alum
Caustic
Sulfuric acid
Catalysts, etc.
Sand for sand bed filters
Shift catalyst
ZnO guard bed to remove sulfur
Methanation catalyst
Molecular sieve to clean up CO,, vent
Ion exchange resin for water treating
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- 59 -
Table 14
Potential Odor Emissions
Coal storage and handling.
Coal preparation, washing, settling pond-
Coal drying - vent gas.
Vent gas from lock hoppers.
Wet ash handling and disposal.
Sour water stripping and handling.
CC-2 vent stream from acid gas removal.
Sulfur plant and tail gas.
Biox pond and other ponds.
Leaks: ammonia, H2S, phenols, etc.
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- 60 -
Table 15
Potential Noise Problems
Coal handling and conveyors.
Coal crushing, drying and grinding.
Oxygen plant air and oxygen compressors.
Lock hoppers, especially on depressuring from 1100 psig.
Burners on furnaces.
Stacks emitting flue gases.
Turbos-generator etc., in utilities area.
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- 61 -
Table 16
Miscellaneous Inputs
For water treating: lime, caustic, alum, sulfuric acid,
chlorine
Cooling water additives: anti algae (chlorine)
anti corrosion (chromium salt)
Other chemicals: carbonate and additives for acid gas removal
glycol for drying product gas
Catalysts, etc.: sand for sand bed filters
methanation catalyst
Claus plant catalyst
ZnO guard bed to remove sulfur
Sieve for sulfur clean up on C02 vent gas
Oil: to lubricate pumps, compressor, etc.
Bios nutrients, if required.
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- 62 -
14. QUALIFICATIONS
As pointed out, this study does not consider cost or economics.
Also, areas such as coal mining and general offsites are excluded, as well
as miscellaneous small utility consumers such as instruments, lighting
etc. These will be similar and common to all coal conversion operations.
The study is based on the specific process design and coal type
cited, 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 BI-GAS study uses high sulfur
western Kentucky coal to supply gasification as well as utility furnaces.
Therefore, flue gas clean up has been added. Because of variations in
coal feed, moisture content, and other basic items, great caution is
needed in making comparisons between coal gasification processes as they
are not on a completely comparable basis.
Other gasification processes may make large amounts of various
by-products such as tar, naphtha, phenols, and ammonia. The disposition
and value of these must be taken into account relative, to the increased
coal consumption that results and the corresponding improvement in overall
thermal efficiency. Such variability further increases the difficulty of
making meaningful comparisons between processes.
The BI=GAS process makes no appreciable amounts of tar, naphtha,
or phenols; however, there could be a sizeable yield of ammonia, amounting
to over 100 tpd and it is assumed that this can be recovered and sold.
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- 63 -
15. BIBLIOGRAPHY
1. Magee, E.M., Jahnig, C.E. and Shaw, H., "Evaluation of Pollution
Control in Fossil Fuel Conversion Processes, Gasification; Section 1:
Koppers-Totzek Process", Report No- EPA-650/2-74-009a, January 1974.
2. Kalfadelis, C.D., and Magee, E.M., "Evaluation of Pollution Control
in Fossil Fuel Conversion Processes, Gasification; Section 2;
Synthane Process", Report No. EPA-650/2-74=009b, June 1974.
3. Shaw, H., and Magee, E.M., "Evaluation of Pollution Control in
Fossil Fuel Conversion Processes, Gasification; Section 3s
Lurgi Process", Report No. EPA-650/2-74-009c, July 1974.
4. Jahnig, C.E., and Magee, E.M., "Evaluation of Pollution Control
in Fossil Fuel Conversion Processes, Gasification; Section 4:
C02 Acceptor Process", Report No. EPA-650/2=74-009d, December 1974.
5. Kalfadelis, C. D. Evaluation of Pollution Control in Fossil Fuel
Conversion Processes, Liquefaction: Section 1: COED Process.
EPA-650/2-74-009e, January 1975.
6 Jahnig, C.E., "Evaluation of Pollution Control in Fossil Fuel
Conversion Processes, Liquefaction; Section 2, Solvent Refined Coal
Process", Report No* EPA 650/2-74~009f, March 1975.
7. Grace, Rober J., "Development of the BI-GAS Process1,1 IGT Symposium,
September 1973.
8. Grace, R.J., and Zehradnik, R.L., "BI-GAS Program Enters Pilot
Plant Stage", Fourth Synthetic Pipeline Gas Symposium, Chicago,
October 30-31, 1972,,
9 Engineering Study end Technical Evaluation of the Bituminous Coal
" Research, Inc. Two Stage Super Pressure Gasification Process.
Research and Development Report No. 60 for Office of Coal Research
by Air Products and Chemicals, Inc., 1970=,
10. "Control Techniques for SO* Air Pollution", Rept, AP-52, U.S.
Dept. Health, January 1969.
11. Coalgate, J.L., Akers, D.J. and From, R.W. "Gob Pile Stabilisation,
Reclamation, and Utilization", OCR R&D Report 75, 1973.
12 EPA Symposium "Environmental Aspects of Fuel Conversion Technology"
Colony Oil Shale Development M.To Atwood. St. Louis, Missouri
May 13=16, 1974, EPA-650/2-74-118.
13. National Public Hearings on Po^jesr Plant Compliance with Sulfur.
Oxide Air Pollution Regulations, EPA Report January 1974.
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- 64 -
14. Parrish, R. W. and Neilson, H.B., "Synthesis Gas Purification
Including Removal of Trace Contaminants by the BENFIELD Process",
presented at 167th National Meeting of ACS, Div. of I&EC,
Los Angeles, March 31-April 5, 1974.
15. Hydrocarbon Processing April 1973, pp0 109-116
16. Atmospheric Emissions from Petroleum Refineries, U.S. Dept. of Health,
Education and Welfare, Publ0 No, 783, 1960.
17. Characterisation of Glaus Plant Emissions,
EPA Report EPA-R2-73-188, April 1973.
18. Cooling Tower Operations
Furlong, E., Environmental Science & Technology
Volume 8, No. 8, August 1974, page 712
19. Pearson, M.J., "Hydrocarbon Processing," 52, (2), p. 81.
20. Lee, R.E., et a., "Trace Metal Pollution in the Environment", Journ.
e£ Air Poll. Control, 23, (10), October 1973.
21. Schultz, H.9 Hattman, E. A., and Booker, W. B., ACS Div. of Fuel.
Chem., Vol. 8, No. 4, p. 108, August 1973
22. Billings, C. E., Sacco, A. M., Matson, W. R., Griffin, R. M., Coniglio,
W. R., and Harley, R. A., "Mercury Balance on a Large Pulverized Coal-
Fired Furnace", J. Air Poll. Control Association, Vol. 23, No. 9,
September 1973, p. 773
23. Schultz, Hyman et al., "The Fate of Some Trace Elements During Coal
Pre-treatment and Combustion", ACS Div. Fuel Chem. 8, (4), p. 108
August 1973
24. Bolton, N.E., et al, "Trace Element Mass Balance Around a Coal-Fired
Stream Plant", ACS Div. Fuel Chem., 18, (4), p. 114, August 1973.
25. Magee, E. M., Hall, H. J., and Varga, G. M., Jr., "Potential Pollutants
in Fossil Fuels", EPA-R2-73-249, June, 1973.
26. Trace Elements and Potential Toxic Effects in Fossil Fuels
H = J. Hall, EPA Symposium "Environmental Aspects of Fuel Conversion
Technology" St. Louis, MO., May 1974.
27. Attari, A. "The Fate of Trace Constituents of Coal During Gasification",
EPA Report'650/2-73-004, August 1973.
28.' Control of Mine Drainage from Coal Mine Mineral Waste, EPA Report
14010 DDN 08/71 (NTIS No. PB-2Q8 326)
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- 65 -
29° Kim, A.G., "An Experimental Study of Ferrous Iron Oxidation in Acid
Mine Water", Proc. Second Symp. on Coal Mine Drainage Research, Mellon
Institute, Pittsburgh, Pennsylvania, May, 1968.
30= Removal of Hydrogen Sulfide from Hot Producer Gas by Solid Absorbents
Bureau of Mines - RI7947 (1974)
31. Production of High Btu Gas from Light Petroleum Dist.
R=J. Cockerham & George Percival, Ind. Bag. Chem; Proc. Design &
Development, Volume 5, No. 3 (July, 1966), pp. 253-257
32. CRG Route to SNG, F.E. Hart et al.,Hydrocarbon Processing, April 1972
P. 89,
33. Substitute Natural Gas from Liquid Hydrocarbons, A° Roeger.
Proceed.52nd Annual Convention, Natural Gas Processors Assoc.
Vol. 52, 1973 pp. 152-165.
34. Status of Flue Gas Desulfurization Technology F. T. Princiottap
EPA Symposium on Environmental Aspects of Fuel Conversion Technology.
St. Louis, Missouri, May 13-16, 1964, EPA 650/2-74-118.
35. Chemical Engineering: Environmental Engineering, October 21, 1974
pp. 79-85.
36. Grace, R.Jo, and Diehl, E°K», "Environmental Aspects of the BI-GAS
Process", EPA Symposium on Environmental Aspects of Fuel Conversion
Technology, St. Louis, Missouri, May 1974, EPA 650/2=74=118
37. Environmental Aspects of El Paso's Burnhanel Coal Gasification
Complex. C. R. Gibson, et al. EPA symposium on Environmental
Aspects of Coal. Conversion Technology, St. Louis, Missouri.
May 1974, EPA 650/2-74-118.
38. Bertrand, R. R. et al., "Trip Report - Four Commercial
Gasification Plants Nov. 6-18, 1974" EPA Report, May 1975.
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TECHNICAL REPORT DATA
(Please read Inunctions on the reverse before completing)
1. REPORT NO.
EPA-650/2-74-009-g
2.
3. RECIPIENT'S ACCESSION*NO.
4. T.TLE AND SUBTITLE Evaluation of Pollution Control in
Fossil Fuel Conversion Processes; Gasification:
Section 5. BI-GAS Process
5. REPORT DATE
May 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
C.E. Jahnig
8. PERFORMING ORGANIZATION REPORT NO
GRU.9DJ.75
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Exxon Research and Engineering Company
P. O. Box 8
Linden, NJ 07036
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADD-023
11. CONTRACT/GRANT NO.
68-02-0629
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final: 6/72-8/75
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The report gives results of a review of the Bituminous Coal Research, Inc.
BI-GAS Process, from the standpoint of its effect on the environment. The
quantities of solid, liquid, and gaseous effluents were estimated, where
possible, as well as the thermal efficiency of the process. For the purpose of
reducing environmental impact, a number of possible process modifications
or alternatives were proposed, and new technology needs pointed out.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Coal Gasification
Fossil Fuels
Thermal Efficiency
Trace Elements
Air Pollution Control
Stationary Sources
Clean Fuels
BI-GAS Process
Fuel Gas
Research Needs
13B
13H
21D
20M
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport/
Unclassified
21. NO. OF PAGES
72
20. SECURITY CLASS (Thispage)
Unlimited
22. PRICE
EPA Form 2220-1 (S-73)
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